SEMPRA — Annual Report 2025

Feb 26, 2026

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-K

(Mark One) — ☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended	December 31 , 2025
	or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from	to

Commission File No.	Exact Name of Registrants as Specified in their Charters, Address and Telephone Number		State of Incorporation	I.R.S. Employer Identification Nos.
1-14201	SEMPRA	●	California	33-0732627
	488 8th Avenue
	San Diego , California 92101
	(619) 696-2000
1-03779	SAN DIEGO GAS & ELECTRIC COMPANY	●	California	95-1184800
	8330 Century Park Court
	San Diego , California 92123
	(619) 696-2000
1-01402	SOUTHERN CALIFORNIA GAS COMPANY	●	California	95-1240705
	555 West 5th Street
	Los Angeles , California 90013
	(213) 244-1200

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: — Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
SEMPRA:
Common Stock, without par value	SRE	New York Stock Exchange
5.75% Junior Subordinated Notes Due 2079, $25 par value	SREA	New York Stock Exchange
SAN DIEGO GAS & ELECTRIC COMPANY:
None
SOUTHERN CALIFORNIA GAS COMPANY:
None

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Title of Each Class
SEMPRA:
None
SAN DIEGO GAS & ELECTRIC COMPANY:
None
SOUTHERN CALIFORNIA GAS COMPANY:
6% Preferred Stock, $25 par value
6% Preferred Stock, Series A, $25 par value

Indicate by check mark if the Registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act. — Yes	☒	No	☐
Indicate by check mark if the Registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes	☐	No	☒
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	☐ S maller 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 have filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the Registrants included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the Registrants’ respective executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the Registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes	☐	No	☒

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant computed by reference to the price at which the common equity was last sold as of June 30, 2025, the last business day of each Registrant’s most recently completed second fiscal quarter:
Sempra	$ 49.4 billion
San Diego Gas & Electric Company	$ 0
Southern California Gas Company	$ 0

Common stock, without par value, outstanding as of February 19, 2026:

Sempra	653,284,140 shares
San Diego Gas & Electric Company	Wholly owned by Enova Corporation, which is wholly owned by Sempra
Southern California Gas Company	Wholly owned by Pacific Enterprises, which is wholly owned by Sempra
SAN DIEGO GAS & ELECTRIC COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTIONS I(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY GENERAL INSTRUCTION I(2).

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Sempra proxy statement to be filed for its May 2026 annual meeting of shareholders are incorporated by reference into Part III of this annual report on Form 10-K.
Portions of the Southern California Gas Company information statement to be filed for its June 2026 annual meeting of shareholders are incorporated by reference into Part III of this annual report on Form 10-K.

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SEMPRA FORM 10-K
SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-K
SOUTHERN CALIFORNIA GAS COMPANY FORM 10-K
TABLE OF CONTENTS
		Page
Glossary		5
Information Regarding Forward-Looking Statements		9
Summary of Risk Factors		11
PART I
Item 1.	Business	12
Item 1A.	Risk Factors	40
Item 1B.	Unresolved Staff Comments	68
Item 1C.	Cybersecurity	68
Item 2.	Properties	70
Item 3.	Legal Proceedings	70
Item 4.	Mine Safety Disclosures	70
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	71
Item 6.	(Reserved)	71
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	72
	Overview	72
	Results of Operations by Registrant	73
	Capital Resources and Liquidity	88
	Critical Accounting Estimates	108
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	112
Item 8.	Financial Statements and Supplementary Data	114
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	115
Item 9A.	Controls and Procedures	115
Item 9B.	Other Information	119
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	119
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	120
Item 11.	Executive Compensation	120
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	121
Item 13.	Certain Relationships and Related Transactions, and Director Independence	121
Item 14.	Principal Accountant Fees and Services	122
PART IV
Item 15.	Exhibits and Financial Statement Schedules	123
Item 16.	Form 10-K Summary	134
Signatures		135
Index to Consolidated Financial Statements		F-1
Index to Condensed Financial Information of Parent		S-1

This combined Form 10-K 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 Registrant on its own behalf. Each such Registrant makes statements herein only as to itself and makes no statement whatsoever as to any other Registrant.

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 II – Item 8 is provided for each Registrant, except for the Notes to Consolidated Financial Statements, which are combined for all the Registrants. All Items other than Part II – Item 8 are combined for the three Registrants.

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The following terms and abbreviations appearing in this report have the meanings indicated below.

GLOSSARY
2019 Wildfire Legislation	AB 1054 and AB 111
2025 Wildfire Legislation	Senate Bill 254
2025 Energy Laws	Mexico’s 2025 energy-related laws, including Mexico’s Electric Sector Law and Hydrocarbons Sector Law
AB	California Assembly Bill
ADIA	Black Silverback ZC 2022 LP (assignee of Black River B 2017 Inc.), a wholly owned affiliate of Abu Dhabi Investment Authority
AFUDC	allowance for funds used during construction
amparo	an extraordinary constitutional appeal governed by Articles 103 and 107 of the Mexican Constitution and filed in Mexican federal court
AOCI	accumulated other comprehensive income (loss)
ARO	asset retirement obligation
ASC	Accounting Standards Codification
ASEA	Agencia de Seguridad, Energía y Ambiente (Mexico’s National Agency for Safety, Energy, and Environment)
ASU	Accounting Standards Update
ATM	at-the-market equity offering program pursuant to the Sales Agreement
Bcf	billion cubic feet
Bechtel	Bechtel Energy Inc.
Blackstone	BX Frontier Member I LLC and BX Frontier Member II LLC, collectively
bps	basis points
California ISO adder	an additional 0.50% ROE for participation in the California ISO
Cameron LNG JV	Cameron LNG Holdings, LLC
Cameron LNG Phase 1 facility	Cameron LNG JV liquefaction facility
Cameron LNG Phase 2 project	Cameron LNG JV liquefaction expansion project
CARB	California Air Resources Board
CCA	Community Choice Aggregator
CCM	cost of capital adjustment mechanism
CEC	California Energy Commission
CFE	Comisión Federal de Electricidad (Mexico’s Federal Electricity Commission)
CFIN	Cameron LNG FINCO, LLC, a wholly owned and unconsolidated affiliate of Cameron LNG JV
CNE	Comisión Nacional de Energía (Mexico’s National Commission of Energy)
CODM	chief operating decision maker as defined in ASC 280
ConocoPhillips	ConocoPhillips Company
Continuation Account	the Wildfire Fund Continuation Account established by the 2025 Wildfire Legislation
COVID-19	coronavirus disease 2019
CPUC	California Public Utilities Commission
CRNCI	contingently redeemable noncontrolling interest
CRR	congestion revenue right
DA	Direct Access
DER	distributed energy resources
DOE	U.S. Department of Energy
DOT	U.S. Department of Transportation
DWR	California Department of Water Resources
ECA LNG	ECA LNG Phase 1 and ECA LNG Phase 2, collectively
ECA LNG Phase 1	ECA LNG Holdings B.V., a subsidiary of SI Partners that owns the ECA LNG Phase 1 project
ECA LNG Phase 2	ECA LNG II Holdings B.V., a subsidiary of SI Partners that owns the ECA LNG Phase 2 project
ECA Regas Facility	Energía Costa Azul, S. de R.L. de C.V. LNG regasification facility
Ecogas	Ecogas México, S. de R.L. de C.V.
Edison	Southern California Edison Company, a subsidiary of Edison International
EFH	Energy Future Holdings Corp. (renamed Sempra Texas Holdings Corp.)
EPA	U.S. Environmental Protection Agency
EPC	engineering, procurement and construction
EPS	earnings (losses) per common share

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GLOSSARY
ERCOT	Electric Reliability Council of Texas, Inc., the ISO and the regional coordinator of various electricity systems within Texas
ESJ	Energía Sierra Juárez, S. de R.L. de C.V.
ETR	effective income tax rate
Exchange Act	Securities Exchange Act of 1934, as amended
FD	final decision
feed gas	natural gas that is provided to be used for processing to produce LNG
FERC	Federal Energy Regulatory Commission
FID	final investment decision
Fitch	Fitch Ratings, Inc.
FTA	Free Trade Agreement
GCIM	Gas Cost Incentive Mechanism
GHG	greenhouse gas
GRC	General Rate Case
HOA	Heads of Agreement
IEnova	Infraestructura Energética Nova, S.A.P.I. de C.V.
IEnova Pipelines	IEnova Pipelines, S. de R.L. de C.V.
IMG	Infraestructura Marina del Golfo
IOU	investor-owned utility
IRA	Inflation Reduction Act of 2022
IRS	U.S. Internal Revenue Service
ISFSI	independent spent fuel storage installation
ISO	Independent System Operator
ITC	investment tax credit
JV	joint venture
KKR Denali	KKR Denali Holdco LLC, an affiliate of Kohlberg Kravis Roberts & Co. L.P.
KKR Partners	affiliates of Kohlberg Kravis Roberts & Co. L.P. and indirect co-investor Canada Pension Plan Investment Board, collectively
KKR Pinnacle	KKR Pinnacle Investor L.P., an affiliate of Kohlberg Kravis Roberts & Co. L.P.
kV	kilovolt
kW	kilowatt
kWh	kilowatt hour
LA Fires	the wildfires in Los Angeles County, California, including the Palisades, Eaton and other fires, that burned in January and February of 2025
LH	Mexico’s Hydrocarbons Law
LIE	Mexico’s Electricity Industry Law
LNG	liquefied natural gas
LPG	liquid petroleum gas
LTIP	long-term incentive plan
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MMBtu	million British thermal units (of natural gas)
MMcf	million cubic feet
Moody’s	Moody’s Investors Service, Inc.
MOU	Memorandum of Understanding
Mtpa	million tonnes per annum
MW	megawatt
MWh	megawatt hour
NAV	net asset value
NCI	noncontrolling interest(s)
NDT	nuclear decommissioning trusts
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering
NOL	net operating loss
NRC	Nuclear Regulatory Commission

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GLOSSARY
NYSE	New York Stock Exchange
O&M	operation and maintenance expense
OBBBA	One Big Beautiful Bill Act of 2025
OCI	other comprehensive income (loss)
OEIS	Office of Energy Infrastructure Safety
Oncor	Oncor Electric Delivery Company LLC
Oncor Holdings	Oncor Electric Delivery Holdings Company LLC
OSHA	Occupational Safety and Health Administration
Other Sempra	All Sempra consolidated entities, except for SDG&E and SoCalGas
PA2 JVCo	a subsidiary of SI Partners that owns Port Arthur LNG II
PA2 JVCo LLCA	PA2 JVCo’s limited liability company agreement
PA LNG Phase 1 project	initial phase of the Port Arthur LNG liquefaction project
PA LNG Phase 2 project	second phase of the Port Arthur LNG liquefaction project
PBOP	postretirement benefits other than pension
PD	proposed decision
PEMEX	Petróleos Mexicanos (Mexican state-owned oil company)
PG&E	Pacific Gas & Electric Company
PHMSA	Pipeline and Hazardous Materials Safety Administration
Port Arthur LNG I	Port Arthur LNG, LLC, a subsidiary of SI Partners that owns the PA LNG Phase 1 project
Port Arthur LNG II	Port Arthur LNG Phase II, LLC, a subsidiary of SI Partners that owns the PA LNG Phase 2 project
PP&E	property, plant and equipment
PPA	power purchase agreement
PRP	Potentially Responsible Party
PSEP	Pipeline Safety Enhancement Plan
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act
Rating Agencies	Moody’s, S&P and Fitch, collectively
REC	renewable energy certificate
Registrants	has 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
ROE	return on equity
ROU	right-of-use
RPS Program	Renewables Portfolio Standard program
RSU	restricted stock unit
S&P	S&P Global Ratings, a division of S&P Global Inc.
Sales Agreement	ATM 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)
SB	California Senate Bill
scope 1 GHG emissions	a company’s direct GHG emissions from operations that it owns or controls
scope 2 GHG emissions	a company's indirect GHG emissions such as purchased electricity for its own use at its facilities
SDG&E	San Diego Gas & Electric Company
SDSRA	Senior Debt Service Reserve Account
SEC	U.S. Securities and Exchange Commission
SEDATU	Secretaría de Desarrollo Agrario, Territorial y Urbano (Mexico’s agency in charge of agriculture, land and urban development)
SENER	Secretaría de Energía de México (Mexico’s Ministry of Energy)
series C preferred stock	Sempra’s 4.875% fixed-rate reset cumulative redeemable perpetual preferred stock, series C
Sharyland Holdings	Sharyland Holdings, L.P.
Sharyland Utilities	Sharyland Utilities, L.L.C.
Shell	Shell México Gas Natural, S. de R.L. de C.V.

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GLOSSARY
SI Partners	Sempra Infrastructure Partners, LP, the holding company for most of Sempra’s businesses not subject to California or Texas utility regulation
SoCalGas	Southern California Gas Company
SOFR	Secured Overnight Financing Rate
SONGS	San Onofre Nuclear Generating Station
SPA	sale and purchase agreement
SST Committee	Safety, Sustainability and Technology Committee of the Sempra board of directors
Support Agreement	support agreement, dated July 28, 2020 and amended in June 2021 and January 2025, between Sempra and Sumitomo Mitsui Banking Corporation
TAG Norte	TAG Norte Holding, S. de R.L. de C.V.
TAG Pipelines	TAG Pipelines Norte, S. de R.L. de C.V.
Tangguh PSC	Tangguh PSC Contractors
TCEQ	Texas Commission on Environmental Quality
TCJA	Tax Cuts and Jobs Act of 2017
TdM	Termoeléctrica de Mexicali
TO5	Electric Transmission Owner Formula Rate, effective June 1, 2019 through May 31, 2025
TO5 adder refund provision	the 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
TO6	Electric Transmission Owner Formula Rate, effective June 1, 2025, subject to refund
TTI	Texas Transmission Investment LLC, an entity indirectly owned by OMERS Administration Corporation (acting through its infrastructure investment entity, OMERS Infrastructure Management Inc.) and GIC Private Limited
U.S. GAAP	generally accepted accounting principles in the United States of America
UTM	unified tracker mechanism
VaR	value at risk
Ventika	Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V., collectively
VIE	variable interest entity
Wildfire Fund	the fund established pursuant to AB 1054
WMP	wildfire mitigation plan

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 Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively:

▪ the Consolidated Financial Statements and related Notes of Sempra;

▪ the Financial Statements and related Notes of SDG&E; and

▪ the Financial Statements and related Notes of SoCalGas.

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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, disallowances or 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) CNE, CPUC, 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 a positive 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 nation-state actors, of ransomware or other attacks on our systems, the energy grid or our other infrastructure, or the systems of third parties with which we conduct business

▪ 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 of efforts to increase affordability of U.S. utility customer rates on our ability to obtain cost recovery from applicable regulators, our capital expenditure and other growth plans and our ability to advance statewide policies

▪ the impact on affordability of customer rates, cost of capital and operating margin due to (i) volatility in inflation, interest rates, commodity prices, tariff rates, and foreign currency exchange rates and (ii) with respect to SDG&E’s and SoCalGas’ businesses, the cost of meeting the demand for lower carbon and reliable energy in California

▪ 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 and in other reports we file with the SEC.

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SUMMARY OF RISK FACTORS

There are a number of risks you should understand before making an investment decision in our securities or the securities of our businesses. This summary is not intended to be complete and should only be read together with the information set forth in “Part I – Item 1A. Risk Factors” in this report. If any of these risks occur, Sempra’s and its businesses’ results of operations, financial condition, cash flows and/or prospects could be materially adversely affected, and the trading price of Sempra’s securities and those of its businesses could decline. These risks include the following:

Risks Related to Sempra

▪ Sempra’s ability to pay dividends and meet its obligations largely depends on the performance of its subsidiaries and entities accounted for as equity method investments

▪ Successfully executing our five-year capital expenditures plan is subject to risks

▪ The economic interest, voting rights and market value of our outstanding common stock may be adversely affected by any additional equity securities we may issue

Risks Related to All Sempra Businesses

▪ Our infrastructure and its supporting systems subject us to risks

▪ We face risks related to severe weather, natural disasters, physical attacks and other similar events

▪ We face evolving cybersecurity, technology resiliency and data security and governance risks, including with respect to increasing use of artificial intelligence

▪ Our debt service obligations expose us to risks

▪ The availability and cost of financing could be negatively affected by market and economic conditions and other factors

▪ Credit rating agencies may downgrade our credit ratings or place them on negative outlook, and our efforts to maintain these ratings could require additional equity securities issuances by Sempra or sales of equity interests in subsidiaries or projects in development

▪ We face risks related to the evolving regulatory environment, including failures or delays in obtaining and maintaining franchises and other required approvals and potential negative impacts of our legislative and regulatory advocacy efforts

▪ We face risks related to environmental and climate change regulation and the costs of the energy transition

▪ We are subject to complex tax and accounting requirements that expose us to risks

Risks Related to Sempra California

▪ Wildfires in California pose risks to Sempra, SDG&E and SoCalGas

▪ The electricity industry is undergoing significant change

▪ Natural gas continues to be the subject of political and public debate, including a desire by some to reduce or eliminate reliance on natural gas as an energy source

▪ SDG&E and SoCalGas are subject to extensive regulation

Risks Related to Sempra Texas Utilities

▪ Ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management, policies and operations of Oncor

▪ Changes in the regulation of Oncor or the regulation or operation of the electric utility industry and/or ERCOT market could negatively affect Oncor

▪ Oncor’s capital expenditures plan may not be executed as planned or achieve its business objectives

▪ Oncor’s capital expenditures plan will result in significant liquidity needs that may necessitate additional investments

Risks Related to Sempra Infrastructure

▪ Project development activities may not be successful, projects under construction may not be completed on schedule or within budget, and completed projects may not operate at expected levels or generate expected earnings or cash flows

▪ We may not be able to secure, maintain, extend or replace long-term supply, sales or capacity agreements

▪ Our international businesses and operations expose us to increased legal, regulatory, tax, economic, geopolitical, credit and management oversight risks and challenges

Risks Related to Planned Sales of Certain Assets and Businesses

▪ 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

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PART I.

ITEM 1. BUSINESS

OVERVIEW

We are a holding company whose principal businesses are regulated utilities in California and Texas. Our businesses invest in and operate electric and gas utilities and other energy infrastructure that provide energy services to customers.

Sempra was formed in 1998 through a business combination of Enova Corporation and Pacific Enterprises, the holding companies of our regulated public utilities in California: SDG&E, which began operations in 1881, and SoCalGas, which began operations in 1867. We have since expanded our regulated public utility presence into Texas through our 80.25% interest in Oncor and 50% interest in Sharyland Utilities. Sempra Infrastructure’s assets include investments in the U.S. and Mexico with a focus on LNG, energy networks and low carbon solutions.

Business Strategy

Sempra’s mission is to build America’s leading utility growth business. We are primarily focused on the largest economies in the U.S., California and Texas, where we are investing in regulated utilities with a view toward producing stable cash flows and improved earnings visibility. Our goal is to deliver safe, reliable and affordable energy to customers while increasing shareholder value.

DESCRIPTION OF BUSINESS BY SEGMENT

Sempra’s business activities are organized under the following reportable segments:

▪ Sempra California

▪ Sempra Texas Utilities

▪ Sempra Infrastructure

SDG&E and SoCalGas each have one reportable segment.

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Sempra California

SDG&E

SDG&E is a regulated public utility that provides electric services to a population of, at December 31, 2025, approximately 3.6 million and natural gas services to approximately 3.3 million of that population, covering an approximate 4,100 square mile service territory in Southern California that encompasses San Diego County and an adjacent portion of Orange County.

SDG&E’s assets at December 31, 2025 covered the following territory:

We describe SDG&E’s electric utility operations below. We describe SDG&E’s natural gas utility operations below in “Sempra California’s Natural Gas Utility Operations.” For a discussion of the risks and uncertainties facing SDG&E’s business, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California.”

Electric Transmission and Distribution System. Service to SDG&E’s customers is supported by its electric transmission and distribution system, which includes substations and overhead and underground lines. These electric facilities are primarily in the San Diego, Imperial and Orange counties of California and in Arizona and Nevada and consisted of 2,018 miles of transmission lines, 24,210 miles of distribution lines and 158 substations at December 31, 2025. Occasionally, various areas of the service territory require expansion to accommodate customer growth and maintain reliability and safety.

SDG&E’s 500-kV Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego, California. SDG&E’s share of the line is 1,163 MW, although it can be less under certain system conditions. SDG&E’s Sunrise Powerlink is a 500-kV transmission line constructed by SDG&E that extends across Southern California. Both of these lines are operated by the California ISO and together provide SDG&E with import capability of 3,900 MW of power.

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Mexico’s Baja California transmission system is connected to SDG&E’s system via two 230-kV interconnections with combined capacity of up to 600 MW in the north-to-south direction and 800 MW in the south-to-north direction. However, it can be less under certain system conditions.

SDG&E’s system is connected to Edison’s transmission system via five 230-kV transmission lines.

Electric Resources. SDG&E supplies power from its own electric generation facilities and procures power on a long-term basis from other suppliers for resale through CPUC-approved PPAs or purchases on the spot market. SDG&E does not earn any return on commodity sales volumes. SDG&E’s electric resources at December 31, 2025 were as follows:

ELECTRIC RESOURCES (1)	Contract expiration date	Net operating capacity (MW)	% of total
SDG&E:
Owned generation facilities, natural gas (2)		1,217	26 %
PPAs:
Renewable energy:
Wind	2026 to 2042	962	20
Solar	2030 to 2043	1,546	32
Other	2027 and thereafter	30	1
Tolling and other	2026 to 2042	1,023	21
Total		4,778	100 %

(1) Excludes approximately 482 MW of energy storage owned and approximately 632 MW of energy storage contracted.

(2) SDG&E owns and operates four natural gas-fired power plants, three of which are in California and one is in Nevada.

Charges under contracts with suppliers are based on the amount of energy received or are tolls based on available capacity. Tolling contracts are PPAs under which SDG&E provides natural gas to the energy supplier.

SDG&E procures natural gas under short-term contracts for its owned generation facilities and for certain tolling contracts associated with PPAs. Purchases from various southwestern U.S. suppliers are primarily priced based on published monthly bid-week indices, which can be subject to volatility.

SDG&E participates in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement that allows access to power trading with more than 300 member utilities, power agencies, energy brokers and power marketers throughout the U.S. and Canada. Participants can make power transactions on standardized terms, including market-based rates, preapproved by the FERC. Participation in the Western Systems Power Pool is intended to assist members in managing power delivery and price risk.

Customers and Demand. SDG&E provides electric services through the generation, transmission and distribution of electricity to the following customer classes:

ELECTRIC CUSTOMER METERS AND VOLUMES	Customer meter count	Volumes (1) (millions of kWh)
	December 31,	Years ended December 31,
	2025	2025	2024	2023
SDG&E:
Residential	284,726	1,252	1,348	2,004
Commercial	31,605	1,281	1,363	1,868
Industrial	324	296	441	670
Street and highway lighting	1,545	56	55	77
	318,200	2,885	3,207	4,619
CCA and DA	1,229,624	13,903	13,484	12,228
Total	1,547,824	16,788	16,691	16,847

(1) Includes intercompany sales.

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SDG&E currently provides procurement service for a portion of its customer load. Most customers receive electric commodity service from a load-serving entity other than SDG&E through programs such as CCA and DA. In such cases, SDG&E no longer procures energy for this departed load. Accordingly, SDG&E’s CCA and DA customers receive primarily transportation and distribution services from SDG&E.

CCA is only available if a customer’s local jurisdiction (city or county) offers such a program, and DA is currently limited by a cap based on gigawatt hours. Several jurisdictions in SDG&E’s territory have implemented CCA, including the City of San Diego in 2022.

Due to this departed load, SDG&E’s historical energy procurement commitments for future deliveries exceed the needs of its remaining bundled customers. To help achieve the goal of ratepayer indifference (as to whether customers’ energy is procured by SDG&E or by CCA or DA), the CPUC revised the Power Charge Indifference Adjustment framework. The framework is intended to more equitably allocate SDG&E’s historical energy procurement cost obligations among customers served by SDG&E and customers now served by CCA and DA.

San Diego’s mild climate contributes to lower consumption by our customers. Rooftop solar installations continue to reduce residential and commercial volumes sold by SDG&E. At December 31, 2025, 2024 and 2023, the residential and commercial rooftop solar capacity in SDG&E’s territory totaled 2,452 MW, 2,318 MW and 2,154 MW, respectively.

Electricity demand is dependent on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preferences, environmental regulations, legislation, renewable power generation, demand-side management impact and DER, among other factors. California’s energy policy supports increased electrification, which could increase electric volumes sold in the coming years. Other external factors, such as the price of purchased power, the use and further development of renewable energy sources and energy storage, the development of or requirements for new natural gas supply sources, demand for and supply of natural gas and general economic conditions, can also result in significant shifts in the market price of electricity, which may in turn impact demand. Electricity demand is also impacted by seasonal weather patterns (or “seasonality”), tending to increase in the summer months to meet the cooling load and in the winter months to meet the heating load.

Competition. SDG&E faces competition to serve its customer load from distributed and local power generation growth, including DER. In addition, the electric industry is undergoing rapid technological change, and third party energy storage alternatives and other technologies may increasingly compete with SDG&E’s traditional transmission and distribution infrastructure in delivering electricity to consumers. Certain FERC transmission development projects are open to competition, allowing independent developers to compete with incumbent utilities for the construction and operation of transmission facilities.

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SoCalGas

SoCalGas is a regulated public utility that owns and operates a natural gas distribution, transmission and storage system that delivers natural gas to a population of, at December 31, 2025, approximately 21.3 million, covering an approximate 24,000 square mile service territory that encompasses Southern California and portions of central California (excluding San Diego County, the City of Long Beach and the desert area of San Bernardino County).

SoCalGas’ assets at December 31, 2025 covered the following territory:

We describe SoCalGas’ natural gas utility operations below in “Sempra California’s Natural Gas Utility Operations.” For a discussion of the risks and uncertainties facing SoCalGas’ business, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California.”

Sempra California’s Natural Gas Utility Operations

Natural Gas Procurement and Transportation. At December 31, 2025, SoCalGas’ natural gas facilities included 52,765 miles of distribution pipelines, 3,030 miles of transmission and storage pipelines, 48,900 miles of service pipelines and seven transmission compressor stations, and SDG&E’s natural gas facilities consisted of 9,206 miles of distribution pipelines, 177 miles of transmission pipelines, 6,795 miles of service pipelines and one compressor station.

SoCalGas’ and SDG&E’s gas transmission pipelines interconnect with four major interstate pipeline systems: El Paso Natural Gas, Transwestern Pipeline, Kern River Pipeline Company, and Mojave Pipeline Company, allowing customers to bring gas supplies into the SoCalGas gas transmission pipeline system from the various out-of-state gas producing basins. Additionally, an interconnection with PG&E’s intrastate gas transmission pipeline system allows gas to flow into SoCalGas’ gas transmission pipeline system. SoCalGas’ gas transmission pipeline system also has an interconnection with a Mexican gas pipeline company at Otay Mesa on the California/Mexico border that allows gas to not only flow south from the gas producing basins in the southwestern U.S., but to also flow north into SoCalGas’ gas transmission pipeline system from supplies in Mexico. There are also several in-state gas interconnections allowing for delivery of California-produced gas, including a number of direct connections from biomethane producers.

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SoCalGas purchases natural gas under short-term and long-term contracts and on the spot market for SDG&E’s and SoCalGas’ core customers. SoCalGas purchases natural gas from various producing regions, including from Canada, the U.S. Rockies and the southwestern regions of the U.S. Purchases of natural gas are primarily priced based on published indices, which can be subject to volatility. The cost of purchases of natural gas for SDG&E’s and SoCalGas’ core customers is billed to those customers without markup.

To support the delivery of natural gas supplies to its distribution system and to meet the needs of customers, SoCalGas has firm and variable interstate pipeline capacity contracts that require the payment of fixed and variable tariffed and negotiated reservation charges to reserve firm and interruptible transportation rights. Energy companies, primarily El Paso Natural Gas Company, Transwestern Pipeline Company and Kern River Gas Transmission Company, provide transportation services into SoCalGas’ intrastate transmission system for supplies purchased by SoCalGas.

Natural Gas Storage. SoCalGas owns four natural gas storage facilities with a combined working gas capacity of 137 Bcf and 122 injection, withdrawal and observation wells that provide natural gas storage service. SoCalGas’ and SDG&E’s core customers, along with certain third-party market participants, are allocated a portion of SoCalGas’ storage capacity. SoCalGas uses the remaining storage capacity for load balancing services for all customers and for storage for noncore customers. Natural gas withdrawn from storage is important to help maintain service reliability during peak demand periods, including consumer heating needs in the winter, as well as peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility has a storage capacity of 86 Bcf and, subject to a biennial administrative staff review by the CPUC and additional CPUC proceedings, represents 63% of SoCalGas’ working natural gas storage capacity. At December 31, 2025, SoCalGas has been authorized by the CPUC to utilize up to 68.6 Bcf of working gas at the facility.

Customers and Demand. SoCalGas and SDG&E sell, distribute and transport natural gas. SoCalGas purchases and stores natural gas for its core customers in its territory and SDG&E’s territory on a combined portfolio basis. SoCalGas also offers natural gas transportation and storage services for others.

NATURAL GAS CUSTOMER METERS AND VOLUMES	Customer meter count	Volumes (Bcf) (1)
	December 31,	Years ended December 31,
	2025	2025	2024	2023
SDG&E:
Residential	888,245
Commercial	29,215
Electric generation and transportation	3,137
Natural gas sales		44	45	48
Transportation		34	38	39
Total	920,597	78	83	87
SoCalGas:
Residential	5,938,904
Commercial	248,047
Industrial	23,554
Electric generation and wholesale	38
Natural gas sales		289	304	321
Transportation		471	522	549
Total	6,210,543	760	826	870

(1) Includes intercompany sales.

For regulatory purposes, end-use customers are classified as either core or noncore customers. Core customers are primarily residential and small commercial and industrial customers.

Most core customers purchase natural gas directly from SoCalGas or SDG&E. While core customers are permitted to purchase their natural gas supplies from producers, marketers or brokers, SoCalGas and SDG&E are obligated to maintain adequate delivery capacity to serve the requirements of all core customers in their service territories.

SoCalGas’ noncore customers consist primarily of electric generation, wholesale, and large commercial and industrial customers. A portion of SoCalGas’ noncore customers are non-end-users, which include wholesale customers consisting primarily of other utilities, including SDG&E, or municipally owned natural gas distribution systems. Noncore customers at SDG&E consist primarily of electric generation and large commercial customers.

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Noncore customers are responsible for procuring their natural gas requirements, as the regulatory framework does not allow SoCalGas and SDG&E to recover the cost of natural gas procured and delivered to noncore customers.

Natural gas demand largely depends on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preferences, environmental regulations, legislation, California’s energy policy supporting increased electrification and renewable power generation, and the effectiveness of energy efficiency programs, among other factors. Other external factors such as weather, the price of, demand for, and supply sources of electricity, the use and further development of renewable energy sources and energy storage, development of or requirements for new natural gas supply sources, demand for natural gas outside California, storage levels, transport capacity and availability of supply into California and general economic conditions can also result in significant shifts in the market price of natural gas, which may in turn impact demand.

One of the larger drivers of natural gas demand is electric generation. Natural gas-fired electric generation within Southern California (and demand for natural gas supplied to such plants) competes with electric power generated throughout the western U.S. Natural gas transported for electric generating plant customers may be affected by the overall demand for electricity, growth in self-generation from rooftop solar, the addition of more efficient gas technologies, new energy efficiency initiatives, and the degree to which regulatory changes in electric transmission infrastructure investment divert electric generation from SoCalGas’ and SDG&E’s service areas. The demand for natural gas may also fluctuate due to volatility in the demand for electricity due to seasonality, weather conditions and other impacts, and the availability of competing supplies of electricity, such as renewable energy sources, among other factors. Given the significant level and availability of natural gas-fired generation, we believe natural gas is a dispatchable fuel that can continue to help provide electric reliability in our California service territories.

The natural gas distribution business is subject to seasonality. Demand for natural gas in our service territory typically rises during the winter months to accommodate heating needs and the summer months to support peak electric generation. As is prevalent in the industry, subject to regulatory limitations, SoCalGas typically injects natural gas into storage during the months of April through October and usually withdraws natural gas from storage during the months of November through March.

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Sempra Texas Utilities

Sempra Texas Utilities is comprised of our equity method investments in Oncor Holdings and Sharyland Holdings. Oncor Holdings is a wholly owned entity of Sempra that owns an 80.25% interest in Oncor. TTI owns the remaining 19.75% interest in Oncor. Sempra owns a 50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities.

Sempra Texas Utilities’ assets at December 31, 2025 covered the following territory:

For a discussion of the risks and uncertainties related to our equity investments in Oncor Holdings and Sharyland Holdings, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Texas Utilities.”

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Oncor

Oncor is a regulated electricity transmission and distribution utility that operates in the north-central, eastern, western and panhandle regions of Texas. Oncor delivers electricity to end-use consumers through its electrical systems and also provides transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas. Oncor’s transmission and distribution assets are located in over 120 counties and more than 400 incorporated municipalities, including the cities of Dallas and Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler, Temple, Killeen and Round Rock, among others. Most of Oncor’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way pursuant to permits, public utility easements, franchise or other agreements or as otherwise permitted by law.

At December 31, 2025, Oncor had approximately 5,600 employees, including 860 employees covered under a collective bargaining agreement and excluding interns.

Certain ring-fencing measures, governance mechanisms and commitments, which we describe in “Part I – Item 1A. Risk Factors,” are in effect and are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, their owners. Sempra does not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and commitments limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends or other distributions, strategic planning and other important corporate matters and actions, including limited representation on the Oncor Holdings and Oncor boards of directors. Because Oncor Holdings and Oncor are managed independently (i.e., ring-fenced), we account for our 100% ownership interest in Oncor Holdings as an equity method investment.

Electricity Transmission. Oncor’s electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction, maintenance and security of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over its transmission facilities in coordination with ERCOT, which we discuss below in “Regulation – Utility Regulation – ERCOT Market.”

At December 31, 2025, Oncor’s transmission system included approximately 18,418 circuit miles of transmission lines, a total of 1,333 transmission and distribution substations, and interconnection to 230 third-party generation facilities totaling 63,670 MW.

Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to limited interconnections to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity over transmission facilities operating at 60 kV and above and are collected from load serving entities benefiting from Oncor’s transmission system. Other services offered by Oncor through its transmission business include system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.

Electricity Distribution. Oncor’s electricity distribution business is responsible for the overall safe and reliable operation of distribution facilities, including electricity delivery, power quality, security and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the electricity distribution system within its certificated service area. Oncor’s distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through 3,874 distribution feeders at December 31, 2025.

Oncor’s distribution system included more than 4.1 million points of delivery at December 31, 2025 and consisted of 127,398 circuit miles of overhead and underground lines.

Distribution revenues from residential and small business users are generally based on actual monthly consumption (kWh) and distribution revenues from large commercial and industrial users are based on, depending on size and annual load factor, either actual monthly demand (kW) or the greater of actual monthly demand (kW) or 80% of peak monthly demand during the prior eleven months.

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Customers and Demand. Oncor operates the largest transmission and distribution system in Texas based on the number of end-use customers and miles of transmission and distribution lines. Oncor delivers electricity to more than 4.1 million homes and businesses and operates more than 145,000 circuit miles of transmission and distribution lines as of December 31, 2025 in a territory with an estimated population of approximately 14 million. The majority of consumers of the electricity Oncor delivers are free to choose their electricity supplier from retail electric providers who compete for their business. Oncor is not a seller of electricity, nor does it purchase electricity for resale. Oncor provides wholesale transmission services to its electricity distribution business as well as non-affiliated electricity distribution companies, electric cooperatives and municipally owned utilities. Oncor also provides distribution services, consisting of retail delivery services to retail electric providers that sell electricity to end-use customers, as well as wholesale delivery services to electric cooperatives and municipally owned utilities. At December 31, 2025, Oncor’s distribution business customers primarily consisted of over 100 retail electric providers that sell the electricity it distributes to consumers in its certificated service areas.

Oncor’s revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.

Competition. Oncor operates in certificated areas designated by the PUCT. The majority of Oncor’s service territory is singularly certificated, with Oncor as the only certificated electric transmission and distribution provider. However, in multi-certificated areas of Texas, Oncor competes with certain municipal utilities and rural electric cooperatives for the right to serve end-use customers. In addition, the electric industry is undergoing rapid technological change, and third-party DER (including behind the meter alternatives and private use networks) and virtual power plants and other technologies may increasingly compete with Oncor’s traditional transmission and distribution infrastructure in delivering electricity to consumers.

Sharyland Utilities

Sharyland Utilities is a regulated electric transmission utility that owns and operates, at December 31, 2025, approximately 64 miles of electric transmission lines in south Texas, including a direct current line connecting Mexico and assets in McAllen, Texas. Sharyland Utilities is responsible for providing safe, reliable and efficient transmission and substation services and investing to support infrastructure needs in its service territory, which we discuss below in “Regulation – Utility Regulation – ERCOT Market.” Transmission revenues are provided under tariffs approved by the PUCT.

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Sempra Infrastructure

Our Sempra Infrastructure segment includes the operating companies of our subsidiary, SI Partners, as well as a holding company and certain services companies. SI Partners is included within our Sempra Infrastructure reportable segment but is not the same in its entirety as the reportable segment. Sempra Infrastructure develops, constructs, 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.

At December 31, 2025, Sempra Infrastructure owned or held interests in the following assets:

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At December 31, 2025, Sempra, KKR Pinnacle and ADIA each hold a 70%, 20%, and 10% interest, respectively, in SI Partners. SI Partners owns a 100% interest in Sempra LNG Holding, LP and a 99.9% interest in IEnova at December 31, 2025.

The minority partners in SI Partners and Sempra are parties to a limited partnership agreement of SI Partners. Under this agreement, matters are generally decided by majority vote and the managers designated by the partners of SI Partners each vote on an equity-weighted basis based on the ownership percentage of their respective designating limited partner. SI Partners and its controlled subsidiaries are prohibited from taking certain limited actions without the prior written approval of the minority partners. The limited partnership agreement contains certain default remedies if any limited partner fails to fund any amounts required to be funded under the agreement and requires that SI Partners distribute to the limited partners at least 85% of distributable cash of SI Partners and its subsidiaries on a quarterly basis, subject to certain exceptions and reserves. Generally, distributions from SI Partners are made on a pro rata basis. However, KKR Pinnacle is entitled to certain priority distributions in the event of material deviations between certain specified projected cash flows and actual cash flows. Additionally, the minority partners are entitled to certain priority distributions in the event a specified project that reaches a positive FID does not have projected internal rates of return greater than a specified threshold or does not meet certain other conditions by certain dates. If the minority partners approve Sempra’s request that a project not be pursued jointly, or if the minority partners decide not to participate in any proposed project for which Sempra nevertheless desires to make a positive FID, then Sempra may proceed with such project either independently through a different investment vehicle or as a “Sole Risk Project” within SI Partners and receive Sole Risk Interests in respect thereof. Sole Risk Projects are separated from other SI Partners projects and are conducted at Sempra’s sole cost, expense and liability, and Sempra receives, through the acquisition of Sole Risk Interests, the economic and other benefits, if any, from such projects.

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 closing conditions. Subject to closing, the KKR Partners will own 65% of SI Partners, Sempra will own a 25% interest and ADIA will retain a 10% interest, with the KKR Partners assuming control. Sempra will deconsolidate SI Partners and account for its 25% interest in SI Partners under the equity method within the existing Sempra Infrastructure segment. At closing, we will enter into an amended and restated limited partnership agreement of SI Partners with the KKR Partners and ADIA, which will govern the rights and obligations of the partners with respect to SI Partners after the sale and will include transfer restrictions, provisions for Sole Risk Projects, under which a partner may independently pursue projects at its own cost and risk, and various other provisions. We describe the terms of this post-closing limited partnership agreement in further detail in Note 6 of the Notes to Consolidated Financial Statements.

In December 2025, we entered into an agreement to sell Ecogas, a natural gas regulated distribution utility that we describe below, to Gas Natural del Noroeste S.A. de C.V. for 9.0 billion Mexican pesos (approximately $500 million U.S. dollar-equivalent at December 31, 2025), subject to adjustments. We expect to complete the sale in the second or third quarter of 2026, subject to closing conditions.

As a result of satisfying all applicable criteria, we classified SI Partners’ and Ecogas’ assets and liabilities as held for sale and ceased depreciation and amortization. We provide further discussion regarding the sales of SI Partners and Ecogas in Note 6 of the Notes to Consolidated Financial Statements.

Subject to closing these sales, we expect Sempra’s ownership interests in SI Partners and all assets owned by SI Partners, other than those listed in the table below, to be 25% post-closing.

SEMPRA’S OWNERSHIP INTERESTS	At December 31, 2025	Projected post-sale
Cameron LNG Phase 1 facility	35.1 %	12.6 %
Cameron LNG Phase 2 project	35.1	12.6
ECA LNG Phase 1 project	58.4	20.9
Ecogas	70.0	—
IMG	28.0	10.0
PA LNG Phase 1 project	19.6	7.0
PA LNG Phase 2 project	35.1	12.5
Sonora pipeline – Guaymas-El Oro segment	100.0	100.0
TAG Norte	35.0	12.5

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Sempra Infrastructure consolidates Sempra’s ownership and management of its non-U.S. utility energy infrastructure assets in North America under a single platform. These assets include LNG and natural gas infrastructure in the U.S. and Mexico and renewable energy, LPG and refined products infrastructure in Mexico, which are managed through three business lines: LNG, Energy Networks and Low Carbon Solutions. For a discussion of the risks and uncertainties facing Sempra Infrastructure’s business, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”

LNG

Sempra Infrastructure’s LNG business line is comprised of a natural gas liquefaction and regasification portfolio in development, under construction or in operation and is focused on securely delivering natural gas to markets around the world. Sempra Infrastructure’s development and/or construction of projects, which we describe below, is subject to numerous risks and uncertainties.

Cameron LNG Phase 1 Facility. SI Partners owns 50.2% of Cameron LNG JV. An affiliate of TotalEnergies SE, an affiliate of Mitsui & Co., Ltd., and Japan LNG Investment, LLC (a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha) each own 16.6% of Cameron LNG JV. SI Partners accounts for its ownership interest in Cameron LNG JV under the equity method. No single owner controls or can unilaterally direct significant activities of Cameron LNG JV.

Cameron LNG JV owns and operates the Cameron LNG Phase 1 facility, a natural gas liquefaction, export, regasification and import facility with three natural gas pre-treatment, processing and liquefaction trains. The Cameron LNG Phase 1 facility is located in Hackberry, Louisiana, along the Calcasieu Ship Channel, which handles significant industrial shipping, including large oil and LNG tankers, that we believe is well positioned to supply the Atlantic and Pacific markets. The three liquefaction trains have a combined nameplate capacity of 13.9 Mtpa of LNG with an export capacity of 12 Mtpa of LNG, or approximately 1.7 Bcf of natural gas per day.

The Cameron LNG Phase 1 facility has 20-year liquefaction and regasification tolling capacity agreements in place with affiliates of TotalEnergies SE, Mitsubishi Corporation and Mitsui & Co., Ltd., which collectively subscribe for the full nameplate capacity of the three trains at the facility.

ECA Regas Facility. SI Partners owns and operates the ECA Regas Facility in Baja California, Mexico, which is capable of processing one Bcf of natural gas per day and has a storage capacity of 320,000 cubic meters in two tanks of 160,000 cubic meters each.

The ECA Regas Facility generates revenues from fees under a firm storage and nitrogen injection service agreement with Shell that expires in May 2028 and permits it to use 36% of the terminal’s capacity, with the remaining capacity available for SI Partners’ use. SI Partners uses a portion of its capacity to satisfy its obligation under an LNG SPA with Tangguh PSC through 2029, which we discuss below. ECA LNG Phase 1 will be the sole user of this capacity thereafter.

The land adjacent to and owned by the ECA Regas Facility is the subject of litigation. The facility, however, is not situated on the land that is the subject of this dispute. We discuss litigation, regulatory and other matters that could impact the ECA Regas Facility and the ECA LNG liquefaction projects in Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.”

ECA LNG Phase 1 Project. SI Partners owns an 83.4% interest in the ECA LNG Phase 1 project that is under construction. An affiliate of TotalEnergies SE owns the remaining 16.6% interest in the project. The ECA LNG Phase 1 project will consist of a one-train natural gas liquefaction facility at the site of SI Partners’ existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa.

The ECA LNG Phase 1 project 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. As of February 26, 2026, no customers have given notice of their intent to terminate the SPAs.

The ECA LNG Phase 1 project achieved mechanical completion in December 2025, and we expect the 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.

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PA LNG Phase 1 Project. SI Partners, KKR Denali and an affiliate of ConocoPhillips own a 28%, 42% and 30% interest, respectively, in the PA LNG Phase 1 project under construction on a greenfield site 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.

The PA LNG Phase 1 project has definitive SPAs for LNG offtake 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

The first train of the Port Arthur LNG liquefaction project remains on schedule, and we continue to expect the first and second trains to commence commercial operations at or near the end of 2027 and in 2028, respectively.

KKR Denali’s interest in the PA LNG Phase 1 project is governed by a limited liability company agreement under which (i) a subsidiary of SI Partners (a) is the managing member, (b) exclusively holds the right to make decisions with respect to certain expansions, such as the PA LNG Phase 2 project, (c) has certain rights to preferential distributions from specified revenues and expansion true-up payments, and (d) through a parent entity that is a subsidiary of Sempra, bears a disproportionately higher allocation of certain capital contribution commitments in certain budgetary overrun scenarios; and (ii) KKR Denali has certain investor protection voting rights.

PA LNG Phase 2 Project. Since September 2025, SI Partners owns 50.1% and Blackstone owns 49.9% of the PA LNG Phase 2 project, a large-scale natural gas liquefaction project located adjacent to the PA LNG Phase 1 project. As we discuss in Note 12 of the Notes to Consolidated Financial Statements, 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 CRNCI in Sempra’s Consolidated Balance Sheet.

Construction of the PA LNG Phase 2 project commenced in September 2025 after reaching a positive FID. The PA LNG Phase 2 project will include two liquefaction trains, one LNG storage tank, and associated facilities with a nameplate capacity of approximately 13 Mtpa.

The PA LNG Phase 2 project has definitive SPAs for LNG offtake 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 PA LNG Phase 2 project for a 20-year term for 2.5 Mtpa of LNG and has entered into offtake agreements for excess quantities of LNG, including 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 expect the third and fourth trains of the Port Arthur LNG liquefaction project to commence commercial operations in 2030 and 2031, respectively.

Asset and Supply Optimization. SI Partners has an LNG SPA through 2029 with Tangguh PSC for the supply of the equivalent of 500 MMcf of natural gas per day at a price based on the SoCal Border index for natural gas. The LNG SPA allows Tangguh PSC to divert certain LNG volumes to other global markets in exchange for payments of diversion fees. SI Partners may also enter into short-term supply agreements to purchase LNG to be received, stored and regasified at the ECA Regas Facility for sale to other parties. SI Partners uses the natural gas produced from this LNG to supply a contract for the sale of natural gas to the CFE at prices that are based on the SoCal Border index. If LNG volumes received from Tangguh PSC are not sufficient to satisfy the commitment to the CFE, SI Partners may purchase natural gas in the market to satisfy such commitment.

SI Partners purchases, transports and sells natural gas and LNG, and has customers in both the U.S. and Mexico, including the CFE. SI Partners may also purchase natural gas from other Sempra affiliates. Natural gas purchases and transportation arrangements are substantially backed by long-term, U.S. dollar-based contracts for the sale of natural gas to third parties (both U.S. sourced and derived from imported LNG), LNG offtake and natural gas storage and pipeline capacity.

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LNG Projects Under Development. SI Partners is pursuing or evaluating the following development opportunities:

▪ Cameron LNG Phase 2 project, an expansion of the Cameron LNG Phase 1 facility that would add one electric drive liquefaction train and debottlenecking capacity from the existing three trains

▪ ECA LNG Phase 2 project, a large-scale natural gas liquefaction project to be located at the site of SI Partners’ existing ECA Regas Facility in Baja California, Mexico

No FID has been reached for either of these potential projects.

Demand and Competition. North America benefits from numerous competitive advantages as a supplier of LNG to world markets, including the following:

▪ high levels of developed and undeveloped natural gas resources, including unconventional natural gas and oil relative to domestic consumption levels

▪ flexible and mature oil and gas markets resulting in efficient unit costs of gas production

▪ availability of extensive natural gas pipeline transmission systems and natural gas storage capacity with proximity to production locations

Global LNG demand and competition may limit North American LNG exports, as international liquefaction projects attempt to match North American LNG production costs and customer contractual rights such as volume and destination flexibility. North American LNG exports add market flexibility that is expected to facilitate additional growth of a global commodity market for natural gas and LNG.

Our LNG projects in development, under construction or in operation all compete globally to market and sell LNG to remarketers and end-users, including gas and electric utilities located in LNG-importing countries around the world. We compete with liquefaction projects currently operating and those under development in the global LNG market. In addition to the U.S., these competitors are located in the Middle East, Southeast Asia, Africa, South America, Australia and Europe.

Energy Networks

Sempra Infrastructure’s Energy Networks business line is comprised of a natural gas transportation and distribution network.

Cross-Border Interconnections and In-Country Pipelines. SI Partners develops, constructs, owns and operates systems for the receipt, transportation, compression and delivery of natural gas and ethane. At December 31, 2025, these systems consisted of 1,985 miles of natural gas transmission pipelines, 17 natural gas compression stations and 139 miles of ethane pipelines in Mexico. The design capacity of these pipeline assets is over 16,900 MMcf per day of natural gas, 204 MMcf per day of ethane gas and 106,000 barrels per day of ethane liquid. Capacity on SI Partners’ pipelines and related assets is substantially contracted under long-term, U.S. dollar-based agreements with major industry participants such as the CFE, Centro Nacional de Control de Gas, PEMEX and other similar counterparties. See “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure” for a discussion about the Guaymas-El Oro segment of the Sonora pipeline.

SI Partners owns the Cameron Interstate Pipeline, a 40-mile natural gas pipeline in south Louisiana that links the Cameron LNG Phase 1 facility in Cameron Parish in Louisiana to seven pipelines that offer access to major feed gas supply basins in Texas and the northeast, midcontinent and southeast regions of the U.S. The majority of transportation capacity on the Cameron Interstate Pipeline is under long-term transportation service agreements with shippers for delivery to the Cameron LNG Phase 1 facility.

SI Partners is constructing the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana. We expect the Port Arthur Pipeline Louisiana Connector to be ready for service ahead of the PA LNG Phase 1 project’s gas requirements.

Natural Gas Distribution. SI Partners owns the natural gas distribution regulated utility, Ecogas, which operates in three separate distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico. At December 31, 2025, Ecogas had approximately 3,246 miles of distribution pipeline, and approximately 169,000 customer meters serving more than 661,000 residential, commercial and industrial consumers with total distribution volume of 94.1 MMcf per day in 2025, of which 10.7 MMcf per day were gas sales to direct end users of Ecogas. Ecogas relies on supply and transportation services, including from SI Partners and SoCalGas for the natural gas it distributes to its customers.

As we discuss in Note 6 of the Notes to Consolidated Financial Statements, in December 2025, we entered into an agreement to sell Ecogas to Gas Natural del Noroeste S.A. de C.V. for 9.0 billion Mexican pesos (approximately $500 million U.S. dollar-equivalent at December 31, 2025), subject to adjustments. We expect to complete the sale in the second or third quarter of 2026, subject to closing conditions.

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LPG Storage and Associated Systems. SI Partners owns and operates the TDF, S. de R. L. de C. V. (TDF) pipeline system and the Guadalajara LPG terminal. At December 31, 2025, the TDF pipeline system consisted of approximately 118 miles of 12-inch diameter LPG pipeline with a design capacity of 34,000 barrels per day and associated storage and dispatch facilities. The TDF pipeline system runs from PEMEX’s Burgos facility in the Mexican state of Tamaulipas, Mexico to SI Partners’ approximately 32,000-barrel LPG storage facility near the city of Monterrey, Mexico and is fully contracted to PEMEX on a firm basis through 2027. SI Partners’ Guadalajara LPG terminal is an 80,000-barrel LPG storage facility near Guadalajara, Mexico, with associated loading and dispatch facilities, and serves the LPG needs of Guadalajara. The Guadalajara LPG terminal is fully contracted to PEMEX on a firm basis through 2028. Both contracts are U.S. dollar-denominated or referenced and are periodically adjusted for inflation.

Refined Products and Natural Gas Storage. SI Partners’ refined products storage business develops, constructs, owns and operates systems for the receipt, storage and delivery of refined products, principally gasoline, diesel and jet fuel, throughout the Mexican states of Baja California, Colima, Estado de Mexico, Puebla, Sinaloa and Veracruz for private companies, with a combined storage capacity of 4.6 million barrels fully operating as of December 31, 2025. Our customer contracts for our refined products storage business are structured as long-term, U.S. dollar-denominated, firm capacity storage agreements with counterparties including Marathon Petroleum Corporation, Valero Energy Corporation and PEMEX. The contracted rate under these contracts is independent from each terminal’s regulated rate as determined by the CNE.

SI Partners 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. We expect Louisiana Storage to be ready for service in time to support the needs of the PA LNG Phase 1 project.

Demand and Competition. Ecogas faces competition from other distributors of natural gas in each of its three distribution zones as other distributors of natural gas construct or consider constructing natural gas distribution systems. SI Partners’ pipeline and storage facilities businesses compete with other regulated and unregulated pipeline and storage facilities. They compete primarily on the basis of price (in terms of storage and transportation fees), available capacity and interconnections to downstream markets. The overall demand for natural gas distribution services increases during the winter months, while the overall demand for power increases during the summer months.

Low Carbon Solutions

Sempra Infrastructure’s Low Carbon Solutions business line is focused on developing, constructing and operating energy infrastructure to help meet the demand for lower carbon and reliable energy supply. The portfolio of infrastructure assets includes renewable energy generation, a natural gas-fired power plant, as well as the development of infrastructure for carbon capture and storage and for generation and storage of low carbon energy.

Renewable Power Generation. SI Partners develops, constructs, owns and operates renewable energy generation facilities that have long-term PPAs to sell the electricity they generate to their customers, which are generally load-serving entities and industrial and other customers. Load serving entities sell electric service to their end-users and wholesale customers upon receipt of power delivery from these energy generation facilities, while industrial and other customers consume the electricity to run their facilities. At December 31, 2025, SI Partners had total nameplate capacity of 1,044 MW related to its operating wind and solar power generation facilities. Generation from SI Partners’ renewable energy assets is susceptible to fluctuations in naturally occurring conditions such as wind, inclement weather and hours of sunlight. Some of these facilities may be affected by recent legal and regulatory changes in Mexico, which we discuss in “Part I – Item 1A. Risk Factors.”

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RENEWABLE POWER GENERATION	Location	Contract expiration date	Nameplate capacity (MW)
Wind power generation facilities:
ESJ – first phase	Tecate, Baja California	2035	155
ESJ – second phase	Tecate, Baja California	2042	108
Ventika	Nuevo León, Mexico	2036	252
Solar power generation facilities:
Border Solar	Ciudad Juarez, Chihuahua	2035, 2040 and 2041	150
Don Diego Solar	Benjamin Hill, Sonora	2037 and 2040	125
Pima Solar	Caborca, Sonora	2038	110
Rumorosa Solar	Tecate, Baja California	2034 and 2039	44
Tepezalá Solar	Aguascalientes, Mexico	2035 and 2040	100
Total			1,044

Natural Gas-Fired Generation. SI Partners owns and operates the TdM power plant in the vicinity of Mexicali, Baja California, adjacent to the Mexico-U.S. border. TdM is a 625 MW natural gas-fired, combined-cycle power plant that is connected to our Gasoducto Rosarito pipeline system, which enables it to receive regasified LNG from the ECA Regas Facility as well as continental gas supplied from the U.S. on the North Baja pipeline. TdM generates revenue from selling electricity and resource adequacy to the California ISO for delivery to governmental, public utility and wholesale power marketing entities.

Low Carbon Solutions Projects. The Cimarrón Wind project, an approximately 320-MW wind generation facility in Baja California, Mexico, commenced energy generation in October 2025 during its commissioning phase. We expect commercial operations to commence in the first quarter of 2026. SI Partners 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 the available capacity on one of SI Partners’ existing cross-border high voltage transmission lines to interconnect and deliver clean energy to the East County substation in San Diego County.

SI Partners 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.

Demand and Competition. SI Partners competes with Mexican and foreign companies for new energy infrastructure projects in Mexico. Some of its competitors (including public or state-operated companies and their affiliates) may have better access to capital or greater financial and other resources or advantages, including those provided by recent legal and regulatory changes in Mexico, which could give them a competitive advantage for such projects.

SI Partners sells power from its ESJ wind power generation facilities into California, where renewable energy demand is affected by U.S. state mandates requiring a portion of energy to come from renewable sources. These mandates are part of California’s RPS Program. The first and second phases of ESJ, which are in operation, were certified by the CEC under the RPS Program. Certification by the CEC means that the energy produced by a facility is eligible to generate RECs, which can be used to meet California’s RPS Program requirements, which in turn influences the demand from California load serving entities for energy from that facility. In January 2025, the CEC approved Cimarrón Wind’s application for precertification under the RPS Program.

TdM participates in the day-ahead and real-time markets supplying power into the California electricity system. SI Partners manages commodity price risk at TdM through a mix of day-ahead sales of energy, energy spreads hedging, ancillary services, and short-term to medium-term capacity sales.

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REGULATION

We discuss the material effects of compliance with government regulations, including environmental regulations, on our capital expenditures, earnings and competitive position in “Part II – Item 7. MD&A” and Note 16 of the Notes to Consolidated Financial Statements.

Utility Regulation

California

SDG&E and SoCalGas are principally regulated at the state level by the CPUC, CEC and CARB.

The CPUC:

▪ consists of five commissioners appointed by the Governor of California for staggered, six-year terms;

▪ regulates, among other things, SDG&E’s and SoCalGas’ customer rates and conditions of service, sales of securities, rates of return, capital structure, rates of depreciation, long-term resource procurement and other financial matters, except as described below in “U.S. Federal;”

▪ has jurisdiction over the proposed construction of major electric generation, transmission and distribution, and natural gas transmission, distribution and storage facilities in California;

▪ conducts reviews and audits of utility performance and compliance with regulatory guidelines and conducts investigations related to various matters, such as safety standards and practices, reliability and planning, deregulation, competition, disconnection and billing practices, commodity pricing, resource adequacy and environmental compliance; and

▪ regulates the interactions and transactions of SDG&E and SoCalGas with Sempra and other affiliates, including their marketing functions.

The CPUC also oversees and regulates other energy-related products and services, including solar and wind energy, bioenergy, alternative energy storage and other forms of renewable energy. In addition, the CPUC’s safety and enforcement authority includes inspections, investigations and citation and enforcement programs for safety and other violations.

The CEC publishes electric demand forecasts for the state and specific service territories. Based on these forecasts, the CEC:

▪ determines the need for additional energy sources and conservation programs;

▪ sponsors alternative-energy research and development projects;

▪ promotes energy conservation programs to reduce demand for natural gas and electricity within California;

▪ maintains a statewide plan of action in case of energy shortages; and

▪ certifies power-plant sites and related facilities within California.

The CEC conducts a 20-year forecast of available supplies and prices for every market sector that consumes natural gas in California. This forecast includes resource evaluation, pipeline capacity needs, natural gas demand and wellhead prices, and transportation and distribution costs. This analysis is one of many resource materials used to support SDG&E’s and SoCalGas’ long-term investment decisions.

We discuss regulatory oversight by CARB below in “Environmental Matters – Air Quality and GHG Emissions.”

Texas

Oncor’s and Sharyland Utilities’ rates are regulated at the state level by the PUCT and, in the case of Oncor, at the city level by certain cities. The PUCT has original jurisdiction over wholesale transmission rates and services and retail rates and services in unincorporated areas and in municipalities that have ceded original jurisdiction to the PUCT, and has exclusive appellate jurisdiction to review the retail rates, retail services, and ordinances of municipalities. Generally, PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that do not have the prior approval of the appropriate regulatory authority (i.e., the PUCT or the municipality with original jurisdiction).

At the state level, PURA requires utility owners or operators of electric transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility’s own use of its system. The PUCT has adopted rules implementing the state’s open-access requirements for all utilities that are subject to the PUCT’s jurisdiction over electric transmission services, including Oncor.

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U.S. Federal

SDG&E and SoCalGas are also regulated at the federal level by the FERC, EPA, DOE and DOT, and for SDG&E the NRC.

The FERC regulates SDG&E’s and SoCalGas’ interstate sale and transportation of natural gas. The FERC also regulates SDG&E’s:

▪ electric transmission rates

▪ transmission and wholesale sales of electricity in interstate commerce

▪ transmission access

▪ rates of return and rates of depreciation on electric transmission investments

▪ electric rates involving sales for resale

▪ the application of the uniform system of accounts

The FERC enforces mandatory reliability standards developed by the North American Electric Reliability Corporation, including standards designed to protect the power system against potential disruptions from cyber and physical security breaches. The U.S. Energy Policy Act governs procedures for requests for electric transmission service. To a small degree related to limited interconnections to other markets, Oncor’s electric transmission revenues are provided under tariffs approved by the FERC.

The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities in the U.S., including SONGS, in which SDG&E owns a 20% interest and which permanently ceased operations in 2013. The NRC and various state regulations require extensive review of these facilities’ safety, radiological and environmental aspects. We provide further discussion of SONGS matters, including the closure and decommissioning of the facility, in Note 15 of the Notes to Consolidated Financial Statements.

The EPA implements federal laws to protect human health and the environment, including federal laws on air quality, water quality, wastewater discharge, solid waste management, and hazardous waste disposal and remediation. The EPA also sets national environmental standards that state and tribal governments implement through their regulations. As a result, SDG&E, SoCalGas, Oncor and Sharyland Utilities are subject to an interrelated framework of environmental laws and regulations.

The DOT, through PHMSA, has established regulations regarding engineering standards and operating procedures, including procedures intended to manage cybersecurity risks, applicable to SDG&E’s and SoCalGas’ natural gas transmission and distribution pipelines, as well as natural gas storage facilities. The DOT has certified the CPUC to administer oversight of and compliance with these regulations for the entities they regulate in California.

California ISO Market

The California IOUs’ electric transmission facilities are under the operational control of the California ISO. The California ISO is a non‑profit, federally regulated organization that manages the flow of electricity from generators to local utilities across approximately 80% of California’s high‑voltage power grid. Within its balancing authority area, the California ISO oversees the markets that help balance electricity supply and demand, coordinate dispatch of generation, and manage system constraints.

ERCOT Market

As member utilities, Oncor and Sharyland Utilities operate within the ERCOT market, which represents approximately 90% of the electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the ISO of the interconnected transmission grid for those systems. ERCOT is subject to oversight by the PUCT and the Texas Legislature. ERCOT is responsible for ensuring reliability, adequacy and security of the electric systems, as well as nondiscriminatory access to transmission service by all wholesale market participants, in the ERCOT region. ERCOT’s membership consists of corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, transmission service providers, distribution service providers, independent retail electric providers and consumers.

The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’ main interconnected electric transmission grid. Oncor and Sharyland Utilities, along with other owners of electric transmission and distribution facilities in Texas, assist the ERCOT ISO in its operations. Each of these Texas utilities has planning, design, construction, operation, maintenance and security responsibility for the portion of the transmission grid and the load-serving substations it owns, primarily within its certificated service area. Each participates with the ERCOT ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing, constructing and upgrading transmission lines in order to remove any existing constraints and interconnect energy generation on the ERCOT transmission grid. These transmission line projects are necessary to meet reliability needs, support energy production and increase bulk power transfer capability.

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Oncor and Sharyland Utilities are subject to reliability standards adopted and enforced by the Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with the standards of the North American Electric Reliability Corporation, including critical infrastructure protection, and ERCOT protocols.

Other U.S. State and Local Territories Regulation

SDG&E has electric franchise agreements with the two counties and the 27 cities in its electric service territory, and natural gas franchise agreements with the one county and the 18 cities in its natural gas service territory. These franchise agreements allow SDG&E to locate, operate and maintain facilities for the transmission and distribution of electricity or natural gas. Most of the franchise agreements have no expiration dates, while some have expiration dates that range from 2028 to 2041. SDG&E has electric and natural gas franchises for the City of San Diego. These franchise agreements, which went into effect in July 2021, provide SDG&E the opportunity to serve the City of San Diego for 20 years, consisting of 10-year agreements that will automatically renew for an additional 10 years unless the City Council voids the automatic renewal. These franchise agreements have been challenged in a lawsuit that we discuss in Note 16 of the Notes to Consolidated Financial Statements.

SoCalGas has natural gas franchise agreements with the 12 counties and the 232 cities in its service territory. These franchise agreements allow SoCalGas to locate, operate and maintain facilities for the transmission and distribution of natural gas. Most of the franchise agreements have no expiration dates, while some have expiration dates that range from 2026 to 2069.

Other U.S. Federal Regulation

The FERC regulates certain of SI Partners’ assets pursuant to the U.S. Federal Power Act and Natural Gas Act, which provide for FERC jurisdiction over, among other things, sales of wholesale power in interstate commerce, transportation of natural gas in interstate commerce, and siting and permitting of LNG facilities.

The FERC may regulate rates and terms of service based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be sufficiently competitive, rates may be market-based. FERC-regulated rates at SI Partners are market-based for wholesale electricity sales, cost-based for the transportation of natural gas, and market-based for the purchase and sale of LNG and natural gas.

SI Partners’ investment in Cameron LNG JV and its LNG projects under construction are subject to regulations of the DOE regarding the export of LNG. Under these regulations, the DOE acts on LNG export applications to non-FTA countries after completing a public interest review that includes several criteria, including economic and environmental review of the proposed export. SI Partners’ natural gas liquefaction projects under development are subject to similar regulations.

SDG&E, SoCalGas and certain of SI Partners’ businesses are subject to the DOT rules and regulations regarding pipeline safety. PHMSA, acting through the Office of Pipeline Safety, is responsible for administering the DOT’s national regulatory program to help ensure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines, including pipelines associated with natural gas storage, and develops regulations and other approaches to risk management to help ensure safety in design, construction, testing, operation, maintenance and emergency response of pipeline facilities. PHMSA also regulates the safety of onshore LNG facilities.

SDG&E, SoCalGas and SI Partners are also subject to regulation by the U.S. Commodity Futures Trading Commission.

Foreign Regulation

Operations and projects in our Sempra Infrastructure segment are subject to regulation by the ASEA, CNE, SENER, the Mexican Ministry of Environment and Natural Resources of Mexico (Secretaría del Medio Ambiente y Recursos Naturales), and other labor and environmental agencies of city, state and federal governments in Mexico. New energy infrastructure projects may also require a favorable opinion from Mexico’s Competition Commission (Comisión Federal de Competencia Económica) in order to be constructed and operated. Recent legal and regulatory changes in Mexico, which we discuss in “Part I – Item 1A. Risk Factors,” are designed to increase the government’s control and participation in the energy sector.

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Licenses and Permits

Our utilities in California and Texas obtain numerous permits, authorizations and licenses for, as applicable, the transmission and distribution of natural gas and electricity and the operation and construction of related assets, including electric generation and natural gas storage facilities, some of which require periodic renewal.

SI Partners obtains numerous permits, authorizations and licenses for its electric and natural gas distribution, generation and transmission systems from the local governments where these services are provided. The permits for generation, transportation, storage and distribution operations at SI Partners are generally for 30-year terms, with options for renewal under certain regulatory conditions.

SI Partners obtains permits, authorizations and licenses for the construction and operation of:

▪ LNG facilities, including the expansion thereof, and for the import and export of LNG and natural gas

▪ facilities for the receipt, storage and delivery of refined products

▪ natural gas storage facilities and pipelines

SI Partners’ businesses also obtain permits, authorizations and licenses in connection with their participation in the wholesale electricity market.

Most of the permits and licenses associated with SI Partners’ construction and operations are for periods generally in alignment with the construction cycle or expected useful life of the asset and in some cases are greater than 20 years.

RATEMAKING MECHANISMS

Sempra California

General Rate Case Proceedings

A CPUC GRC proceeding is designed to set authorized base revenue requirements that are sufficient to allow SDG&E and SoCalGas to recover their reasonable forecasted operating costs and to provide the opportunity to realize their authorized rates of return on their investments. The proceeding generally establishes the test year revenue requirements and provides for attrition, or annual increases in revenue requirements, for each year following the test year. Both the test year revenue requirements and attrition authorize how much SDG&E and SoCalGas can collect from their customers in base rates.

We discuss SDG&E’s and SoCalGas’ most recent GRCs in “Part I – Item 1A. Risk Factors,” “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California” and Note 4 of the Notes to Consolidated Financial Statements.

Cost of Capital Proceedings

A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and return on rate base, which is a weighted average of the authorized returns on debt, preferred equity and common equity (referred to as ROE), weighted on a basis consistent with the authorized capital structure. The authorized return on rate base approved by the CPUC is the rate that SDG&E and SoCalGas use to establish customer rates to finance investments in CPUC-regulated electric distribution and generation, natural gas distribution, transmission and storage assets, as well as general PP&E and information technology systems investments to support operations.

The CPUC established the CCM to apply in the interim years between required cost of capital applications. The CCM considers changes in the cost of capital using changes in interest rates as reflected by the applicable utility bond index published by Moody’s (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. Subject to regulatory approval, 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 during the measurement period. Alternatively, each of SDG&E and SoCalGas is 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.

We discuss the cost of capital and CCM in “Part I – Item 1A. Risk Factors,” “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California” and Note 4 of the Notes to Consolidated Financial Statements.

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Transmission Rate Cases

SDG&E files separate rate cases with the FERC for its FERC-regulated electric transmission operations and assets. The proceeding establishes, among other things, a ROE, capital structure and a formulaic rate whereby rates are determined using (i) a base period of historical costs and a forecast of capital investments, and (ii) a true-up period, similar to balancing account treatment, that is designed to provide earnings equal to SDG&E’s actual cost of service including its authorized return. SDG&E makes annual filings with the FERC to update rates for the following calendar year based on inputs in the FERC-approved formula rate that are contained in SDG&E’s Transmission Owner Tariff. SDG&E may also file for ROE incentives that might apply under FERC rules.

We discuss the latest FERC rate matters in “Part I – Item 1A. Risk Factors,” “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California” and Note 4 of the Notes to Consolidated Financial Statements.

Incentive Mechanisms

SoCalGas is subject to the GCIM and is eligible for financial awards or subject to financial penalties depending on its performance in relation to specific benchmarks. We discuss the GCIM in “Part II – Item 7. MD&A” and Note 3 of the Notes to Consolidated Financial Statements.

Other Cost-Based Regulatory Recovery

The CPUC, and the FERC as applicable to SDG&E, authorize SDG&E and SoCalGas to collect, or in the case of CPUC programmatic activities, to apply for, additional revenue requirements beyond base rates from customers for certain operating and capital-related costs (depreciation, taxes and return on rate base), including for:

▪ costs to purchase natural gas and electricity

▪ costs associated with administering public purpose, demand response, environmental compliance, and customer energy efficiency programs

▪ programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation

▪ costs associated with third-party liability insurance premiums

Authorized costs are recovered as the commodity or service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded in a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met when the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may require regulatory review procedures before authorizing recovery or refund of amounts accumulated for authorized programs, including reviews of costs for reasonableness, and may impose limitations on a program’s total cost or revenue requirement. These procedures and requirements could result in delays or disallowances of recovery from customers.

Sempra Texas Utilities

Rates and Cost Recovery

Oncor’s and Sharyland Utilities’ rates are each regulated at the state level by the PUCT and, in the case of Oncor, at the city level by certain cities, and are subject to regulatory rate-setting processes and earnings oversight. This regulatory treatment does not provide assurance as to achievement of earnings levels or recovery of actual costs. Instead, rates are based on an analysis of each utility’s costs and capital structure in a designated test year, as reviewed and approved in regulatory proceedings. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. However, there is no assurance that the PUCT will judge all of the Texas utilities’ costs to have been prudently incurred and therefore fully recoverable. The approved levels and timing of recovery could differ significantly from requested levels and timing. There can also be no assurance that the PUCT will approve any other items requested in any rate proceeding or that the regulatory process in which rates are determined will result in rates that produce full recovery of the Texas utilities’ actual post-test year costs and/or the full return on invested capital allowed by the PUCT, particularly during periods of increased capital spending, high inflation or increases in interest rates resulting in increased costs relative to the utility’s most recent base rate review.

PUCT rules provide that a transmission and distribution utility must file a comprehensive base rate review within four years of the last order in its most recent comprehensive rate proceeding unless an extension is approved by the PUCT. However, the PUCT or any city retaining original jurisdiction over rates may direct the utility to file a base rate review, or the utility may voluntarily file a base rate review, any time prior to that deadline.

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In addition, PUCT rules allow for interim rate adjustments known as capital trackers that allow Texas electric utilities to recover, subject to reconciliation, the cost of certain investments before a comprehensive base rate review. As a result of Texas legislation signed into law in 2025 establishing the UTM, qualifying electric utilities like Oncor can apply for a single interim rate update annually through 2035 for cost recovery of certain transmission and distribution capital investments, as an alternative to separate distribution cost recovery factor and transmission cost of service capital tracker filings. All investments included in a capital tracker update filing are ultimately subject to prudence review by the PUCT in the next base rate review after such assets are put into service. Oncor anticipates filing its initial UTM application on or after March 16, 2026 for eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, and as a result, Oncor has recorded regulatory assets for recoverable costs associated with those investments and recognized a corresponding amount in other regulated revenues. We discuss Oncor’s anticipated first UTM filing in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Texas Utilities.”

Capital Structure and Return on Equity

In April 2023, the PUCT issued a final order in a comprehensive base rate review that set Oncor’s authorized regulatory capital structure ratio at 57.5% debt to 42.5% equity, its authorized ROE at 9.70%, and its authorized cost of debt at 4.39%. We discuss Oncor’s most recent comprehensive base rate proceeding and a settlement request that, with PUCT approval, would change Oncor’s capital structure, authorized ROE and authorized cost of debt in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Texas Utilities.”

In November 2025, the PUCT approved Sharyland Utilities’ total revenue requirement 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%.

Sempra Infrastructure

Ecogas’ revenues are derived from service and distribution fees charged to its customers in Mexican pesos. The price Ecogas pays to purchase natural gas, which is based on international price indices, is passed through directly to its customers. The service and distribution fees charged by Ecogas are regulated by the CNE, which performs a review of rates every five years and monitors prices charged to end-users. Ecogas’ rate case for 2021 through 2025 was approved by the CNE in December 2023. The tariffs operate under a return-on-asset-base model. In the annual tariff adjustment, rates are adjusted to account for inflation or fluctuations in exchange rates, and inflation indexing includes separate U.S. and Mexican cost components so that U.S. costs can be included in the final distribution rates.

ENVIRONMENTAL MATTERS

We discuss environmental issues affecting us in Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.” You should read the following additional information in conjunction with those discussions.

Hazardous Substances

The CPUC’s Hazardous Waste Collaborative mechanism allows California’s IOUs to recover hazardous waste cleanup costs for certain sites, including those related to certain Superfund sites. For sites that are covered by this mechanism, SDG&E and SoCalGas are permitted to recover in rates 90% of hazardous waste cleanup costs and related third-party litigation costs, and 70% of related insurance-litigation expenses. In addition, SDG&E and SoCalGas can retain a percentage of any recoveries from insurance carriers and other third parties to offset the cleanup and associated litigation costs not recovered in rates.

We record estimated liabilities for environmental remediation when amounts are probable and estimable. In addition, we record amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism as regulatory assets.

Air Quality and GHG Emissions

The natural gas and electric industries are subject to increasingly stringent air quality and GHG emissions standards. Our operations in California are subject to the requirements described below, and our operations in other locations may be subject to laws and regulations in applicable jurisdictions governing similar topics, including GHG emissions reduction objectives, GHG emissions reporting standards and carbon taxes in certain states. AB 32, the California Global Warming Solutions Act of 2006, assigns responsibility to CARB for monitoring and establishing policies for reducing GHG emissions. The law requires CARB to develop and adopt a comprehensive plan for achieving real, quantifiable, and cost-effective GHG emissions reductions, including a statewide GHG emissions cap, mandatory reporting rules, and regulatory and market mechanisms to achieve reductions of GHG emissions. CARB is a department within the California Environmental Protection Agency, an organization that reports directly to the Governor’s Office. SI Partners is also subject to the rules and regulations of CARB.

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California requires certain electric retail sellers, including SDG&E, to deliver a significant percentage of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by the CPUC and the CEC, are generally known as the RPS Program. SB 100 (enacted in 2018) and SB 1020 (enacted in 2022) require each California electric utility, including SDG&E, to procure at least 50% of its annual retail electricity delivered from renewable energy or zero-carbon sources by the end of 2026, 60% by the end of 2030, 90% by the end of 2035, 95% by the end of 2040, and 100% by the end of 2045. SDG&E expects to be in compliance with these RPS program requirements. State law also requires California’s retail electricity supply to be met with a mix of RPS Program-eligible and zero-carbon sources by 2045 without increasing carbon emissions elsewhere in the western grid or allowing resource shuffling, and instructs the CPUC, CEC, CARB and other state agencies to incorporate this requirement into all relevant planning. In addition, AB 1279 (enacted in 2022) requires the State of California to achieve net-zero GHG emissions no later than 2045, and to achieve and maintain net negative GHG emissions thereafter. AB 1279 also directs CARB to address this goal in future scoping plans, which affect major sectors of California’s economy, including energy utilities, transportation, agriculture, construction and manufacturing. Other state climate initiatives in line with this statewide goal include executive orders requiring sales of all passenger vehicles, including SDG&E’s and SoCalGas’ light-duty fleet vehicles, to be zero-emission by 2035. In 2025, the U.S. Administration rescinded the Clean Air Act waiver on which California’s zero-emission vehicle mandate is based, rendering the mandate unenforceable pending the resolution of related litigation.

California has implemented a biomethane procurement program, whereby IOUs providing gas service in California will procure a portion of the natural gas they deliver from CPUC-approved sources of biomethane. The program establishes a Renewable Gas Standard for biomethane procurement that will be phased in through the end of 2030. The CPUC is currently reviewing IOUs’ renewable gas procurement plans and related public comments and considering potential enhancements to the program structure to increase market competition and reduce entry barriers for biomethane producers.

SDG&E and SoCalGas generally recover the costs to comply with these standards in rates. We discuss GHG emissions standards, allowances and obligations and RECs in Note 1 of the Notes to Consolidated Financial Statements.

The South Coast Air Quality Management District is the air pollution control agency responsible for regulating stationary sources of air pollution in the South Coast Air Basin in Southern California. The district’s territory covers all of Orange County and the urban portions of Los Angeles, San Bernardino and Riverside counties.

Sempra aims to have net-zero scope 1 and 2 GHG emissions by 2050 and has an interim aim of 50% scope 1 and 2 GHG emissions reductions by 2035 (this interim target is relative to a 2019 baseline, applies to Sempra California’s operations and Sempra Infrastructure’s Mexico (non-LNG) operations, and may be subject to further revision if Sempra’s planned sale of a portion of its equity interest in SI Partners is completed). Sempra and its subsidiaries also continue to advocate for programs and initiatives that support regulatory, consumer and market demand for lower- and zero-carbon energy. Additionally, although SDG&E and SoCalGas continue to align with California’s goal to achieve net-zero GHG emissions by 2045, their respective abilities to achieve their net-zero aspirations, as well as Sempra’s ability to achieve its 2035 and 2050 aims and meet the demand for lower-carbon and reliable energy in California and elsewhere, will depend on the development, commercialization and regulatory acceptance of affordable, alternative and lower-carbon energy sources, including cleaner fuels, among other factors. For a discussion of risks and uncertainties related to our net-zero and other climate aims, see “Part I – Item 1A. Risk Factors.”

With respect to our net-zero aims, even in a state of “net-zero,” GHG emissions may still be generated, but innovation and continued development of new technology and solutions could allow an equal amount of carbon dioxide or its equivalent to be removed from the atmosphere, resulting in a zero net increase in emissions. In addition, for purposes of these net-zero aims, we expect that achievement of net-zero GHG emissions will be determined based on operations at the time the applicable goal is to be reached, and GHG emissions will be calculated according to widely accepted emissions reporting guidelines or mandates at that time. Our net-zero aim does not include Oncor, which sets its own goals due to certain ring-fencing measures that limit Sempra’s ability to direct the management, policies and operations of Oncor.

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OTHER MATTERS

Information About Our Executive Officers

INFORMATION ABOUT EXECUTIVE OFFICERS — Name	Age (1)	Positions held over last five years	Time in position
Sempra:
Jeffrey W. Martin	64	President	March 2020 to present
		Chairman	December 2018 to present
		Chief Executive Officer	May 2018 to present
Karen L. Sedgwick	59	Executive Vice President and Chief Financial Officer	January 2024 to present
		Chief Administrative Officer	December 2021 to December 2023
		Chief Human Resources Officer	September 2020 to December 2023
		Senior Vice President	September 2020 to December 2021
Justin C. Bird	55	Executive Vice President	January 2024 to present
		Chief Executive Officer, Sempra Infrastructure	November 2021 to present
		Chief Executive Officer, Sempra LNG	April 2020 to November 2021
Caroline A. Winn	62	Executive Vice President	July 2025 to present
		Chief Executive Officer, SDG&E	August 2020 to July 2025
Diana L. Day	61	Corporate Secretary	May 2025 to present
		Chief Legal Counsel	January 2024 to present
		Deputy General Counsel	October 2022 to January 2024
		Senior Vice President, SDG&E	August 2020 to October 2022
		Chief Risk Officer, SDG&E	August 2019 to October 2022
		General Counsel, SDG&E	January 2019 to October 2022
Lisa M. Larroque Alexander	52	Senior Vice President, Human Resources	January 2025 to present
		Senior Vice President, Corporate Affairs	April 2020 to present
Dyan Z. Wold	50	Vice President, Controller and Chief Accounting Officer	July 2025 to present
		Chief Accounting Officer, Sempra Infrastructure	September 2023 to July 2025
		Vice President and Controller, Sempra Infrastructure	December 2021 to July 2025
		Controller, Sempra LNG	November 2019 to December 2021

(1) Ages are as of February 26, 2026.

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INFORMATION ABOUT EXECUTIVE OFFICERS — Name	Age (1)	Positions held over last five years	Time in position
SDG&E:
Scott B. Crider	51	President	February 2025 to present
		Senior Vice President, External and Operations Support	June 2022 to January 2025
		Senior Vice President, Customer Services and External Affairs	June 2021 to June 2022
		Chief Customer Officer	September 2020 to June 2021
Valerie A. Bille	47	Chief Financial Officer and Senior Vice President, SDG&E and SoCalGas	January 2026 to present
		Chief Financial Officer and Senior Vice President	March 2025 to January 2026
		Controller, Chief Accounting Officer and Treasurer	August 2020 to January 2026
		Vice President	August 2020 to March 2025
Kevin C. Geraghty	60	Chief Operating Officer	June 2022 to present
		Chief Safety Officer	January 2021 to present
		Senior Vice President, Electric Operations	July 2020 to June 2022
Robert J. Borthwick	61	Senior Vice President and General Counsel, SDG&E and SoCalGas	January 2026 to present
		Chief Risk Officer, Sempra	May 2023 to January 2026
		Deputy General Counsel, Sempra	March 2019 to May 2023
Maritza Mekitarian	51	Vice President, Controller and Chief Accounting Officer	January 2026 to present
		Assistant Treasurer	March 2024 to present
		Assistant Controller	January 2024 to January 2026
		Director of Financial Planning	September 2021 to January 2024
		Financial and Strategic Planning Manager	April 2021 to September 2021
		Financial Planning Manager	September 2017 to April 2021

(1) Ages are as of February 26, 2026.

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INFORMATION ABOUT EXECUTIVE OFFICERS — Name	Age (1)	Positions held over last five years	Time in position
SoCalGas:
Maryam S. Brown	50	Chief Executive Officer	January 2025 to present
		President	March 2019 to present
Valerie A. Bille	47	Chief Financial Officer and Senior Vice President, SoCalGas and SDG&E	January 2026 to present
		Chief Financial Officer and Senior Vice President, SDG&E	March 2025 to January 2026
		Controller, Chief Accounting Officer and Treasurer, SDG&E	August 2020 to January 2026
		Vice President, SDG&E	August 2020 to March 2025
Rodger R. Schwecke	65	Chief Operating Officer	March 2025 to present
		Senior Vice President and Chief Infrastructure Officer	November 2020 to March 2025
Robert J. Borthwick	61	Senior Vice President and General Counsel, SoCalGas and SDG&E	January 2026 to present
		Chief Risk Officer, Sempra	May 2023 to January 2026
		Deputy General Counsel, Sempra	March 2019 to May 2023
Erin M. Smith	46	Senior Vice President, External Affairs and Chief Talent Officer	June 2025 to present
		Senior Vice President, Chief Talent, Culture, and Operations Support Officer	January 2023 to June 2025
		Chief Talent and Culture Officer	December 2020 to January 2023
Sara P. Mijares	44	Chief Accounting Officer	May 2024 to present
		Assistant Treasurer	April 2023 to present
		Vice President and Controller	July 2022 to present
		Vice President of Accounting and Finance	August 2021 to July 2022
		Assistant Controller	June 2020 to July 2022

(1) Ages are as of February 26, 2026 .

Human Capital

Our ability to advance our mission to build America’s leading utility growth business by investing in U.S. utilities, modernizing critical infrastructure and deploying next-generation technology at scale largely depends on the safety, engagement, and responsible actions of our employees.

Safety is foundational at Sempra and its subsidiaries. We strive to foster a strong safety culture and reinforce this culture through various policies, programs and systems designed to mitigate the occurrence and extent of safety incidents, including training programs, benchmarking, review and analysis of safety trends, internal compliance assessments and audits, and sharing lessons learned from safety incidents and near misses across our businesses. Our businesses also engage in safety-related scenario planning and simulation, develop and implement operational contingency plans, and review safety plans and procedures with work crews regularly. We also participate in emergency planning and preparedness in the communities we serve and train critical employees in emergency management and response each year. The SST Committee assists the Sempra board of directors in overseeing the company’s oversight programs and performance related to safety, and our executives’ annual incentive compensation is based in part on safety metrics established by the Compensation and Talent Development Committee of the board.

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In addition, we strive to create a high-performing, inclusive and supportive workplace where employees of all backgrounds and experiences feel valued and respected. We invest in recruiting, developing and retaining high-performing employees who represent the communities we serve, and we provide a range of programs for employees, including internal and external mentoring and leadership training and workshops, employee resource groups, and a benefits package including wellness benefits and a tuition reimbursement program. We also invest in internal communications programs, including in-person and virtual learning and networking opportunities as well as regular executive communications to employees on topics of interest. In addition, we offer a variety of employee community service opportunities, and at our U.S. operations, we support employees’ personal volunteering and charitable giving through the charitable matching program of Sempra Foundation, which was founded and is solely funded by Sempra. Employees participate in annual ethics and compliance training, which includes a review of Sempra’s Code of Business Conduct as well as information about resources such as Sempra’s ethics and compliance helpline. We measure culture and employee engagement through a variety of channels including pulse surveys, suggestion boxes and a biannual engagement survey administered by a third party.

We continue to advance our workforce modernization efforts to enhance operational performance. Key elements include retaining high performing talent, streamlining organizational structures, and aligning our workforce with evolving business needs. We intend to shift our workforce toward higher-value roles through talent reskilling and upskilling, redeployment strategies, and driving adoption of artificial intelligence and modern technologies. As we implement these initiatives, we expect certain roles to be consolidated or modified over time. While these actions may result in changes in overall headcount over time, the primary focus is on building a more agile, skilled, and technology-enabled workforce capable of supporting the company’s long-term strategy and value for customers.

The table below shows the number of employees for each of the Registrants at December 31, 2025, as well as the number of those employees represented by labor unions under various collective bargaining agreements that generally cover wages, benefits, working conditions and other terms and conditions of employment. We did not experience any major work stoppages in 2025, and we maintain constructive relations with our labor unions.

NUMBER OF EMPLOYEES	Number of employees	Number of employees covered under collective bargaining agreements	Number of employees covered under collective bargaining agreements expiring within one year
Sempra (1)	15,938	6,131	1,603
SDG&E	4,448	1,599	1,599
SoCalGas	8,065	4,528	—

(1) Excludes employees of equity method investees. Includes 3,048 employees, four of whom are covered under collective bargaining agreements, that are included in the disposal group that is classified as held for sale.

COMPANY WEBSITES

The Registrants’ website addresses are:

▪ Sempra – www.sempra.com

▪ SDG&E – www.sdge.com

▪ SoCalGas – www.socalgas.com

We make available free of charge on the Sempra website, and for SDG&E and SoCalGas, via a hyperlink on their websites, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC.

The references to our websites in this report are not active hyperlinks and the information contained on, or that can be accessed through, the websites of Sempra, SDG&E and SoCalGas or any other website referenced herein is not a part of or incorporated by reference in this report or any other document that we file with or furnish to the SEC.

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ITEM 1A. RISK FACTORS

When evaluating our company and its businesses and any investment in our or their securities, you should carefully consider the following risk factors and all other information contained in this report and the other documents we file with the SEC (including those filed subsequent to this report). We also may be materially harmed by risks and uncertainties not currently known to us or that we currently consider immaterial. If any of these risks occur, our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected, our actual results could differ materially from those expressed or implied in our forward-looking statements, and the trading prices of our securities and those of our businesses could decline. These risk factors are not prioritized in order of importance or materiality, and they should be read together with the other information in this report, including in the Consolidated Financial Statements and in “Part II – Item 7. MD&A.”

RISKS RELATED TO SEMPRA

Operational and Structural Risks

Sempra’s ability to pay dividends and meet its obligations largely depends on the performance of its subsidiaries and entities accounted for as equity method investments.

We are a holding company and substantially all the assets that produce our earnings are owned by our subsidiaries or equity method investees, which are entities we do not control. SI Partners, which primarily constitutes our Sempra Infrastructure reportable segment, will be accounted for as an equity method investment subject to closing the planned sale of 45% of our equity interest, which we expect to occur in the second or third quarter of 2026. Our ability to pay dividends and meet our debt and other obligations largely depends on distributions from our subsidiaries and equity method investees, which in turn depend on their ability to execute their business strategies and generate cash flows in excess of their own expenditures, dividend payments to third-party owners (if any) and debt and other obligations. In addition, our subsidiaries and entities accounted for as equity method investments are all separate and distinct legal entities that are not obligated to pay dividends or make loans or distributions to us and could be precluded from doing so by legislation, regulation or contractual restrictions, in times of financial distress or in other circumstances. Any inability to access capital from our subsidiaries and equity method investees could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Sempra’s rights to the assets of its subsidiaries and equity method investees are structurally subordinated to the claims of each entity’s trade and other creditors. When Sempra is a creditor of any such entity, its rights as a creditor are effectively subordinated to any security interest in the entity’s assets and any indebtedness of the entity senior to that held by Sempra. In addition, Sempra may elect to make additional capital contributions to its subsidiaries or equity method investments, which are not required to be repaid and are structurally subordinated to claims by creditors of the applicable subsidiary.

Our investments in businesses we do not control expose us to risks.

We have investments in businesses we do not control or manage or in which we share control, including Oncor and SI Partners (subject to closing our planned sale of a portion of our equity interest in SI Partners). We discuss these investments in Note 5 of the Notes to Consolidated Financial Statements. In some cases, we engage in arrangements with or for these businesses that could expose us to risks in addition to our investment, including guarantees, indemnities and loans. For businesses we do not control, we are subject to the decisions of others, which may be adverse to our interests. When we share control of a business with other owners, any disagreements among the owners about strategy, financial, operational, transactional or other important matters could hinder the business from moving forward with key initiatives or taking other actions and could negatively affect the relationships among the owners and the efficient functioning of the business. In addition, irrespective of whether we control these businesses, we would be responsible for certain liabilities or losses related to these businesses, may be subject to disproportional funding obligations for certain matters or priority distributions in favor of other partners or members, and may be required or elect to make additional capital contributions to these businesses. Any such circumstance could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

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Our business could be negatively affected by activist shareholders.

We have been and may in the future be subject to activist shareholder attention, including proxy solicitations, shareholder proposals or other attempts to effect changes in or assert influence on our board of directors and management. In connection with these efforts, activist shareholders could seek to acquire our capital stock, despite the provisions of our governing documents that may delay, deter or prevent a change of control or other takeover of our company even if our shareholders might prefer such a change of control. At certain ownership levels, these common stock acquisitions could threaten our ability to use some or all of our NOL or tax credit carryforwards if our corporation experiences an “ownership change” under applicable tax rules. Responding to activist shareholders can be costly and time-consuming and requires time and attention from our board of directors and management, diverting their attention from our business strategies.

Any actual or perceived instability in our future direction, inability to execute our strategies, or changes in our board of directors or management team arising from activist shareholder campaigns could be exploited by our competitors and/or other activist shareholders, result in the loss of business opportunities, and make it more difficult to pursue our strategic initiatives or attract and retain qualified personnel and business partners, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Financial and Capital Stock-Related Risks

Successfully executing our five-year capital expenditures plan is subject to risks.

The execution of our five-year capital expenditures plan may not be completed in accordance with current expectations or produce the desired results. Factors that have historically impacted and could continue to impact the amount, timing and types of capital expenditures we make include the cost and availability of financing; economic and market conditions; regulatory decisions; changes in tax law; business opportunities providing desirable rates of return; forecasts related to safety, reliability and load growth, gas system planning and transportation electrification; safety and environmental requirements and climate-related policies; and cooperation of third parties, including customers, partners, suppliers, lenders and others. We discuss these and other relevant factors with respect to each of our businesses below. We aim to finance our five-year capital expenditures plan in a manner that will maintain our investment-grade credit ratings and capital structure, but we may not be able to do so. Any failure to successfully execute our capital expenditures plan could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Settlement provisions contained in forward sale agreements in connection with our ATM program subject us to certain risks.

In November 2024, Sempra established an ATM program, which we discuss in Note 13 of the Notes to Consolidated Financial Statements. We are permitted to sell shares of our common stock in the ATM program pursuant to forward sale agreements, including 4,996,591 shares under existing forward sale agreements that remain subject to future settlement as of February 26, 2026. These forward sale agreements grant each counterparty (forward purchaser) the right to accelerate its forward sale agreement (or, in certain cases, the portion affected by the relevant event) and require us to physically settle the forward sale agreement upon the occurrence of certain events, some of which are not within our control.

A forward purchaser’s decision to exercise this right and require us to physically settle the relevant shares will be made irrespective of our interests, including our capital and other needs. In such cases, we could be required to issue and deliver shares of our common stock under the terms of the physical settlement, which would result in dilution to our EPS and may adversely affect the market price of our common stock and any series of preferred stock we may issue in the future.

The forward price that we expect to receive upon physical settlement of a forward sale agreement will be subject to adjustment on a daily basis based on a floating interest rate factor. If the specified daily rate is less than the applicable spread on any day, this will result in a daily reduction of the forward price. In addition, the forward price will be subject to decrease on certain dates specified in the relevant forward sale agreement by the amount per share of quarterly dividends we expect to declare on our common stock during the term of such forward sale agreement.

We generally have the right, in lieu of physical settlement of any forward sale agreement, to elect cash or net share settlement in respect of any or all of the shares of our common stock subject to each forward sale agreement. If we elect to cash or net share settle all or any part of any forward sale agreement, we would expect to issue a substantially lower number of shares than if we settled by physical delivery, but would not receive the cash for the shares that would have otherwise been issued if we settled the entire forward sale agreement by physical delivery and, as a result, would not derive the same liquidity or credit metrics benefits.

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If the price of our common stock at which purchases are made by a forward purchaser (or its affiliate) exceeds the applicable forward price, we will pay the forward purchaser an amount in cash equal to such difference (if we elect to cash settle) or we will deliver to the forward purchaser a number of shares of our common stock having a market value equal to such difference (if we elect to net share settle). Any such difference could be significant and could require us to pay a significant amount of cash or deliver a significant number of shares of our common stock to a forward purchaser.

The purchase of shares of our common stock by a forward purchaser (or its affiliate) to unwind the forward purchaser’s hedge position could cause the price of our common stock to increase above the price that would have prevailed in the absence of those purchases (or prevent a decrease in such price), thereby increasing the amount of cash (in the case of cash settlement) or the number of shares (in the case of net share settlement) that we would owe the forward purchaser upon settlement of the applicable forward sale agreement or decreasing the amount of cash (in the case of cash settlement) or the number of shares (in the case of net share settlement) that the forward purchaser would owe us upon settlement of the applicable forward sale agreement.

The economic interest, voting rights and market value of our outstanding common stock may be adversely affected by any additional equity securities we may issue.

At February 19, 2026, we had 653,284,140 shares of our common stock outstanding. Our businesses have substantial capital needs, and we may seek to raise capital by issuing additional equity, including in our ATM program, or convertible debt securities in potentially significant amounts depending in part on the prevailing market price of our common stock, which at times experiences substantial volatility. Any future issuance of equity or convertible debt securities may materially dilute the voting rights and economic interests of holders of our outstanding common stock and materially adversely affect the trading price of our common stock.

RISKS RELATED TO ALL SEMPRA BUSINESSES

Operational Risks

Our infrastructure and its supporting systems subject us to risks.

Our facilities and the systems that interconnect and/or manage them are subject to risks of, among other things:

▪ equipment or process failures due to aging infrastructure or otherwise

▪ human error

▪ loss or outage of a key technology platform or system

▪ shortages of or delays in obtaining equipment, materials, supplies, commodities or labor, which have been and may continue to be exacerbated by supply chain and gas transportation capacity constraints, tight labor markets, and cost increases due to inflation, tariffs or otherwise, that may not be recoverable in a timely manner or at all

▪ operational restrictions resulting from governmental interventions, including environmental requirements, or permitting delays

▪ inability to enter into, maintain, extend or replace long-term supply or transportation contracts

▪ performance below expected levels

Our businesses undertake capital investment projects to construct, replace, operate, maintain and upgrade facilities and systems, but such projects may not be completed or effective at managing these risks and involve significant costs that may not be recoverable in a timely manner or at all. We often rely on third parties, including contractors, to perform work related to these projects and other activities, which may subject us to liability for safety issues or lower standards of work quality. Because some of our facilities are interconnected with those of third parties, including customer-side-of-meter facilities, natural gas pipelines and power generation facilities, the operation of our facilities could also be materially adversely affected by these or similar risks to such third-party systems, which may be unanticipated or uncontrollable by us.

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Additional risks associated with our facilities and systems, which may be beyond our control, include:

▪ failure to meet customer demand for electricity and/or natural gas, including electric or gas outages

▪ gas surges into homes or other properties

▪ release of hazardous or toxic substances, including gas leaks

▪ public contact with energized equipment

▪ worksite accidents and other incidents impacting the health, safety or security of employees, contractors, the public or our infrastructure

▪ failure to respond effectively to catastrophic events

▪ severe weather, which we discuss further in the following risk factor

The occurrence of any of these events could affect supply and demand for electricity, natural gas or other forms of energy, cause unplanned outages, damage our assets and/or operations or those of third parties on which our businesses rely, damage property owned by customers or others, and cause personal injury or death, such as recent contractor fatalities on certain Sempra Infrastructure projects under construction. In addition, if we are unable to defend and retain title to the properties we own or obtain or retain rights to construct and operate on the properties we do not own in a timely manner, on reasonable terms or at all, we could lose our rights to occupy and use these properties and related facilities, which could prevent, limit or delay existing or proposed operations or projects, increase our costs, and result in breaches of permits or contracts and related impairments, fines or penalties. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We face risks related to severe weather, natural disasters, physical attacks and other similar events.

Our employees and contractors may be harmed and our facilities and infrastructure may be damaged as a result of physical risks, such as extreme temperatures, storms, droughts and other severe weather; natural disasters, including wildfires, land movement, earthquakes, and solar flares; climate-related conditions, including sea level rise and coastal erosion; accidents, including explosions, excavation damage to pipelines and automobile accidents; or acts of terrorism, war or criminality, including physical attacks and unauthorized drone incursions. Because we are in the business of using, storing, transporting and disposing of highly flammable, explosive and radioactive materials and operating highly energized equipment, the risks such incidents pose to our facilities and infrastructure, as well as to the surrounding communities for which we could be liable, are substantially greater than the potential risks to a typical business. Efforts to mitigate these risks could decrease revenues and earnings and/or increase costs, which for our regulated utilities may not be recoverable in rates on a timely basis or at all, including expenditures on infrastructure maintenance and resiliency, physical and employee safety and security, emergency preparedness, wildfire mitigation and grid modernization.

Such incidents, which have occurred from time to time, could result in operational disruptions, electric or gas outages, property damage, personal injury or death and could cause secondary incidents that also may have these or other negative effects, such as fires; leaks or spills of gases, natural gas odorant or radioactive material; damage to natural resources; or other impacts to affected communities. Any of these occurrences could decrease revenues and earnings and/or increase costs, including restoration expenses, amounts associated with claims against us, and regulatory fines, penalties and disallowances. In some cases, we may be liable for damages even though we are not at fault, such as when the doctrine of inverse condemnation applies, which we discuss below under “Risks Related to Sempra California – Operational Risks.” Insurance coverage for these costs may continue to increase or become prohibitively expensive, be disputed by insurers, or become unavailable for certain of these risks or at adequate levels or in certain geographic locations, and any insurance proceeds may be insufficient to cover our losses or liabilities due to limitations, exclusions, high deductibles, failure to comply with procedural requirements or other factors. We discuss the risks related to insurance for wildfire liabilities below under “Risks Related to Sempra California – Operational Risks.” Such incidents that do not directly affect our facilities may impact our business partners, supply chains and transportation and communication channels, which could negatively affect our ability to operate. Moreover, weather-related incidents have become more prevalent, unpredictable and severe due to climate change or other factors. As a result, these incidents could have a greater impact on our businesses than currently anticipated and, for our regulated utilities, rates may not be adequately or timely adjusted to reflect any such increased impact. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

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We face evolving cybersecurity, technology resiliency and data security and governance risks, including with respect to increasing use of artificial intelligence.

Cybersecurity and Technology Resiliency

Our significant reliance on complex technologies and increasing deployment of new technologies, such as advanced forms of automation and artificial intelligence and virtualization of many business activities, represent large-scale opportunities for attacks on or failures of our information systems, the energy grid and our other infrastructure. Our digitalization and grid modernization efforts, including the networking of operational technology assets such as substations, continue to increase the potential vulnerabilities and points of failure in our systems. We are also at risk of attacks on, vulnerabilities in or other failures of technologies and systems used by certain third-party vendors, regulators and/or ISOs, including third-party systems that are integral to our electric utilities’ operations in their respective ISO markets. Viruses, ransomware, malware and other forms of cyber-attacks targeting utility systems and other energy infrastructure continue to increase in sophistication, magnitude and frequency, may not be recognized until launched against a target and may further escalate during periods of heightened geopolitical tensions. Adversaries increasingly use artificial intelligence to develop new hacking tools, exploit vulnerabilities, obscure malicious activities and increase the difficulty of detecting threats. Accordingly, we may be unable to anticipate these techniques or to implement adequate preventative measures, making it impossible to eliminate these risks.

Although we make significant investments in risk management, technology resiliency and cybersecurity measures for the protection of our systems and data, these measures could be insufficient or otherwise fail, particularly against unknown software flaws, insider threats, attacks involving sophisticated adversaries, including nation-state actors, or outages involving key technology vendors and systems. The costs and operational consequences of implementing, maintaining and enhancing these measures are significant and expected to increase to address evolving cyber risks. We increasingly rely on third-party vendors to deploy new technologies and host, maintain and update our systems (including providing security updates), and these third parties may not have adequate risk management, technology resiliency and cybersecurity measures with respect to their systems or may fail to timely provide and install software updates. Certain of our key externally hosted systems depend on global cloud service providers as well as their respective vendors, some of which have experienced significant system failures and outages in the past.

Although we have not experienced a material breach of our information systems or data, we and some of our vendors have been and will likely continue to be subject to breaches of and attempts to gain unauthorized access to our systems or data or efforts to otherwise disrupt our operations. Any actual or perceived noncompliance with applicable legal or regulatory requirements or any incidents impacting our or our vendors’ systems, the integrity of our data or assets or the energy grid could result in disruptions to our business operations; legal or regulatory compliance failures; inability to produce accurate and timely financial statements; energy delivery failures; financial and reputational loss; litigation; and fines or penalties, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. Although we currently maintain cyber liability insurance, this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover the costs associated with a cybersecurity incident, and this insurance may not continue to be available on acceptable terms.

Data Security and Governance

Our businesses collect, process and retain large volumes of data, including personal, sensitive and confidential information from customers, employees, contractors and other third parties. SDG&E and SoCalGas are increasingly required to disclose large amounts of data (including customer personal information and energy use data) to support state energy initiatives, increasing the risks of inadvertent disclosure or unauthorized access of sensitive information. Our businesses operating in California are subject to the California Consumer Privacy Act, which requires companies that collect information about California residents to, among other things, disclose their data collection, use and sharing practices; allow consumers to opt out of certain data sharing with third parties; and assume liability for unauthorized disclosure of certain highly sensitive personal information. Certain of our other businesses may operate in jurisdictions with similar laws.

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In addition to security and privacy risks related to data, we face challenges related to data governance, including the need to manage our data with the aim to meet regulatory requirements and create a foundation for the use of artificial intelligence tools. Our current and potential future uses of such tools (and use by our vendors and agents) may expose us to heightened security and privacy risks as well as operational, legal, and reputational risks. Data produced by or contained in artificial intelligence tools may contain inaccuracies, and our investments in such technologies and related organizational changes may not deliver the expected benefits, which could result in operational disruptions, inefficiencies, unexpected costs and regulatory disallowances. Beginning in January 2027, our businesses that are subject to the California Consumer Privacy Act will also be subject to new regulations related to, among other things, the use of artificial intelligence tools to automate certain decisions. These regulations may limit some potential applications of such technologies, particularly with respect to previously collected personal data. The regulations require companies to disclose any covered use of such technologies and how the relevant decisions will be made and to allow consumers to opt out of such use, subject to limited exceptions. The regulations also require companies to conduct risk assessments before initiating certain data processing activities, disclose information about these assessments to the California Privacy Protection Agency, conduct an annual cybersecurity audit and submit a written compliance certification to the agency.

We will continue to incur costs related to our deployment of artificial intelligence and compliance with applicable laws and regulations governing data collection, processing and retention. Any actual or perceived noncompliance could result in reputational harm, enforcement actions or other proceedings and fines or penalties, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Conditions in global markets, including the impact of enacted and proposed 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. SI Partners 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 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. In particular, the U.S. Administration has imposed new tariffs on Mexico and Canada, and additional tariffs have been threatened and these and other changes, including in connection with the planned joint review of the U.S.-Mexico-Canada Agreement in 2026, may become effective in the near term. 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. The U.S. Administration also is considering new tariffs on additional imported products, including power grid equipment, large-scale batteries and plastic piping. These threatened and imposed 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 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. The Mexican government has announced it may implement retaliatory tariffs in response to the U.S. Administration’s tariffs, and other foreign governments may also impose trade measures, including retaliatory 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.

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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.

We actively seek opportunities in the market through acquisitions, partnerships, JVs and divestitures, and we may be unable to complete or realize the anticipated benefits from such transactions.

We diligently analyze the financial viability of acquisitions, divestitures, partnerships and JVs we pursue. However, our diligence may prove to be insufficient and there could be latent or unforeseen defects. In addition, we may not realize the anticipated benefits from future transactions for various reasons, including difficulties integrating or separating operations and personnel effectively or in a timely manner, higher or unexpected transaction or operating costs, unknown liabilities, and fluctuations in markets. We discuss these and other risks related to our planned sale of a portion of our equity interest in SI Partners below under “Risks Related to Sempra Infrastructure – Risks Related to Planned Sales of Certain Assets and Businesses.” Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We face risks related to activities and projects intended to advance new energy-related technologies.

We participate in research, development and demonstration projects and other activities designed to develop and implement new technologies in the energy space, including those related to hydrogen, liquefaction, energy storage, microgrids, carbon sequestration, wildfire mitigation and grid modernization. These activities and projects involve significant employee time, as well as substantial capital resources, and we may be required to impair or write off amounts we have invested if any project is unsuccessful or its book value is less than the amount of our investment. As has happened in the past, regulators may deny rate recovery to our regulated utilities for some of these investments. We have sought and continue to seek a variety of related federal and state funding opportunities for these activities and projects, such as government incentives and subsidies under the IRA, some of which were revised by the OBBBA. These efforts can involve significant compliance requirements and have not always been successful in securing funding on acceptable terms or at all. In addition, the timing to complete these activities and projects is inherently uncertain and may require significantly more resources than we initially anticipate. Moreover, many of these technologies are in the early stage of development and may not prove economically and technically feasible or be accepted by regulators, and the applicable activities and projects may not be completed. If any of these circumstances occur, we may not receive an adequate or any return on our investment, and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.

The operation of our facilities depends on good labor relations with our employees and our ability to attract and retain qualified personnel.

Our businesses depend on recruiting, developing and retaining qualified personnel. Several of our businesses have collective bargaining agreements with different labor unions, which are negotiated on a company-by-company basis. At December 31, 2025, employees covered under collective bargaining agreements were 38%, 36% and 56%, respectively, of Sempra’s, SDG&E’s and SoCalGas’ workforce (exclusive of equity method investees), of which the collective bargaining agreements covering 26%, 100% and 0%, respectively, of such employees expire within one year (the SDG&E agreements will expire in August 2026). Any prolonged negotiation or failure to reach an agreement on these labor contracts as they are up for renewal could result in work stoppages or other labor disruptions. Additionally, we have faced a shortage of experienced and qualified personnel in certain specialty operational positions and could experience disruptions from recruiting or retention challenges for personnel in those positions. Any labor disruption, negotiated wage or benefit increases or other challenges, whether due to union activities, employee turnover, labor shortages or otherwise, could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

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Our businesses depend on the performance of counterparties.

Our businesses depend on the performance of business partners, customers, suppliers, contractors, and other counterparties under contractual and other arrangements to provide, among other things, services, supplies, equipment or commodities. If they fail to perform their obligations in accordance with these arrangements or elect to exercise early termination rights, we may be unable to meet our obligations and may be required to secure alternative arrangements, if available, or honor our underlying commitments at then-current market prices, which may result in losses or delays or other operational disruptions. Any efforts to enforce the terms of these arrangements through legal or other means could involve significant time and costs and may not succeed. We may not be able to secure replacement agreements on favorable terms, in a timely manner or at all if any of these arrangements terminate. We often face counterparty credit risk with respect to customers, suppliers, and other counterparties and, although we perform credit analyses prior to extending credit or entering into transactions with such counterparties, we may not be able to collect the amounts owed to us. Volatility and disruptions in capital and credit markets could have a negative impact on our counterparties and their ability to meet their obligations. SI Partners also faces risks related to doing business with PEMEX and the CFE, which are Mexican state-owned enterprises, including their financial solvency and performance of their respective contractual obligations. Any delay or default in payment could result in our recording of a provision for expected credit losses on past due receivable balances and lower revenues, as was the case in 2024 and 2025 for a customer at SI Partners. The failure of any of our counterparties to perform their obligations could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Financial Risks

Our debt service obligations expose us to risks.

We have significant debt service obligations and an ongoing need for significant amounts of additional capital, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects by, among other things:

▪ making it more difficult and costly to service, pay or refinance debts as they come due, particularly when interest rates increase or economic or industry conditions are otherwise unfavorable

▪ limiting flexibility to pursue strategic opportunities or react to business developments or industry changes causing lenders to require materially adverse terms for new debt, such as restricting uses of proceeds, imposing liens on our assets and limiting our ability to incur additional debt, pay dividends, repurchase stock, or receive distributions from subsidiaries or equity method investees

The availability and cost of financing could be negatively affected by market and economic conditions and other factors.

Our businesses are capital-intensive, with significant and increasing capital spending expected in future periods. In general, we rely on long-term debt to fund a significant portion of our capital expenditures and to repay or refinance outstanding debt, and we rely on short-term debt to fund a significant portion of day-to-day operations. Certain of our businesses also rely on other funding sources, such as Sempra Infrastructure’s use of capital contributions from its owners and various forms of project financing, which may involve guarantees, indemnities or other arrangements that expose us to additional risks, such as potential losses upon the occurrence of events related to the development, construction, operation or financing of the applicable projects. Sempra has also raised and may continue to seek capital by issuing equity, including in our ATM program, or selling equity interests in our subsidiaries or investments.

External sources of capital may not be adequate or available on reasonable terms, in a timely manner or at all. Limitations on the availability of credit, increases in interest rates or credit spreads due to inflation or otherwise or other negative effects on the terms of any financing we pursue could cause us to fund operations and capital expenditures at a higher cost or fail to raise our targeted amount of funds, which could negatively impact our ability to meet contractual and other commitments, progress development projects, make non-safety related capital expenditures and effectively sustain operations. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

In addition to market and economic conditions, factors that can affect the availability and cost of capital include:

▪ adverse changes to laws and regulations

▪ for Sempra and SDG&E, risks related to California wildfires

▪ for Sempra, SDG&E and SoCalGas, any deterioration of or uncertainty in the political or regulatory environment for companies operating in California

▪ credit ratings downgrades

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Credit rating agencies may downgrade our credit ratings or place them on negative outlook, and our efforts to maintain these ratings could require additional equity securities issuances by Sempra or sales of equity interests in subsidiaries or projects in development.

Credit rating agencies routinely evaluate Sempra, SDG&E, SoCalGas, SI Partners and certain of our other businesses, whose ratings are based on many factors, including, as applicable, the ability to generate cash flows; terms and levels of indebtedness, including the credit rating agencies’ treatment of certain types of indebtedness, such as subordinated indebtedness which is given partial equity credit but carries a higher interest rate than comparable senior indebtedness; overall financial strength; specific transactions or events, such as share repurchases and significant litigation; the status of certain capital projects; and general economic and industry conditions. The Rating Agencies also have specified certain events that could lead to negative ratings actions, including, among others:

▪ weakening of certain financial measures or failure to meet certain financial credit metrics

▪ ratings downgrades at certain affiliated entities

▪ for Sempra, expansion of unregulated businesses in a manner inconsistent with its present level of credit quality

▪ for Sempra and SDG&E, catastrophic wildfires caused by SDG&E or any other California electric IOU that participates in the Wildfire Fund and Continuation Account

▪ for SDG&E and SoCalGas, a deterioration of the legislative or regulatory environment, including credit negative outcomes of regulatory proceedings

▪ for Sempra and SI Partners, the PA LNG Phase 1 project or PA LNG Phase 2 project experiencing higher construction costs, delays or other challenges

In an effort to maintain these credit ratings, we may seek to reduce our outstanding indebtedness or our need for additional indebtedness by reducing or postponing discretionary, non-safety or reliability related capital expenditures or investments in new businesses. We may also issue additional equity securities, including in our ATM program, or sell additional equity interests in our subsidiaries or development projects. We may not be able to complete any such equity sales on acceptable terms or at all, and any new equity issued by Sempra may dilute the voting rights and economic interests of Sempra’s existing equity holders. Any such outcome could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.

Although we aim to maintain or improve these credit ratings, they could be downgraded or subject to other negative rating actions at any time, such as S&P’s January 2025 actions that revised Sempra’s outlook to negative from stable and downgraded SoCalGas’ issuer credit rating, and Moody’s March 2025 action that revised Sempra’s outlook to negative from stable. A downgrade of any of our businesses’ credit ratings or ratings outlooks, as well as the reasons for such downgrades, could materially adversely affect the interest rates at which borrowings can be made and debt securities issued and the various fees on our credit facilities. This could make it more costly to borrow money, issue securities and/or raise other types of capital, any of which could reduce our ability to meet our debt obligations and contractual commitments and, in the case of our regulated utilities, increase customer rates, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We discuss these credit ratings in “Part II – Item 7. MD&A - Capital Resources and Liquidity.”

We do not fully hedge our assets or contract positions against changes in commodity prices or interest rates, and for positions that are hedged, our hedging mechanisms may not mitigate our risk or reduce our losses as intended.

We use forward contracts, futures, financial swaps and/or options, among other mechanisms, to hedge a portion of our known or anticipated purchase and sale commitments, inventories of natural gas and LNG, natural gas storage and pipeline capacity and electric generation capacity in an effort to reduce our, and for SDG&E and SoCalGas, customers’ financial exposure related to commodity price fluctuations. In addition, we have used and may continue to use similar financial instruments to hedge against changes in interest rates. The extent to which we hedge our positions varies over time. Certain derivative instruments are recorded at fair value through earnings to reflect movements in the price of the derivative, which has recently and could in the future create volatility in our earnings. The effect of such commodity derivative instruments for SDG&E and SoCalGas are passed through to customers in rates without markup. To the extent we have unhedged positions, if any hedging counterparty fails to fulfill its contractual obligations, or if our hedging strategies do not work as intended, fluctuating commodity prices and interest rates could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

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Risk management procedures may not prevent or mitigate losses.

Although we have risk management and control systems designed to quantify and manage risk, these systems may not prevent material losses. Risk management procedures may not always be followed as intended or function as expected. In addition, daily VaR and loss limits, which are primarily based on historic price movements and which we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” may not protect us from losses if prices significantly or persistently deviate from historic prices. As a result of these and other factors, our risk management procedures and systems may not prevent or mitigate losses that could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

An impairment of our long-lived assets could result in a material charge to earnings.

We test long-lived assets, including equity method investments, for recoverability when events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the assets. We could experience events or changes in circumstances from, among other things, (i) an inability to operate our existing facilities; (ii) an inability to collect from customers; (iii) changes to laws or regulations or other circumstances affecting the energy sector or our assets in Mexico; (iv) adverse rulings in lawsuits, binding arbitrations, regulatory proceedings, audits and other proceedings materially impacting our businesses and (v) more generally any loss of permits or approvals that requires us to adjust or cease certain operations and any failure to complete or receive an adequate return on our investments in capital projects. A material charge to earnings from an impairment loss could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Market performance, significant transactions or changes in other assumptions could require unplanned contributions to pension and PBOP plans.

Sempra, SDG&E and SoCalGas provide defined benefit pension and PBOP plans to eligible employees and retirees. The cost of providing these benefits is affected by many factors, including the market value of plan assets, the partial termination of Sempra’s pension plan in connection with the planned sale of a portion of our equity interest in SI Partners and the other factors described in Note 9 of the Notes to Consolidated Financial Statements and “Part II – Item 7. MD&A – Capital Resources and Liquidity.” A decline in the market value of plan assets or an adverse change in any of these other factors could cause a material increase in our funding obligations for these plans, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Legal and Regulatory Risks

We face risks related to the evolving regulatory environment, including failures or delays in obtaining and maintaining franchises and other required approvals and potential negative impacts of our legislative and regulatory advocacy efforts.

The industries in which we operate are subject to extensive regulation, increasing regulatory uncertainty and political influence and polarization.

Our businesses require numerous permits, licenses, rights-of-way, franchises, certificates and other approvals from federal, state, local and foreign governmental agencies. These approvals may not be granted in a timely manner (including due to potential staffing and funding issues at regulatory agencies) or at all or may be modified, rescinded or fail to be extended for a variety of reasons, including due to legal or regulatory changes or political considerations. The City of San Diego is studying the feasibility of municipalization as a potential alternative to SDG&E’s existing electric franchise agreement, and various aspects of SDG&E’s natural gas and electric franchise agreements have also been challenged in a lawsuit that we discuss in Note 16 of the Notes to Consolidated Financial Statements. At SI Partners, amendments to Mexico’s Constitution and the 2025 Energy Laws have increased government control and participation in the energy sector and may create novel challenges for infrastructure development and operations. Obtaining or maintaining required approvals could result in higher costs or the imposition of conditions or restrictions on our operations. Further, noncompliance by us or certain of our customers with the terms of these approvals could result in their modification, suspension or rescission and subject us to reduced revenue, fines and penalties. If any of these approvals are suspended, rescinded or otherwise terminated or modified in a manner that makes our continued operation of the applicable business prohibitively expensive or otherwise impracticable, we may be required to adjust or temporarily or permanently cease certain of our operations, sell the associated assets or remove them from service and/or construct new assets intended to bypass the impacted area, in which case we may lose some of our rate base or revenue-generating assets, our development and construction projects may be negatively affected and we may incur impairment charges or other costs that may not be recoverable. The occurrence of any of these events could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

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From time to time, we invest funds in projects prior to receiving all regulatory approvals. Any inability to recover funds invested in these projects could materially increase our costs, result in material impairments, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We may be unable to recover any or all amounts invested in such projects if:

▪ there is a delay in obtaining these approvals

▪ any approval is conditioned on changes or other requirements that increase costs or impose restrictions on our existing or planned operations

▪ we fail to obtain or maintain these approvals or comply with them or other applicable laws or regulations

▪ we are involved in litigation that adversely impacts any approval or rights to the applicable property or assets

▪ management decides not to proceed with a project

▪ for our regulated utilities, expenditures are required before rate recovery can be requested or remain subject to subsequent regulatory filings and/or reasonableness reviews that could result in extended delays or denial of rate recovery or disallowance of some or all incurred costs

Our businesses engage in lobbying at the federal, state and local levels with the aim to support sound and stable governmental policies and shape the legal and regulatory framework for the energy sector. As has happened in the past, these advocacy efforts may be unsuccessful or result in adverse publicity. We also incur costs related to these activities, and for our regulated utilities, such costs are not recoverable in rates. Any of these impacts could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We face risks related to environmental and climate change regulation and the costs of the energy transition.

The impacts from efforts to mitigate climate change and related regulations may increase the costs we incur to procure and transmit energy and provide other services. The changes in costs and preferences for lower carbon and renewable energy sources may impact the demand for, consumption of, and types of energy we transmit and distribute.

Environmental and Climate Change Regulation

We are subject to extensive federal, state, regional, local, tribal and foreign laws and regulations relating to climate change and environmental protection. To comply with these laws and regulations, we must expend significant capital and employee resources on environmental monitoring, surveillance and other measures to track and disclose performance; acquisition and installation of pollution control equipment; implementation of environmental safety practices; other mitigation efforts; and emissions fees, taxes, penalties and other payments. These requirements could increase as a result of various factors we may not control, including changes to laws and regulations, many of which are becoming more burdensome in light of increasing environmental concerns and related changes to legal and regulatory frameworks; increased readiness and enforcement activities; delays in the renewal and issuance of permits; evolving expectations of investors and other stakeholders; and changes to the mix of energy we transmit and distribute, any of which could negatively impact our operations, costs and corporate planning, demand for our services, customer affordability, and the scope and economics of proposed infrastructure projects or other capital expenditures. In particular, legislation and regulation designed to reduce GHG emissions and mitigate climate change are proliferating, as we discuss in “Part I – Item 1. Environmental Matters.” California’s goals are facing cost pressures and may experience delays or other challenges that could cause the state to modify its laws and rules, resulting in significant uncertainty. Any failure to comply with these or other environmental laws and regulations may subject us to fines and penalties, including criminal penalties in some cases, and/or curtailment of our operations.

In addition, we are generally responsible for hazardous substances and other contamination on, and the conditions of, our projects and properties, regardless of when these conditions arose and whether they are known or unknown. We have been and may in the future be required to pay environmental remediation costs at former facilities and off-site waste disposal sites where any of our businesses is identified as a PRP under federal, state and local environmental laws. For our regulated utilities, some or all of these costs may not be recoverable in rates.

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Additionally, California laws requiring expansive disclosures on GHG emissions and other environmental measures, targets and claims subject us to potential liability for these disclosures as well as significant compliance costs and could have other consequences that may be difficult to predict, including negative sentiment from current and potential investors, regulators, legislators or other groups. These California disclosure requirements, which remain subject to rulemaking by CARB and have been the subject of legal challenges, and other voluntary disclosures we make may use different reporting frameworks, methodologies and boundaries from each other, which may further increase compliance costs and the risk of compliance failures and may create confusion for stakeholders. Moreover, these disclosure requirements could increase the risk that we become subject to climate change lawsuits. Defense costs associated with such litigation could be significant, and any adverse outcome could require substantial capital expenditures or payment of substantial penalties or damages.

Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Other Energy Transition Risks

The energy transition in California and elsewhere, including decarbonization goals and increasingly divergent investor sentiment regarding climate change efforts, has led to contradictory expectations from various investors and other stakeholders and uncertainty in long-term investor support, including some investors reducing participation in or divesting from our sector. Maintaining investor confidence and attracting capital at a competitive cost will depend, in part, on demonstrating our ability to address material business risks related to climate and our efforts to help achieve the goals of our consumers and the markets and jurisdictions where we operate. In an effort to maintain a sustainable and durable business risk profile and continue to focus on value creation, Sempra updated its climate aspirations to reflect the changing policy, regulatory, commercial and technological landscape, including stakeholders’ evolving focus on reliability, resiliency and affordability and the pace and impact of climate and other public policies. Sempra aims to have net-zero scope 1 and 2 GHG emissions by 2050 and has an interim aim of 50% scope 1 and 2 GHG emissions reductions by 2035 (this interim target is relative to a 2019 baseline, applies to Sempra California’s operations and Sempra Infrastructure’s Mexico (non-LNG) operations, and may be subject to further revision if Sempra’s planned sale of a portion of its equity interest in SI Partners is completed). Sempra’s, SDG&E’s and SoCalGas’ abilities to advance their respective net-zero and other climate objectives and meet the demand for lower-carbon and reliable energy in California and elsewhere will depend on many factors, some of which we do not control, including supportive federal and state energy laws, policies, incentives, tax credits and regulatory decisions; cost and affordability considerations; development, commercialization and regulatory acceptance of affordable, alternative and lower-carbon energy sources, including cleaner fuels; successful research and development efforts focused on lower carbon technologies that are economically and technically feasible; cooperation from our partners, financing sources and commercial counterparties; and consumers’ decisions and preferences. In addition, we will need to continue to expend capital and employee resources to develop and deploy new technologies and modernize grid systems, which may not be recoverable in rates or, with respect to our businesses that are not regulated utilities, may not be able to be passed through to customers. Even if such costs are recoverable, these costs, coupled with necessary safety and reliability investments, may negatively impact the affordability of SDG&E’s and SoCalGas’ services and, for our businesses that are not regulated utilities, may cause costs to increase to levels that reduce customer demand and growth. Moreover, forecasting specified targets over longer-term periods is inherently uncertain and could be significantly impacted by the trajectory of the energy transition. As a result, although we are dedicated to making progress on our climate aims and are continuing to develop capabilities designed to reduce GHG emissions from our own operations as well as to support consumers’ and markets’ climate goals and applicable legislative and regulatory mandates, we may not be successful in achieving these objectives. We could suffer difficulties attracting investors and business partners, reputational harm and other negative effects if we do not meet or if we further modify our GHG emissions reduction aims or there are negative views about our environmental disclosures or practices generally.

We develop our capital expenditure plans based on assumptions and forecasts as well as regulatory and compliance requirements, including those related to safety, reliability and load growth, gas system planning, and transportation electrification, which generally assume that California will continue to pursue consistent environmental and climate-related policies. If the federal government continues to reduce its support for grid and infrastructure modernization or takes further action to prohibit California from pursuing its environmental and climate-related policies, or if California changes its policies, the assumptions and forecasts underlying our capital expenditure plans may prove to be inaccurate, and our investment plans could suffer significant negative effects.

The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

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We are subject to complex tax and accounting requirements that expose us to risks.

We are subject to complex tax and accounting requirements. These requirements may undergo changes at the federal, state, local and foreign levels, including in response to economic or political conditions. Compliance with these requirements and any changes to them or how they are implemented, interpreted or enforced could increase our operating costs and materially adversely affect how we conduct our business. New tax legislation, such as the OBBBA, and new regulations or interpretations or changes in tax policies in the U.S., Mexico or other countries in which we do business could negatively affect our tax expense and/or tax balances and our businesses generally. Any failure to comply with these requirements could subject us to fines and penalties, including criminal penalties in some cases. The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We may be negatively impacted by the outcome of litigation or other proceedings in which we are involved.

Our businesses are involved in a number of lawsuits, appeals, binding arbitrations, regulatory investigations and other proceedings. We discuss material pending proceedings in Note 16 of the Notes to Consolidated Financial Statements. Our businesses also may become involved in proceedings that we do not consider material, such as the approximately 28,000 proofs of claim that have been filed on behalf of persons who assert the right to file lawsuits in the future based on alleged exposure to asbestos in power plants designed and/or built by certain predecessor entities we acquired in connection with our acquisition of our majority interest in Oncor. We have spent, and continue to spend, substantial capital and employee resources on lawsuits and other proceedings. The uncertainties inherent in lawsuits and other proceedings and the broad range of potential outcomes make it difficult to estimate with any degree of certainty the timing, costs and other potential impacts of these matters, and changes or disruptions to judicial systems, such as the nationwide strike by the Mexican judiciary in 2024 in response to judicial reforms and the limitations on operations of U.S. federal courts in 2025 due to lapses in congressional appropriations, could result in delays, increased costs, or unfavorable outcomes. In addition, juries have demonstrated a willingness to grant large awards, including punitive damages, in response to personal injury, product liability, property damage, nuisance, and other claims. Accordingly, actual costs incurred have and may continue to differ materially from insured or reserved amounts and may not be recoverable, in whole or in part, from insurance or in customer rates. Any of the foregoing could cause reputational damage and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

RISKS RELATED TO SEMPRA CALIFORNIA

Operational Risks

Wildfires in California pose risks to Sempra, SDG&E and SoCalGas.

More and Increasingly Severe Wildfires

In recent years, California has experienced some of the largest wildfires (measured by acres burned and/or structures destroyed) in its history. Frequent and severe drought conditions, inconsistent and extreme swings in precipitation, changes in vegetation, unseasonably warm temperatures, low humidity, strong winds and other factors have increased the duration of the wildfire season and the intensity, prevalence and difficulty of preventing and containing wildfires in California, including in SDG&E’s and SoCalGas’ service territories. Changing weather patterns, including as a result of climate change, could exacerbate these conditions. Certain California local land use policies and forestry management practices, as well as expanded construction and development of residential and commercial projects in high-risk fire areas, could lead to increased third-party claims and greater losses related to fires for which SDG&E or SoCalGas may be liable.

The LA Fires burned in SoCalGas’ service territory. The California Department of Forestry and Fire Protection estimates that the Palisades and Eaton fires destroyed approximately 16,200 structures and damaged approximately 2,000 structures. Although the majority of SoCalGas’ infrastructure in the fire-affected areas is underground, these fires resulted in service disruptions, response costs and damage to some of SoCalGas’ infrastructure and third-party property. SoCalGas and Sempra are subject to pending litigation with respect to the operation of SoCalGas’ system and damage sustained as a result of the fires, which we discuss in Note 16 of the Notes to Consolidated Financial Statements. As with other litigation, the timing, impacts and ultimate outcome of these matters is inherently uncertain and may result in substantial costs, some or all of which may not be recoverable from insurance, third parties or in customer rates. We discuss these and other risks associated with litigation above under “Risks Related to All Sempra Businesses – Operational Risks.”

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Future wildfires in SDG&E’s or SoCalGas’ service territories could compromise SDG&E’s and SoCalGas’ electric and natural gas infrastructure and result in further service disruptions, which could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects. We discuss these risks further in this risk factor below and above under “Risks Related to All Sempra Businesses – Operational Risks.”

The Wildfire Legislation

In July 2019 and September 2025, respectively, the 2019 Wildfire Legislation and the 2025 Wildfire Legislation (collectively, the Wildfire Legislation) were signed into law, which we discuss in Note 1 of the Notes to Consolidated Financial Statements. The 2019 Wildfire Legislation established the Wildfire Fund and the 2025 Wildfire Legislation established the Continuation Account, which offer liquidity to reimburse wildfire-related claims incurred by participating California electric IOUs in excess of $1 billion, subject to the coverage of each fund. The Wildfire Legislation’s legal standards for the recovery of wildfire costs may not be implemented effectively or applied consistently. Moreover, the Wildfire Fund and the Continuation Account, if it becomes operative, could be materially reduced, exhausted, or terminated due to claims by SDG&E or other participating IOUs related to fires caused by utility conduct or operations, or SDG&E could fail to maintain a valid annual safety certification from the OEIS or meet other requirements, any of which could result in SDG&E losing eligibility for the Wildfire Legislation’s liability cap and the other protections afforded by these funds. As a result, a fire resulting from the conduct or operations of any participating California electric IOU could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects, with potentially material additional exposure if SDG&E’s conduct or operations is determined to be a cause of a fire and SDG&E is found to have acted imprudently.

In February 2026, a participating IOU publicly disclosed that it has received, or expects to receive, approximately $1.26 billion in aggregate reimbursements from the Wildfire Fund for eligible claims related to wildfires that occurred in 2019 and 2021. Also in February 2026, another participating IOU publicly disclosed it has received, or expects to receive, approximately $134 million in aggregate reimbursements from the Wildfire Fund for losses incurred and expected to be incurred in connection with one of the LA Fires, the cause of which remains under investigation and has not been conclusively determined. The administrator of the Wildfire Fund has confirmed that this wildfire qualifies as a “covered wildfire” for purposes of accessing the Wildfire Fund, and the scope of potential damages caused by this fire could materially reduce or exhaust the Wildfire Fund. The participating IOU 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. In addition to the risks described above, a material reduction, exhaustion or termination of the Wildfire Fund may require SDG&E to recognize a reduction to its Wildfire Fund asset up to its carrying value.

The Wildfire Legislation did not change the doctrine of inverse condemnation, which imposes strict liability for certain types of claims (meaning that liability is irrespective of negligence or intent) on a utility whose equipment is determined to be a cause of a fire. In such an event, the utility would be responsible for the costs of damages, including business interruption losses, interest and attorneys’ fees, even if the utility is not found negligent. In the past, the CPUC has denied recovery of incurred costs associated with wildfire claims despite the doctrine of inverse condemnation, which was historically based on the ability of a utility to pass such costs through to rate payers. The doctrine of inverse condemnation also is not exclusive of other theories of liability, such as negligence, under which additional liabilities, such as fire suppression, clean-up and evacuation costs, medical expenses, and personal injury, punitive and other damages, could be imposed. We are unable to predict the impact of the Wildfire Legislation on SDG&E’s ability to recover costs and expenses if SDG&E’s equipment is determined to be a cause of a fire.

The 2025 Wildfire Legislation also established 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 and, if it becomes operative, the Continuation Account. We are unable to predict the impact on Sempra or SDG&E of further legislative or regulatory action with respect to the Wildfire Fund or the Continuation Account or wildfire claims liability generally.

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Cost Recovery Through Insurance or Rates

As a result of California’s doctrine of inverse condemnation, substantial losses recorded by insurance companies, and increased wildfire risk, obtaining insurance coverage for wildfires potentially associated with SDG&E’s equipment (or, to a lesser extent, SoCalGas’ equipment) has become increasingly difficult and costly. If these conditions continue or worsen, including as a result of the LA Fires, insurance for wildfire liabilities may become unavailable or may become prohibitively expensive and we may be denied recovery of insurance cost increases through the regulatory process. In addition, insurance for wildfire liabilities may not be sufficient to cover all losses we may incur, or it may not be available to meet the $1.0 billion of primary insurance required by the Wildfire Legislation. Wildfire insurance may also become prohibitively expensive or unavailable for homeowners and businesses in SDG&E’s service territory, potentially increasing SDG&E’s financial exposure if a wildfire is found to be caused by SDG&E’s equipment. We may be unable to recover in rates or from the Wildfire Fund or the Continuation Account the amount of any uninsured losses (including amounts paid for self-insurance and other costs). A loss that is not fully insured, is not sufficiently covered by the Wildfire Fund or the Continuation Account and/or cannot be recovered in customer rates could materially adversely affect Sempra’s and one or both of SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.

Regulatory Actions Related to Wildfire Mitigation Efforts

Although we expend significant resources on measures designed to mitigate wildfire risks, these measures may not be effective in preventing wildfires or reducing our wildfire-related losses, and their costs may not be fully recoverable in rates. SDG&E is required by California law to submit WMPs for approval by the OEIS and could be subject to increased risks if these plans are not approved in a timely manner or SDG&E is determined to not have substantially complied with its approved plans, including the risk of fines or penalties for non-implementation or denial of its safety certification. Moreover, wildfire mitigation investments incremental to those authorized in a GRC may be subject to reasonableness reviews after they are made and could be subject to disallowances as a result of such reviews, as was the case with the FD issued in connection with SDG&E’s Track 2 request in its 2024 GRC. One of SDG&E’s wildfire mitigation strategies is to de-energize certain circuits for safety when there is elevated weather-related wildfire ignition risk. These “public safety power shutoffs” have been subject to scrutiny by various stakeholders, including customers, regulators and lawmakers, which could increase the risk of regulatory fines and penalties, claims for damages and reputational harm if SDG&E is found not to have acted within applicable guidelines and regulations. Such costs may not be recoverable in rates. Unrecoverable costs, adverse legislation or rulemaking, stakeholder scrutiny, ineffective wildfire mitigation measures or other negative effects associated with these efforts could materially adversely affect Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.

The electricity industry is undergoing significant change .

Electric utilities in California are experiencing increasing deployment of solar and wind generation, including DER, energy storage and energy efficiency and demand management technologies, and California’s environmental policy objectives are accelerating the pace and scope of these changes. This growth will require further modernization of the electric grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid’s capacity to interconnect these resources. In addition, attaining California’s clean energy goals will require sustained investments in transmission and distribution grid modernization, renewable energy integration projects, operational and data management systems, and electric vehicle and energy storage infrastructure, which may increase exposure to overall grid instability and technology obsolescence. The growth of third-party energy storage alternatives and other technologies also may increasingly compete with SDG&E’s traditional transmission and distribution infrastructure in delivering electricity to consumers. Certain FERC transmission development projects are open to competition, allowing independent developers to compete with incumbent utilities for the construction and operation of transmission facilities. The CPUC is conducting various proceedings regarding DER, including the evaluation of special programs and pilot projects; changes to the planning and operation of the electric grid to prepare for higher penetration of DER; future grid modernization investments; the deferral of traditional grid investments by DER; and the role of the electric grid operator. These proceedings and the broader changes in California’s electricity industry could result in new regulations, policies and/or operational changes that could materially adversely affect Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.

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Most of SDG&E’s customers receive electric commodity service from a load-serving entity other than SDG&E through programs such as CCA and DA. CCA is only available if a customer’s local jurisdiction (city or county) offers such a program, as is the case with the City of San Diego and certain other jurisdictions in SDG&E’s service territory, and DA is currently limited by a cap based on gigawatt hours. Due to this departed load, SDG&E’s historical energy procurement commitments for future deliveries exceed the needs of its remaining bundled customers. To help achieve the goal of ratepayer indifference (as to whether customers’ energy is procured by SDG&E or by CCA or DA), the CPUC revised the Power Charge Indifference Adjustment framework. The framework is intended to more equitably allocate SDG&E’s historical energy procurement cost obligations among customers served by SDG&E and customers now served by CCA and DA. If the framework or other mechanisms designed to achieve ratepayer indifference do not perform as intended, if the law changes, or if the law is not interpreted or enforced as expected, SDG&E’s remaining bundled customers could experience large increases in rates for ongoing historical commodity costs under commitments made on behalf of CCA and DA customers prior to their departure or, if all such costs are not recoverable in rates, SDG&E could experience material increases in its unrecoverable commodity costs. Any of these outcomes could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.

Additionally, if a CCA or DA in SDG&E’s service territory were to fail, SDG&E, as the provider of last resort, would be responsible for providing uninterrupted electric service to customers and would be entitled to cost recovery for temporary service, and the CCA or DA would be required to post financial security to cover the cost of returning load. Once returned, SDG&E would be required to provide commodity service to those customers and would be required to meet the increased commodity compliance requirements resulting from service of the additional load. The CPUC has established an application process for non-IOU load serving entities to potentially step into the role of provider of last resort. If a non-IOU load serving entity was permitted to serve as provider of last resort in SDG&E’s service territory, SDG&E may not be responsible for providing commodity service from the failure of a CCA or DA, the impact of which remains uncertain. Any of these outcomes could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.

Natural gas continues to be the subject of political and public debate, including a desire by some to reduce or eliminate reliance on natural gas as an energy source .

Certain California legislators, regulators and other stakeholders have expressed a desire to limit or eliminate reliance on natural gas as an energy source through increased use of renewable electricity and electrification. Reducing methane emissions also has become a major focus of certain local and state agencies, resulting in passed or proposed legislation, regulation, policies and ordinances to prohibit or restrict the use of natural gas in new buildings, appliances and other applications, including proposed and recently enacted requirements regarding space and water heaters in newly constructed buildings and an open CPUC proceeding to establish long-term gas system infrastructure planning for natural gas utilities in alignment with California’s decarbonization goals. Additionally, customer preferences may drive increased disconnections from gas service. These actions could result in reduced natural gas use over time and changes to rate and cost recovery policies, and the combination of reduced load and increasing costs to maintain the gas system could negatively impact affordability for remaining natural gas customers. Moreover, a substantial reduction in or the elimination of natural gas use in California could result in impairment of some or all of SDG&E’s and SoCalGas’ natural gas infrastructure assets without adequate recovery of investments, if they were not permitted to be repurposed, or if they were required to be depreciated on an accelerated basis or were to become stranded, in which case, SDG&E and SoCalGas could be required to incur significant decommissioning or other costs, which may require additional funding and may not be recoverable in rates. For instance, in a prior proceeding that is now closed, the CPUC evaluated the feasibility of minimizing or eliminating SoCalGas’ Aliso Canyon natural gas storage facility. The authorized storage level and reliance on the facility in general remain subject to a biennial administrative staff review by the CPUC and additional CPUC proceedings. A permanent closure, which could only be achieved through a new CPUC proceeding, could result in an impairment of the facility that could be material, and a closure or significant reduction in authorized capacity could risk energy and electric reliability in the region. Any such outcome could have a material adverse effect on Sempra’s, SoCalGas’ and SDG&E’s results of operations, financial conditions, cash flows and/or prospects.

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SDG&E may incur significant costs and liabilities from its partial ownership of a nuclear facility being decommissioned .

SDG&E has a 20% ownership interest in SONGS, which we discuss in Note 15 of the Notes to Consolidated Financial Statements. SDG&E is responsible for financing its proportionate share of the facility’s expenses and capital expenditures, including those related to decommissioning activities. Although the facility is being decommissioned, SDG&E’s ownership interest in SONGS continues to subject it to risks, including:

▪ the potential release of radioactive material

▪ the potential harmful effects from the former operation of the facility

▪ limitations on the insurance commercially available to cover losses associated with operating and decommissioning the facility

▪ uncertainties with respect to the technological, financial, and political aspects of decommissioning the facility and the long-term storage of radioactive materials

SDG&E maintains the SONGS NDT to provide funds for nuclear decommissioning. Trust assets generally have been invested in equity and debt securities, which are subject to market fluctuations. A decline in the market value of trust assets, an adverse change in the law regarding funding requirements for decommissioning trusts, or changes in assumptions or forecasts related to decommissioning timing and costs could increase the funding requirements for these trusts, which costs may not be fully recoverable in rates. In addition, CPUC approval is required to make withdrawals from the NDT, which may be denied if the expenditures are found to be unreasonable. In addition, decommissioning may be materially more expensive than we currently anticipate and therefore decommissioning costs may exceed the amounts in the NDT. Rate recovery for overruns would require CPUC approval, which may be denied.

The occurrence of any of these events could result in a reduction in our expected recovery and have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.

Legal and Regulatory Risks

SDG&E and SoCalGas are subject to extensive regulation.

Rates and Other Financial Matters

The CPUC regulates SDG&E’s and SoCalGas’ customer rates and conditions of service, except for SDG&E’s interstate electric transmission and wholesale electric rates and conditions of service, which are regulated by the FERC. The CPUC also regulates SDG&E’s and SoCalGas’ sales of securities, rates of return, capital structure, rates of depreciation, long-term resource procurement and other financial matters in various ratemaking proceedings. The CPUC periodically approves SDG&E’s and SoCalGas’ customer rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investments while incorporating a risk-based decision-making framework, as well as certain settlements with third parties and mandatory social programs. The timing and outcome of ratemaking proceedings can be affected by various factors, many of which are not in our control, including the level of opposition by intervening parties; any rejection by the CPUC of settlements with third parties; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of regulators, customers and other stakeholders. These ratemaking proceedings include decisions about major programs in which SDG&E and SoCalGas make investments under an approved CPUC framework, such as wildfire mitigation, pipeline and storage integrity and safety enhancement programs, but which investments may remain subject to CPUC filings or reasonableness reviews that may result in the disallowance of incurred costs, as was the case with SDG&E’s Track 2 request in its 2024 GRC. SDG&E and SoCalGas also may be required to make investments and incur other costs before they can request rate recovery for certain projects or to comply with proposed legislative and regulatory requirements, including those related to California’s climate goals and policies, before finalization of the requirements and corresponding ratemaking mechanisms, which investments may not ultimately be fully recoverable. Recovery may be delayed and/or insufficient if ratemaking mechanisms involve a significant time lag between when costs are incurred and when those costs are recovered in rates or if there are material differences between the authorized costs embedded in rates (which are set on a prospective basis) and the actual costs incurred. As was the case with respect to the 2024 GRC FD, delays may also result from the regulatory process and the CPUC may deny recovery altogether on the basis that costs were not reasonably or prudently incurred or for other reasons, such as customer affordability. Even if recoverable, simultaneously investing in support of necessary safety and reliability and regulatory requirements and demand for reliable lower-carbon energy may negatively impact the affordability of SDG&E’s and SoCalGas’ services and their and Sempra’s results of operations, financial condition, cash flows and/or prospects.

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A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and return on rate base. The CPUC applies the CCM, which we describe in “Part I – Item 1. Business – Ratemaking Mechanisms” and Note 4 of the Notes to Consolidated Financial Statements, in the interim years to consider changes in the cost of capital using changes in interest rates. Any rate changes due to a downward trigger of the CCM, the denial by the CPUC of an automatic upward trigger of the CCM or further structural changes to the CCM could have a material adverse effect on Sempra’s and the applicable utility’s results of operations, financial condition, cash flows and/or prospects. We discuss the CCM in “Part I – Item 1. Business – Ratemaking Mechanisms – Sempra California – Cost of Capital Proceedings,” and in Note 4 of the Notes to Consolidated Financial Statements.

The FERC regulates electric transmission rates, transmission and wholesale sales of electricity in interstate commerce, transmission access, rates of return and rates of depreciation on electric transmission investments, and other similar matters involving SDG&E. These ratemaking mechanisms are subject to many risks similar to those described above regarding CPUC ratemaking proceedings. In particular, 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. 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 proposed, 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. In February 2026, the settlement judge in the TO6 proceeding reported to the FERC that the participants had reached an agreement in principle on all issues in the proceeding. The parties will draft an offer of settlement to be filed with the FERC for approval. Any unfavorable outcome in these proceedings, such as an authorized ROE that is materially lower than the requested ROE, could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.

Operational Matters

Our operations are subject to CPUC rules (and similar FERC rules), commonly referred to as “affiliate rules,” relating to transactions among SDG&E, SoCalGas and other Sempra businesses. These rules primarily impact market transactions and marketing activities involving transmission supply and capacity, including sales or other trades of natural gas or electricity within or among SDG&E and SoCalGas and Sempra and its covered affiliates. Noncompliance with these rules, as well as any changes or additions to these rules or their interpretations, could materially adversely affect our operations and, in turn, our results of operations, financial condition, cash flows and/or prospects.

Additionally, the CPUC has regulatory authority related to safety standards and practices, reliability and planning, competitive conditions and a wide range of other operational matters, including restrictions on funding of lobbying or other political activities, promotional advertising and certain other costs, as well as citation and enforcement programs concerning matters such as safety activity, disconnection and billing practices, commodity pricing, resource adequacy and environmental compliance. Many of these standards and citation and enforcement programs are becoming more stringent and could subject a utility to significant penalties and fines, as well as higher operating costs. The CPUC conducts reviews and audits of the matters under its authority and may launch investigations or open proceedings at its discretion, the results of which could include citations, disallowances, fines and penalties, as well as requirements for corrective or mitigation actions to address any noncompliance, any of which may not be sufficiently funded by customer rates or at all. Any such occurrence could result in other regulatory exposure, significant litigation, and reputational harm and could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.

The FERC enforces mandatory reliability standards developed by the North American Electric Reliability Corporation, including standards designed to protect the power system against potential disruptions from cyber and physical security breaches. Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1.6 million per day per violation) for any failure to comply with these standards, which could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.

We discuss various CPUC and FERC proceedings relating to SDG&E and SoCalGas in Note 4 of the Notes to Consolidated Financial Statements.

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Regulatory and Legislative Changes and Influence of Other Organizations

SDG&E and SoCalGas incur significant capital, operating and other costs associated with regulatory compliance. Sempra, SDG&E and SoCalGas may be materially adversely affected by revisions or reinterpretations of existing or new legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies, any of which could change how SDG&E and SoCalGas operate, affect their ability to recover various costs through rates or adjustment mechanisms, require them to incur additional compliance or other costs, including fines and penalties, or otherwise materially adversely affect their and Sempra’s results of operations, financial condition, cash flows and/or prospects.

SDG&E and SoCalGas are also affected by numerous advocacy groups, including California Public Advocates Office, The Utility Reform Network, Utility Consumers’ Action Network and the Sierra Club. Success by any of these groups in directly or indirectly influencing legislators and regulators could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.

Failure by the CPUC to adequately reform SDG&E’s electric rate structure could negatively impact Sempra and SDG&E.

The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable energy generation (primarily solar) for residential and business customers. Depending on when the on-site generation is installed, NEM customers receive a full retail rate or a reduced retail rate for energy they generate but do not use that is fed to the utility’s power grid, which results in these customers not paying their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, subject to certain exceptions, but still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs. As more and higher electric-use customers switch to NEM and self-generate energy, the burden on remaining non-NEM customers, who effectively subsidize the unpaid NEM costs, increases, which in turn encourages more self-generation and further increases rate pressure on remaining non-NEM customers.

In December 2023, a new Net Billing Tariff was implemented for customers who interconnect their qualifying on-site renewable energy generation after April 2023. The new Net Billing Tariff revised the NEM structure for new customers with a retail export compensation rate that is better aligned with the value provided to the grid by behind-the-meter energy generation systems and retail import rates that encourage electrification and adoption of solar systems paired with storage. The new Net Billing Tariff is designed to compensate customers for the value of their exports to the grid based on avoided cost. In addition, prior to the fourth quarter of 2025, the electric residential rate structure in California was primarily based on consumption volume, which placed a higher rate burden on customers with higher electric use while subsidizing lower-use customers. In response to California legislation adopted in 2022, the CPUC broadly restructured the way certain residential fixed costs are collected, moving away from volumetric -only charges and incorporating an income-based fixed charge for default residential rates. The intent of such a fixed charge is to allow the utility to collect a greater portion of its fixed costs on a non-volumetric basis, advance the state’s climate goals through end-use electrification and provide a more affordable rate design on average for lower-income customers. The residential fixed charge was implemented in the fourth quarter of 2025. Depending on the effectiveness of the new Net Billing Tariff and fixed charge, which are uncertain, the risks associated with the existing NEM tariff and rate design could continue or increase, including adverse impacts on electricity rates and the reliability of the transmission and distribution system and the potential for increases in customer dissatisfaction, likelihood of noncompliance with CPUC or other safety or operational standards, and power procurement, operating, capital and other costs that may not be recoverable, any of which could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.

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RISKS RELATED TO SEMPRA TEXAS UTILITIES

Operational and Structural Risks

Ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management, policies and operations of Oncor.

Various “ring-fencing” measures, governance mechanisms and commitments are in place that create legal and financial separation between Oncor Holdings, Oncor and their subsidiaries, on the one hand, and Sempra and its affiliates and subsidiaries, on the other hand. These measures are designed to enhance Oncor’s separateness from its owners and mitigate the risk that Oncor would be negatively impacted by a bankruptcy or other adverse financial development affecting its owners. These measures subject us and Oncor to various restrictions, including:

▪ seven members of Oncor’s 13-person board of directors must be independent directors in all material respects under the rules of the NYSE in relation to Sempra and its affiliates and any other owners of Oncor, and also must have no material relationship with Sempra or its affiliates or any other owners of Oncor currently or within the previous 10 years; of the six remaining directors, two must be designated by Sempra, two must be designated by Oncor’s minority owner, TTI, and two must be current or former Oncor officers

▪ Oncor will not pay dividends or other distributions (except for contractual tax payments) if (i) a majority of Oncor’s independent directors or any of the directors appointed by TTI determines that it is in the best interest of Oncor to retain such amounts to meet expected future requirements, (ii) the payment would cause Oncor’s debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT, or (iii) unless otherwise allowed by the PUCT, Oncor’s senior secured debt credit rating by any of the Rating Agencies falls below BBB (or Baa2 for Moody’s)

▪ certain “separateness measures” must be maintained to reinforce the legal and financial separation of Oncor from Sempra, including a requirement that dealings between Oncor and Sempra or Sempra’s affiliates (other than Oncor Holdings and its subsidiaries) must be on an arm’s-length basis, limitations on affiliate transactions and a prohibition on pledging Oncor assets or membership interests for any entity other than Oncor

▪ a majority of Oncor’s independent directors and the directors designated by TTI that are present and voting (with at least one required to be present and voting) must approve any annual or multi-year budget if the aggregate amount of capital expenditures or O&M in the budget differs by more than 10% from the corresponding amounts in the budget for the preceding fiscal year or multi-year period, as applicable

As a result of these measures, we do not control Oncor Holdings or Oncor, and we have limited ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends or other distributions, strategic planning, risk management, climate-related activities, cybersecurity practices and other important matters. Moreover, all directors of Oncor, including the directors we have appointed, have considerable autonomy and have a duty to act in the best interest of Oncor consistent with the approved ring-fence and Delaware law, which may in some cases be contrary to our interests. To the extent the directors approve or Oncor otherwise pursues actions that are not in our interest, our results of operations, financial condition, cash flows and/or prospects may be materially adversely affected.

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Industry-Related Risks

Changes in the regulation of Oncor or the regulation or operation of the electric utility industry and/or ERCOT market could negatively affect Oncor.

Oncor operates in the electric utility industry and is subject to many of the same or similar risks as SDG&E and SoCalGas as we describe above under “Risks Related to All Sempra Businesses” and “Risks Related to Sempra California,” particularly with respect to our operational risks, financial risks and specifically regulation by federal, state, and local legislative and regulatory authorities regarding rates and other financial and operational matters. Oncor is subject to a complex regulatory oversight structure with several different regulators, including the PUCT, FERC, North American Electric Reliability Corporation and Texas Reliability Entity, Inc. Oncor operates in the ERCOT market, which is subject to oversight by the PUCT and the Texas legislature, either of which could impose changes to the ERCOT market that could impact Oncor. In ERCOT, rates are set by the PUCT based on a historical test year, and as a result, the rates Oncor is allowed to charge generally will not exactly match its costs at any given point in time and it may not be able to timely or fully recover its actual costs and/or earn its full return on invested capital, particularly during periods of increased capital spending by Oncor, high inflation, or increases in interest rates, storm-related costs, and other operating costs relative to Oncor’s most recent base rate review. Further, the levels and timing of any approved recovery could significantly differ from Oncor’s requests. In addition to requests to recover its costs, Oncor’s rate proceedings may contain other requests. Failure to receive approval of its requests in any rate proceeding could adversely impact Oncor, and those impacts could be material.

The costs and burdens of complying with the various federal, state, and local legislative and regulatory requirements applicable to Oncor and adjusting Oncor’s business and operations in response to legislative and regulatory developments, including changes in ERCOT, and any fines or penalties that could result from any noncompliance, may have a material adverse effect on Oncor. In addition, insufficient electric generation capacity within ERCOT or significant changes within ERCOT or to the ERCOT market structure that impact transmission and distribution utilities, including adverse publicity or public perception or additional regulatory requirements or oversight, could materially adversely affect Oncor. Moreover, legislative, regulatory, market or industry activities could adversely impact Oncor’s collections and cash flows and jeopardize the predictability of utility earnings. For instance, in June 2025, legislation was signed into law to reduce regulatory lag on transmission and distribution capital investments through the UTM process, which we describe in “Part I – Item 1. Business – Ratemaking Mechanisms.” Oncor anticipates filing a UTM on or after March 16, 2026 for eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, and as a result has recorded regulatory assets for recoverable costs associated with those investments and recognized a corresponding amount in other regulated revenues. However, the PUCT has not finalized rules with respect to use of the UTM, and as a result any positions Oncor has taken with respect to interpreting the legislation could be revised as a result of the PUCT’s final rules and interpretations, and such revisions could have a material adverse impact on our results of operations, financial condition, cash flows and/or prospects.

Additionally, projected load growth across the ERCOT system could, if not sufficiently addressed through generation resources, system design and reliability measures, negatively impact electric infrastructure reliability and potentially cause system-wide stresses, which may be exacerbated by extreme weather events, climate-related conditions, wildfires, cyberattacks and other emergencies. Oncor is not a generator of electricity and has no control over the generation supply in ERCOT. If electricity generation is inadequate or disrupted, Oncor’s electricity delivery services may be interrupted or diminished, which could have an adverse impact on our results of operations, financial condition, cash flows and/or prospects.

Oncor is subject to periodic audits of its compliance with operations and critical infrastructure protection standards, including reliability and cybersecurity standards, as well as periodic inspections of its facilities for compliance with weatherization standards. Oncor is also required to report to the PUCT on its reliability and weather preparedness. If Oncor is found to be noncompliant with applicable reliability, service quality, weatherization or other standards, it could be subject to reputational harm, regulatory scrutiny or sanctions, including monetary penalties.

If Oncor does not successfully manage these risks and respond to any other applicable legislative, regulatory, market or industry developments, Oncor could suffer a deterioration in its results of operations, financial condition, cash flows and/or prospects, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

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Financial Risks

Oncor’s capital expenditures plan may not be executed as planned or achieve its business objectives.

Oncor’s capital expenditures plan may not be successful or completed in accordance with currently forecasted amounts, and the capital expenditures Oncor currently intends to make may not be implemented as contemplated or produce the desired improvements to service and reliability or cost management. A significant portion of Oncor’s five-year capital expenditures plan is attributable to addressing expected growth in ERCOT. Changes to the timing, location or scope of these planned projects or to the overall projected demand growth in Oncor’s service territory could materially impact Oncor’s capital expenditures plan and consequently our capital expenditures plan, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Oncor’s capital expenditures plan contemplates the large-scale buildout of new transmission lines, including the planned introduction of the 765-kV voltage class to the ERCOT market through ERCOT’s 765-kV Strategic Transmission Expansion Plan. In addition, Oncor’s capital expenditures plan includes projects to service increasing amounts of transmission interconnection requests from LC&I customers, including data centers. Data center development in Oncor’s service territory is expected to drive increasing electric demand and require a rapid and significant increase in Oncor’s grid infrastructure. The resources required to serve these new LC&I requests, including activities related to the planning, analysis, financing, and construction of transmission infrastructure required to meet the projected demand of these customers, are significant in terms of both cost and time, and Oncor may not be able to effectively or efficiently plan, receive required regulatory approvals for, finance, and execute on these requests. Additionally, forecasting future demand involves the risk that one or more high-usage customers may decide not to take energy, to take less energy than anticipated, or not to take service on the anticipated schedule, which may result in lower than expected demand growth. In addition, various statutes, regulatory requirements, and ERCOT rules and policies increasingly govern the connection of new LC&I customers to the grid and these regulations and procedures are under significant and rapidly evolving scrutiny, development and modification. How these provisions are ultimately implemented could significantly impact the desirability of the ERCOT market to prospective customers or Oncor’s ability to interconnect projects on their requested timelines. Certain of these new customers may be transitory and exit Oncor’s service territory for reasons outside of Oncor’s control.

If expected projects in Oncor’s service territory are cancelled or do not materialize or actual demand is lower than projected for any of the reasons described above or any others, Oncor’s ability to obtain cost recovery from the PUCT for related expenditures or the affordability of Oncor’s customer rates may be adversely impacted, which could materially adversely impact our results of operations, financial condition, cash flows and/or prospects.

Oncor’s capital expenditures plan will result in significant liquidity needs that may necessitate additional investments.

Oncor’s business is capital-intensive, with significant expected increases to capital spending in future periods.

Oncor relies on external financing as a significant source of liquidity for its capital requirements. In the past, Oncor has financed much of its cash needs from operations and with proceeds from indebtedness, but these sources of capital may not be adequate or available in a timely manner, on reasonable terms or at all. Oncor’s access to capital and credit markets and its cost of debt could be directly affected by changes to its credit ratings or ratings outlook. Adverse action with respect to Oncor’s credit ratings or ratings outlooks generally causes debt issuance and borrowing costs to increase. Moreover, legislative, regulatory, market or industry activities could negatively impact Oncor’s credit ratings or ratings outlooks. For example, rating agencies have noted concern that, in Texas, regulators have mandated equity ratios significantly lower than the national average for rate-making purposes. Additionally, in July 2025, S&P lowered Oncor’s senior secured debt and commercial paper ratings, citing elevated wildfire risk as a result of changing climate conditions and the lack of certain legal protections for wildfire litigation in Texas.

Because our commitments to the PUCT prohibit us from making loans to Oncor, we may elect to increase our capital contributions to Oncor if it is unable to meet its capital requirements, access sufficient capital, or raise capital on favorable terms. Any such investments could be substantial, would reduce the cash available to us for other purposes, may not be recovered, and could increase our indebtedness, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

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Sempra could incur substantial tax liabilities if EFH’s 2016 spin-off of Vistra is deemed to be taxable.

As part of its bankruptcy proceedings, in 2016, EFH distributed all the outstanding shares of common stock of its subsidiary Vistra Corp. (formerly Vistra Energy Corp. and referred to herein as Vistra) to certain creditors of TCEH LLC (the spin-off), and Vistra became an independent, publicly traded company. Vistra’s spin-off from EFH was intended to qualify for partially tax-free treatment to EFH and its shareholders under Sections 368(a)(1)(G), 355 and 356 of the U.S. Internal Revenue Code of 1986 (as amended) (collectively referred to as the Intended Tax Treatment). In connection with and as a condition to the spin-off, EFH received a private letter ruling from the IRS regarding certain issues relating to the Intended Tax Treatment, as well as tax opinions from counsel to EFH and Vistra regarding certain aspects of the spin-off not covered by the private letter ruling.

In connection with the merger of EFH with a subsidiary of Sempra in 2018 (the Merger), EFH received a supplemental private letter ruling from the IRS and Sempra and EFH received tax opinions from their respective counsels that generally provide that the Merger will not affect the conclusions reached in, respectively, the IRS private letter ruling and tax opinions issued with respect to the spin-off described above. Similar to the IRS private letter ruling and opinions issued with respect to the spin-off, the supplemental private letter ruling is generally binding on the IRS and any opinions issued with respect to the Merger are based on factual representations and assumptions, as well as certain undertakings, made by Sempra and EFH. If such representations and assumptions are untrue or incomplete, any such undertakings are not complied with, or the facts upon which the IRS supplemental private letter ruling or tax opinions (which will not impact the IRS position on the transactions) are based are different from the actual facts relating to the Merger, the tax opinions and/or supplemental private letter ruling may not be valid and could be challenged by the IRS. Even though Sempra Texas Holdings Corp. would have administrative appeal rights if the IRS were to invalidate its private letter ruling and/or supplemental private letter ruling, including the right to challenge any adverse IRS position in court, any such appeal would be costly, subject to uncertainties and could fail. If it is ultimately determined that the Merger caused the spin-off not to qualify for the Intended Tax Treatment, Sempra, through its ownership of Sempra Texas Holdings Corp., could incur substantial tax liabilities, which would materially reduce the value associated with our investment in Oncor and could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

RISKS RELATED TO SEMPRA INFRASTRUCTURE

Operational Risks

Project development activities may not be successful, projects under construction may not be completed on schedule or within budget, and completed projects may not operate at expected levels or generate expected earnings or cash flows.

Energy Infrastructure Projects

We are involved in a number of energy infrastructure projects in various stages of development and construction, which subject us to numerous risks. Success in developing each project depends on, among other things:

▪ our financial condition and cash flows and other factors that impact our ability to invest sufficient funds in the project, including for preliminary activities conducted before we determine whether the project is viable

▪ project assessment and design and our ability to foresee and incorporate emerging trends and technologies

▪ our ability to reach a positive FID or meet other milestones, which may be influenced by factors outside our control, including the global economy and energy and financial markets, actions by regulators, internal and external approval requirements, and many of the other factors described in this risk factor

▪ negotiation of satisfactory EPC agreements and renegotiation in the event of delays in reaching an FID or other specified deadlines

▪ identification of suitable partners, customers, contractors, suppliers and other necessary counterparties

▪ progressing relationships from MOUs, HOAs or other non-binding arrangements to execution of binding, definitive agreements

▪ negotiation and maintenance of satisfactory equity, purchase, sale, supply, transportation and other appropriate commercial agreements, and satisfaction of any conditions to effectiveness of such agreements, including reaching an FID within agreed timelines

▪ timely receipt and maintenance of required governmental permits, licenses and other authorizations on acceptable terms

▪ our project partners’, contractors’, equipment providers’, lenders’ and other vendors’ and counterparties’ willingness and financial or other ability to fulfill their contractual commitments

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▪ timely, satisfactory and on-budget completion of construction, which could be negatively affected by engineering problems; stakeholder relations issues, such as the opposition by some members of the Yaqui tribe to the construction of the Guaymas-El Oro segment of the Sonora pipeline, which we discuss in in Note 1 of the Notes to Consolidated Financial Statements; work stoppages; unavailability or increased costs of materials, equipment, labor and commodities due to inflation, tariffs or supply chain or other issues; and a variety of other factors, many of which we discuss above under “Risks Related to All Sempra Businesses – Operational Risks” and elsewhere in this risk factor

▪ implementation of new or changes to existing laws or regulations, including increasing influence of the Mexican government on economic and energy matters and risks related to laws and regulation in Mexico generally, which we discuss further in the risk factors below

▪ obtaining satisfactory financing for the project

▪ the absence of hidden defects or inherited environmental liabilities on the project site

▪ timely and cost-effective resolution of any litigation or unsettled property rights affecting the project

▪ geopolitical events and other uncertainties

Any failures with respect to the above factors or other factors relevant to any particular project could involve additional costs, otherwise negatively affect our ability to successfully complete the project and force us to impair or write off amounts we have invested in the project. If we are unable to complete a development project, if we experience delays, or if construction, financing or other project costs exceed our estimated budgets and we are required to make additional capital contributions, we may not receive an adequate or any return on our investment and other resources expended on the project and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.

The operation of existing facilities and any future projects we complete involves many risks, including the potential for unforeseen design flaws, engineering challenges, or breakdowns of facilities, equipment or processes; labor disputes or shortages; fuel interruption; environmental contamination; increasing regulatory requirements, including from regulations aiming to reduce GHG emissions; and the other operational risks that we discuss above under “Risks Related to All Sempra Businesses – Operational Risks.” Any of these events could lead to our facilities being idle or operating below expected levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

LNG Projects

In addition to the risks described above that are applicable to all our energy infrastructure projects, our LNG projects, which we discuss in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure,” also face distinct disadvantages relative to some LNG projects being pursued by other project developers, including:

▪ The proposed Cameron LNG Phase 2 project is subject to certain restrictions and conditions under the JV project financing agreements for the Cameron LNG Phase 1 facility and requires unanimous consent of all the members, including with respect to the equity investment obligation of each member. We may not be able to satisfy these conditions, receive members’ consent, obtain satisfactory conclusion on the EPC process, or obtain the extension of our non-FTA approval, in which case our ability to develop the Cameron LNG Phase 2 project would be jeopardized.

▪ The ECA LNG projects under construction and in development are subject to the Mexican regulatory process and an overlay of U.S. regulation for natural gas exports to LNG facilities in Mexico, which are not well developed and, among other factors, contributed to delays in obtaining a necessary permit from the Mexican government for the ECA LNG Phase 1 project and could cause similar delays or other hurdles in the future. In September 2025, we submitted a filing with the DOE to extend the construction deadline associated with our non-FTA permits for the ECA LNG Phase 1 project until the end of summer 2026, but we may not receive this extension on a timely basis or at all. In addition, the Baja California region does not have extensive sources of natural gas, and at times, natural gas supply to the region is severely constrained and may impact our costs and our ability to source all feed gas required under our ECA LNG Phase 1 supply contracts. Further, while we do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility, we expect construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which currently has a firm storage and nitrogen injection service agreement with Shell that expires in May 2028.

▪ The PA LNG Phase 1 project under construction is located at a greenfield site and is therefore subject to certain disadvantages relative to projects being constructed or developed at brownfield sites, such as increased time and costs to develop and construct the project due to lack of existing infrastructure. The PA LNG Phase 2 project under construction is located at the site of the PA LNG Phase 1 project and is therefore subject to potential disadvantages, such as increased complexity of integrating new facilities with existing infrastructure.

Development and operation of these or any other LNG projects will depend on the expansion of our existing pipeline interconnections or the ability to permit and construct new pipeline facilities, each of which may require us to enter into additional pipeline interconnection agreements with third-party pipelines, which may not be possible on reasonable terms or at all.

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The capital requirements for our LNG projects can be significant, even if we do not reach a positive FID. As has happened in the past, our proposed facilities may not be completed in accordance with estimated timelines or budgets or at all as a result of the above or other factors, and delays, cost overruns or our inability to complete one or more of these projects could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We face risks from increasing competition.

The markets in which we operate are characterized by numerous capable competitors, many of which have extensive and diversified development and/or operating experience domestically and internationally and financial resources similar to or greater than ours. In particular, the natural gas pipeline, storage and LNG market segments have been characterized by strong and increasing competition for winning new development projects and acquiring existing assets. These competitive factors could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We are exposed to additional competitive risks in connection with our LNG projects. Our ability to reach a positive FID for each development project and, if a project is completed, the overall success of the project depend in part on global energy markets, which can increase competition for global LNG demand in a number of ways. In general, depressed natural gas and LNG prices in the markets intended to be served by any of our projects, including as a result of global oil prices and their associated current and forward projections or other factors, could reduce the pricing and cost advantages of exporting natural gas and LNG produced in North America, which could lead to decreased demand from our projects. Although demand for natural gas is currently strong due to increased focus on energy security and climate aims, a reduction in natural gas demand could also occur from higher penetration of alternative fuels in new power generation, reduced economic activity in general, or as a result of calls by some to limit or eliminate global reliance on natural gas. Further, because LNG projects take a number of years to develop and construct, it is difficult to match current and expected demand with the projected supply from projects under development. Moreover, shifts in U.S. and foreign energy policy could impact supply, demand and other matters critical to LNG projects, such as permitting and other approval processes. These factors could delay or hamper the development of U.S. LNG export facilities and make LNG projects in other parts of the world more feasible and competitive with LNG projects in North America, thus increasing supply and competition for global LNG demand. Any of these occurrences could impact competition and prospects for developing LNG projects and negatively affect the performance and prospects of any of our projects that are or become operational, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We may not be able to secure, maintain, extend or replace long-term supply, sales or capacity agreements.

Certain of SI Partners’ projects, including the ECA Regas Facility, Cameron LNG JV and all of its LNG projects under construction, have long-term agreements with a limited number of customers. The long-term nature of these agreements and the small number of customers exposes us to risks, including increased credit risks and amplified impacts of disputes or other similar issues, which we have experienced in the past. Any such issues that arise in the future with respect to these long-term contracts could lead to significant legal and other costs, result in termination of certain key contracts and negatively impact the reliability of revenues from the applicable projects and the prospects of any implicated development projects. Any such event could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

SI Partners’ obligations and those of its counterparties, such as its LNG customers, are contractually subject to suspension or termination for force majeure events, which generally are beyond the control of the parties. Force majeure declarations may have attendant negative consequences, such as loss or deferral of revenue arising from non-deliveries of natural gas from suppliers or LNG to customers in certain circumstances. Also, certain force majeure events may impact the contractors constructing SI Partners’ projects, which may result in delays or increased costs. SI Partners may have limited available remedies, including limitations on damages that may prohibit recovery of all costs incurred. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

SI Partners’ ability to secure new or maintain or extend existing long-term sales or capacity agreements for its natural gas pipeline operations depends on, among other factors, demand for and supply of LNG and/or natural gas from its transportation customers, which may include our LNG facilities. A decrease in demand for or supply of LNG or natural gas from such customers or the occurrence of other events that hinder SI Partners from maintaining such agreements or establishing new ones could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

The electric generation and wholesale power sales industries are highly competitive. As more plants are built, supplies of energy and related products may exceed demand, competitive pressures may increase and wholesale electricity prices may decline or become more volatile. Without long-term power sales agreements, our revenues may be subject to increased volatility, and we may be unable to sell the power that SI Partners’ facilities can produce at favorable prices or at all, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

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We rely on transportation assets and services, much of which we do not control, to deliver natural gas and electricity.

We depend on electric transmission lines, natural gas pipelines and other transportation facilities and services owned and operated by third parties to, among other things:

▪ deliver the natural gas, LNG, electricity and LPG we sell to customers or use at our LNG facilities

▪ supply natural gas to our gas storage and electric generation facilities

▪ provide retail energy services to customers

If transportation is disrupted, the construction of necessary interconnecting infrastructure is not completed on schedule or at all or capacity is inadequate, we may be delayed in completing projects under development and/or unable to meet our contractual obligations to customers of those projects or existing projects, in which case we may be responsible for damages they incur, such as the cost of acquiring alternative supplies at then-current spot market rates, and we could lose customers that may be difficult to replace. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Financial Risks

Fixed-price long-term contracts for services or commodities expose our businesses to risks.

SI Partners seeks long-term contracts for services and commodities to better utilize its facilities, reduce volatility in earnings and support the construction of new infrastructure. Certain of these contracts are at fixed prices, and their profitability may be negatively affected by inflation, tariffs, rising interest rates and changes in applicable exchange rates. We aim to mitigate these risks by, among other things, using variable pricing tied to market indices, contracting for direct pass-through of operating costs and/or entering into hedges. However, these measures may not fully or substantially offset any increases in operating expenses or financing costs and their use could introduce additional risks, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Our international businesses and operations expose us to foreign currency exchange rate and inflation risks.

Our operations in Mexico pose foreign currency exchange rate and inflation risks. Exchange and inflation rates with respect to Mexico and fluctuations in those rates may have an impact on the revenue, cash flows and costs from our international operations, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We sometimes attempt to hedge cross-currency transactions and earnings exposure through various means, including financial instruments and short-term investments, but these hedges may not fully achieve our objectives of mitigating earnings volatility that would otherwise occur due to exchange rate fluctuations. Because we do not hedge our net investments in foreign countries, we are susceptible to volatility in OCI caused by exchange rate fluctuations for entities whose functional currencies are not the U.S. dollar. Moreover, Mexico has experienced periods of high inflation and exchange rate instability in the past, and severe devaluation of the Mexican peso could result in governmental intervention to institute restrictive exchange control policies, as has occurred in Mexico and other Latin American countries. We discuss our foreign currency exposure at our Mexican subsidiaries in “Part II – Item 7. MD&A” and “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Our businesses are exposed to fluctuations in commodity prices.

We buy energy-related commodities from time to time for pipeline operations, LNG facilities or power plants to satisfy contractual obligations with customers. The regional and other markets in which we purchase these commodities are competitive and can be subject to significant pricing volatility. Our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected if the prevailing market prices for natural gas, LNG, electricity or other commodities we buy change in a direction or manner not anticipated and for which we have not provided adequately through purchase or sale commitments or other hedging transactions.

As we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” SI Partners 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.

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If the CRNCI becomes redeemable, SI Partners may not have sufficient funds available to fulfill its obligation of 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. Because these redemption features are contingent on events not solely within SI Partners’ control, we present Blackstone’s equity interest as a CRNCI. If the CRNCI becomes redeemable, SI Partners may not have sufficient funds available to fulfill its obligation of redemption to satisfy Blackstone’s redemption right.

Legal and Regulatory Risks

Our international businesses and operations expose us to increased legal, regulatory, tax, economic, geopolitical, credit and management oversight risks and challenges.

We own or have interests in a variety of energy infrastructure assets in Mexico, and we do business with companies based in foreign markets, including particularly our LNG export operations. Conducting these activities in foreign jurisdictions subjects us to complex management, security, political, legal, economic and financial risks that vary by country, many of which may differ from and potentially be greater than those associated with our wholly domestic businesses, and the occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. These risks include the following and the other risks discussed in this risk factor below:

▪ compliance with tax, trade, environmental and other foreign laws and regulations, including legal limitations on ownership in some foreign countries and inadequate or inconsistent enforcement of regulations

▪ actions by local regulatory bodies, such as the CNE, including setting rates and tariffs that may be earned by or charged to our businesses

▪ adverse changes in social, geopolitical, economic or market conditions

▪ adverse rulings by or instability in foreign courts or tribunals

▪ challenges obtaining, maintaining and complying with permits or approvals

▪ difficulty enforcing contractual and property rights and differing legal standards

▪ expropriation or theft of assets

▪ the stability of foreign governments or such foreign governments’ relations with the U.S. government

▪ changes in the priorities and budgets of international customers, which may be driven by many of the factors listed above, among others

Mexican Government Influence on Economic and Energy Matters

The Mexican government exercises significant and increasing influence over the Mexican energy sector and has adopted additional changes that could impact private investment in this sector.

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 the 2025 Energy Laws, which 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 2025 Energy Laws give Mexican authorities broad discretion to revoke or suspend permits under certain circumstances. In October 2025, the Mexican government enacted new regulations regarding the 2025 Energy Laws, 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. Additionally, in December 2025, the Mexican government released proposed regulations that could adversely impact our self-supply power plants and the development of new power export projects by potentially increasing tariff rates and thereby reducing the competitiveness of projects operating under the self-supply framework.

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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 remains uncertain. These laws and future implementation of existing and any new regulations could adversely affect SI Partners’ ability to secure favorable rate cases and operate its existing assets at their current levels; result in increased costs to SI Partners and its customers; adversely impact SI Partners’ ability to secure and retain permits and develop new projects in Mexico; result in decreased revenues and/or cash flows; and negatively impact SI Partners’ ability to recover the carrying values of its investments in Mexico, any of which could have a material adverse impact on our business, results of operations, financial condition, cash flow and/or prospects.

In addition to the constitutional changes noted above, in 2024 the Mexican government introduced significant changes to the Mexican Constitution, including reforms requiring that all judges be elected rather than appointed, which may adversely impact, among other things, SI Partners’ ability to enforce its contracts with state-owned enterprises or challenge actions taken by regulators. These reforms and any further Mexican Constitutional, legal or regulatory changes could adversely affect the Mexican economy, energy sector and our businesses, the extent of which we currently are unable to predict.

U.S. and Foreign Laws and International Relations

Our international business activities are subject to laws and regulations in the U.S. and Mexico and other countries where we do business related to foreign operations and doing business internationally, including the U.S. Foreign Corrupt Practices Act, the Mexican Federal Anticorruption Law in Public Contracting (Ley Federal Anticorrupción en Contrataciones Públicas) and similar laws, and are sensitive to geopolitical factors in each of these countries. The current and the last U.S. Administrations have taken different stances with respect to international trade agreements, tariffs, immigration and other matters of foreign policy that impact trade and foreign relations. We discuss developments in tariff policies above under “Risks Related to All Sempra Businesses – Operational Risks.” Shifts in other aspects of foreign policy could create uncertainty and result in or increase adverse effects on our businesses. Violations or alleged violations of the laws referred to above, as well as foreign policy positions or sanctions, could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We face risks related to unsettled property rights and titles in Mexico.

We are engaged in a dispute regarding our title to property in Mexico adjacent to and owned by the ECA Regas Facility, which we discuss in Note 16 of the Notes to Consolidated Financial Statements. In addition, we have and may in the future seek to obtain long-term leases or rights-of-way from governmental agencies or other third parties to operate our energy infrastructure on land we do not own. In addition to the risks associated with such property ownership and use that we describe above under “Risks Related to All Sempra Businesses – Operational Risks,” disputes regarding ownership or rights to any of these properties could lead to difficulties developing, constructing and, if completed, operating the affected facilities or proposed projects. Any of these outcomes could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

SI Partners’ energy infrastructure assets may be considered by the Mexican government to be a public service or essential for the provision of a public service, in which case these assets and the related businesses could be subject to expropriation or nationalization, loss of concessions, renegotiation or annulment of existing contracts, and other similar risks. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

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Risk Related to Planned Sales of Certain Assets and Businesses

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 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 certain conditions, including receipt of antitrust approvals in Mexico; 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 December 2025, we entered into an agreement to sell Ecogas. We expect to complete the sale of Ecogas in the second or third quarter of 2026, subject to closing conditions. These pending sales may not 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, including with respect to our capital recycling program, 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.

Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

CYBERSECURITY RISK MANAGEMENT

Sempra, SDG&E and SoCalGas have cybersecurity risk management processes in place that are intended to protect the confidentiality, integrity, and availability of our critical infrastructure, systems and information. These cybersecurity risk management processes include cybersecurity incident response plans that are integrated into each entity’s respective enterprise risk management and emergency management programs.

Our cybersecurity processes are largely designed and assessed based on the National Institute of Standards and Technology Cybersecurity Framework and the DOE’s Cybersecurity Capability Maturity Model standards. This does not imply that we meet any technical standards, specifications, or requirements, only that we use these standards as a guide to help us identify, assess, and manage cybersecurity risks relevant to our business.

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Our cybersecurity risk management processes include:

▪ risk assessments performed by internal personnel and third-party advisors designed to help identify material cybersecurity risks to our critical systems, information, services, and our broader enterprise information technology environments

▪ cybersecurity teams principally responsible for developing and implementing (1) cybersecurity risk assessment processes, (2) cybersecurity controls, and (3) response plans to cybersecurity incidents

▪ the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our cybersecurity controls

▪ cybersecurity awareness training and policies designed to address social engineering attacks targeting employees and contractors

▪ cybersecurity incident response plans that include procedures for responding to and reporting, if applicable, certain cybersecurity incidents

▪ risk management processes for third-party service providers, suppliers, and vendors

We have not identified risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected or are reasonably likely to materially affect our results of operations, financial condition, cash flows and/or prospects.

CYBERSECURITY GOVERNANCE

Sempra’s, SDG&E’s and SoCalGas’ respective boards of directors consider cybersecurity risk as part of their risk oversight function. The Sempra board of directors has delegated to its SST Committee oversight of cybersecurity and other information and operational technology risks. The SST Committee reports to the Sempra board of directors regarding the Committee’s activities, including those related to cybersecurity. The SST Committee receives briefings on cybersecurity topics from Sempra’s chief information security officer, internal information technology leadership or external experts in part for continuing education on topics that impact public companies. The SST Committee as well as the SDG&E and SoCalGas boards of directors oversee management’s implementation of our cybersecurity risk management processes and receive regular reports from management on our material cybersecurity risks. In addition, as needed, management updates the SST Committee and SDG&E and SoCalGas boards of directors about certain cybersecurity incidents. The SDG&E and SoCalGas boards of directors receive briefings from SDG&E’s and SoCalGas’ chief information officer and internal information technology and cybersecurity leadership. SDG&E’s and SoCalGas’ boards of directors also have safety committees that, at times, may oversee the matters described above on behalf of those companies’ respective boards of directors.

We have formed cybersecurity councils to provide overall corporate oversight for managing material risks from cybersecurity threats. The cybersecurity councils meet regularly to receive updates on cybersecurity developments at Sempra and our consolidated entities from their cybersecurity management teams.

Our cybersecurity management teams supervise efforts designed to prevent, detect, mitigate, and remediate cybersecurity risks and incidents. The cybersecurity management teams receive intelligence on emerging cybersecurity threats through various means, including internal cybersecurity personnel; governmental, public and private sources; subject matter experts and consultants; and cybersecurity tools deployed in the environment. Cybersecurity management also supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Sempra’s director of cybersecurity governance & chief information security officer provides additional oversight and support for the operational cybersecurity activities at our consolidated entities.

Our cybersecurity materiality assessment teams, which include chief information security officers, chief information officers, chief accounting officers or chief financial officers, and general counsels, help assess the materiality of certain cybersecurity incidents.

The cybersecurity management teams, cybersecurity councils and materiality assessment teams include professionals with decades of experience in their respective fields of cybersecurity, information and operational technology, legal, compliance, financial reporting and enterprise risk management. Some of these professionals hold relevant degrees and certifications that we believe enhance our ability to manage and respond to cybersecurity risks, including, among others, bachelor’s and/or master’s degrees in cybersecurity and computer science as well as certified information systems security professional, certified incident handler, and certified information security manager certifications .

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ITEM 2. PROPERTIES

We own or lease land, warehouses, offices, operating and maintenance centers, shops and service facilities necessary to conduct our businesses. Each of the Registrants currently has adequate space and, if we need more space, we believe it is readily available. We discuss properties related to our electric, natural gas and energy infrastructure operations in “Part I – Item 1. Business” and Note 1 of the Notes to Consolidated Financial Statements.

ITEM 3. LEGAL PROCEEDINGS

We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses), including environmental proceedings described in Item 103(c)(3) of SEC Regulation S-K, except for the matters described in Note 16 of the Notes to Consolidated Financial Statements or referred to in “Part I – Item 1A. Risk Factors” or “Part II – Item 7. MD&A.”

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

MARKET INFORMATION

Sempra Common Stock

Our common stock is traded on the NYSE under the trading symbol SRE. At February 19, 2026, there were approximately 18,180 record holders of our common stock. Information concerning dividend declarations for Sempra is included in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sources and Uses of Cash – Dividends.”

SoCalGas and SDG&E Common Stock

Information concerning dividend declarations for SoCalGas and SDG&E is included in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sources and Uses of Cash – Dividends.”

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

On July 6, 2020, our board of directors authorized the repurchase of shares of our common stock at any time and from time to time in an aggregate amount not to exceed the lesser of $2 billion or amounts spent to purchase no more than 25,000,000 shares. This repurchase authorization was publicly announced on August 5, 2020 and has no expiration date. As of February 26, 2026, a maximum of $1.25 billion and no more than 19,632,529 shares may yet be purchased under this repurchase authorization.

ITEM 6. (RESERVED)

Not applicable.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	Page
Overview	72
Results of Operations by Registrant	73
Sempra	73
SDG&E	83
SoCalGas	86
Capital Resources and Liquidity	88
Critical Accounting Estimates	108
New Accounting Standards	112

OVERVIEW

This combined MD&A includes the operational and financial results of the following three Registrants:

▪ Sempra is a holding company whose principal businesses are regulated utilities in California and Texas. Our businesses invest in and operate electric and gas utilities and other energy infrastructure that provide energy 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.

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 have one reportable segment.

Below are significant events, including major project updates, that affected our business in 2025 and may continue to affect our future results:

▪ The 2025 Wildfire Legislation was signed into law and established, among other things, an $18 billion Continuation Account that would provide additional liquidity to reimburse catastrophic wildfire-related claims incurred by large California electric IOUs if the Wildfire Fund is depleted, and 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

▪ The CPUC issued an FD for SDG&E’s and SoCalGas’ cost of capital for 2026 through 2028

▪ The CPUC issued an FD in SDG&E’s 2024 GRC Track 2 request that authorizes partial recovery of SDG&E’s WMP costs

▪ Oncor filed its 2025 comprehensive base rate review and expects to receive a final order from the PUCT in the first half of 2026

▪ In June 2025, Texas House Bill 5247, which established the UTM, was signed into law and became effective

▪ In September 2025, we entered into an agreement to sell 45% of our equity interest in SI Partners to the KKR Partners for an aggregate base purchase price of approximately $9.99 billion, subject to adjustments, and expect the sale to close in the second or third quarter of 2026, subject to closing conditions

▪ In December 2025, we entered into an agreement to sell Ecogas for 9.0 billion Mexican pesos (approximately $500 million U.S. dollar-equivalent at December 31, 2025), subject to adjustments, and expect the sale to close in the second or third quarter of 2026, subject to closing conditions

▪ We sold a 49.9% equity interest in the PA LNG Phase 2 project to Blackstone

▪ SI Partners reached a positive FID on the PA LNG Phase 2 project and issued a full notice-to-proceed under Bechtel’s fixed-price EPC contract

▪ We invested $12.6 billion in capital expenditures and investments

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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.

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 year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion of our results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “ Part II – Item 7. MD&A – Results of Operations ” in our 2024 annual report on Form 10-K filed with the SEC on February 25, 2025. We also discuss herein the impact of foreign currency and inflation rates on Sempra’s results of operations.

RESULTS OF OPERATIONS

RESULTS OF OPERATIONS
(Dollars and shares in millions, except per share amounts)

EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra:
Sempra California	$ 1,428	$ 1,846	$ 1,747
Sempra Texas Utilities	861	781	694
Sempra Infrastructure	(160)	911	877
Segment earnings attributable to common shares	2,129	3,538	3,318
Parent and other	(333)	(721)	(288)
Earnings attributable to common shares	$ 1,796	$ 2,817	$ 3,030

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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 Consolidated Financial Statements.

In 2025 compared to 2024, the decrease in earnings of $418 million (23%) was primarily due to:

▪ $432 million charge in 2025 from regulatory disallowances related to 2019 through 2024 associated with the 2024 GRC Track 2 FD, which we discuss in Note 4 of the Notes to Consolidated Financial Statements

▪ $159 million lower income tax benefits primarily from flow-through items, including gas repairs tax benefits, offset by impacts from the election to accelerate self-developed software deductions and the resolution of prior year income tax items

▪ $63 million higher net interest expense

▪ $25 million charge in 2025 from disallowed regulatory recovery of COVID-19 costs

Offset by:

▪ $148 million higher CPUC base operating margin, net of operating expenses including higher depreciation, $44 million lower authorized cost of capital and a $32 million charge from regulatory disallowances associated with the 2024 GRC Track 2 FD related to 2025

▪ $89 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪ $15 million impairment in 2024 from disallowed capital costs in the 2024 GRC FD

Sempra Texas Utilities

In 2025 compared to 2024, the increase in earnings of $80 million (10%) was primarily due to higher equity earnings from Oncor Holdings driven by:

▪ overall higher revenues primarily attributable to:

◦ the establishment of the UTM

◦ rate updates to reflect increases in invested capital

◦ customer growth

◦ higher annual energy efficiency program performance bonus

Offset by:

▪ higher interest expense and depreciation expense associated with increases in invested capital

▪ higher O&M

Sempra Infrastructure

In 2025 compared to 2024, losses were $160 million compared to earnings of $911 million primarily due to:

▪ $703 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:

◦ $693 million income tax expense to adjust deferred income tax liabilities primarily related to outside basis differences in our investment in SI Partners

◦ $10 million income tax expense due to the recognition of a deferred tax liability on our outside basis difference in Ecogas

▪ $445 million unfavorable impact from foreign currency and inflation effects on our monetary positions in Mexico, comprised of a $181 million unfavorable impact in 2025 compared to a $264 million favorable impact in 2024

▪ $43 million lower income tax benefit primarily from outside basis differences and the remeasurement of certain deferred income taxes

▪ $30 million unfavorable impact in interest expense from unrealized gains in 2024 on interest rate swaps related to the PA LNG Phase 1 project

▪ $27 million unfavorable impact related to a customer’s early termination of firm transportation agreements, including interest expense

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▪ $21 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

Offset by:

▪ $52 million from asset and supply optimization driven by higher optimization of transport and storage contracts, higher LNG diversion fees and lower unrealized losses on commodity derivatives due to changes in natural gas prices

▪ $38 million lower O&M in 2025 primarily from lower provisions for expected credit losses

▪ $37 million lower depreciation expense as a result of management's decision to classify SI Partners and Ecogas as held for sale

▪ $31 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 that ended in December 2025

▪ $13 million higher net interest income primarily from a change in the fair value of the Support Agreement

Parent and Other

In 2025 compared to 2024, the decrease in losses of $388 million was primarily due to:

▪ $252 million from $78 million income tax expense in 2025 compared to $330 million income tax expense in 2024 from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the TCJA

▪ $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

▪ $19 million higher net investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan

▪ $15 million lower preferred dividends

Offset by:

▪ $92 million higher net interest expense

▪ $16 million equity earnings in 2024 related to our investment in RBS Sempra Commodities LLP from the substantial dissolution of the partnership

▪ $11 million preferred deemed dividends related to the redemption of series C preferred stock in 2025

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”), which may be subject to reviews for reasonableness.

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 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.

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UTILITIES: NATURAL GAS REVENUES AND COST OF NATURAL GAS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra:
Natural gas revenues:
Sempra California	$ 7,263	$ 7,083	$ 9,425
Sempra Infrastructure	78	78	87
Segment totals	7,341	7,161	9,512
Eliminations and adjustments	(22)	(20)	(17)
Total	$ 7,319	$ 7,141	$ 9,495
Cost of natural gas (1) :
Sempra California	$ 1,264	$ 1,118	$ 3,747
Sempra Infrastructure	25	22	8
Segment totals	1,289	1,140	3,755
Eliminations and adjustments	(7)	(8)	(36)
Total	$ 1,282	$ 1,132	$ 3,719

(1) Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.

In 2025 compared to 2024, Sempra’s natural gas revenues increased by $178 million (2%) driven by Sempra California, which included:

▪ $202 million higher CPUC-authorized base revenues, net of $40 million lower authorized cost of capital

▪ $146 million increase in cost of natural gas sold, which we discuss below

▪ $88 million higher revenues from incremental and balanced capital projects offset by lower authorized cost of capital

▪ $18 million higher regulatory revenues associated with refundable programs, which are fully offset in O&M

Offset by:

▪ $166 million lower regulatory revenues primarily from the release of a regulatory liability in 2024 for gas repairs tax benefits as a result of the 2024 GRC FD

▪ $57 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax expense

▪ $29 million lower revenues in 2025 from disallowed regulatory recovery of COVID-19 costs

In 2025 compared to 2024, Sempra’s cost of natural gas increased by $150 million (13%) driven by Sempra California, which included:

▪ $193 million higher average natural gas prices

Offset by:

▪ $47 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 are at SDG&E. Intercompany revenues are eliminated in Sempra’s 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.

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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)
	Years ended December 31,
	2025	2024	2023
Sempra:
Electric revenues:
Sempra California	$ 4,555	$ 4,299	$ 4,336
Eliminations and adjustments	(3)	(3)	(2)
Total	$ 4,552	$ 4,296	$ 4,334
Cost of electric fuel and purchased power (1) :
Sempra California	$ 448	$ 308	$ 445
Eliminations and adjustments	(63)	(63)	(70)
Total	$ 385	$ 245	$ 375

(1) Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.

In 2025 compared to 2024, Sempra’s electric revenues increased by $256 million (6%) driven by Sempra California, which included:

▪ $140 million increase in cost of electric fuel and purchased power, which we discuss below

▪ $94 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪ $80 million higher revenues from incremental and balanced capital projects offset by lower authorized cost of capital

▪ $36 million higher CPUC-authorized base revenues, net of $20 million lower authorized cost of capital

▪ $31 million higher revenues from transmission operations

▪ $22 million higher revenues from a $17 million cost in 2025 compared to a $5 million credit in 2024 for the non-service components of net periodic benefit cost, which fully offsets in other income, net

Offset by:

▪ $115 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax expense

▪ $23 million lower regulatory revenues associated with refundable programs, which are fully offset in O&M

▪ $21 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax expense

In 2025 compared to 2024, Sempra’s cost of electric fuel and purchased power increased by $140 million driven by Sempra California, which included:

▪ $151 million higher purchased power primarily due to changes in excess capacity sales and tolling agreements

▪ $55 million lower sales to the California ISO due to lower market prices

Offset by:

▪ $62 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)
	Years ended December 31,
	2025	2024	2023
Sempra:
Revenues:
Sempra Infrastructure	$ 1,887	$ 1,804	$ 2,984
Parent and other (1)	(56)	(56)	(93)
Total	$ 1,831	$ 1,748	$ 2,891
Cost of sales (2) :
Sempra Infrastructure	$ 367	$ 380	$ 548
Total	$ 367	$ 380	$ 548

(1) Includes eliminations of intercompany activity.

(2) Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.

In 2025 compared to 2024, Sempra’s revenues from energy-related businesses increased by $83 million (5%) primarily due to:

▪ $63 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 that ended in December 2025

▪ $59 million from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:

◦ $54 million primarily from higher diversion fees due to higher natural gas prices

◦ $36 million driven by higher natural gas prices and higher volumes associated with optimization of transport and storage contracts

Offset by:

◦ $31 million 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

▪ $14 million from TdM mainly due to lower volumes and lower power prices

In 2025 compared to 2024, Sempra’s cost of sales from energy-related businesses decreased by $13 million (3%) primarily due to:

▪ $27 million driven by lower LNG purchases offset by higher natural gas purchases related to asset and supply optimization

Offset by:

▪ $10 million higher purchased power due to higher power capacity sales

Operation and Maintenance

OPERATION AND MAINTENANCE
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra:
Sempra California	$ 4,315	$ 4,398	$ 4,591
Sempra Texas Utilities	6	5	5
Sempra Infrastructure	865	858	793
Segment totals	5,186	5,261	5,389
Parent and other (1)	95	75	69
Total	$ 5,281	$ 5,336	$ 5,458

(1) Includes eliminations of intercompany activity.

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In 2025 compared to 2024, Sempra’s O&M decreased by $55 million (1%) primarily due to:

▪ $83 million decrease at Sempra California due to:

◦ $61 million lower non-refundable operating costs

◦ $20 million impairment in 2024 from disallowed capital costs in the 2024 GRC FD

◦ $5 million lower expenses associated with refundable programs, which costs are recovered in revenue

Offset by:

▪ $20 million increase at Parent and other primarily due to non-recoverable insurance claims in 2025

▪ $7 million increase at Sempra Infrastructure due to:

◦ $42 million primarily due to higher maintenance expenses and higher expenses in 2025 in advance of ECA LNG Phase 1 commencing commercial operations

◦ $38 million higher development costs and certain non-capitalized expenses from projects under construction

Offset by:

◦ $73 million lower provisions for expected credit losses

Regulatory Disallowances

As we discuss in Note 4 of the Notes to Consolidated Financial Statements, the CPUC issued an FD in SDG&E’s 2024 GRC Track 2 request that disallowed recovery of certain WMP costs. In connection with the Track 2 FD, in the fourth quarter of 2025, SDG&E recorded a charge of $651 million ($464 million after tax), of which:

▪ $605 million ($432 million after tax) relates to 2019 through 2024

▪ $41 million ($28 million after tax) relates to the first nine months of 2025

▪ $5 million ($4 million after tax) relates to the fourth quarter of 2025

Depreciation and Amortization

In 2025 compared to 2024, Sempra’s depreciation and amortization increased by $126 million (5%) to $2.6 billion primarily due to:

▪ $199 million higher at Sempra California due to higher utility plant rate base

Offset by:

▪ $71 million lower at Sempra Infrastructure due to:

◦ $81 million lower as a result of management's decision to classify SI Partners and Ecogas as held for sale

Offset by:

◦ $11 million higher due to the commencement of commercial operations at Gasoducto Rosarito pipeline expansion in December 2024 and Topolobampo marine terminal in June 2024

Other Income, Net

In 2025 compared to 2024, Sempra’s other income, net, increased by $33 million (24%) to $169 million primarily due to:

▪ $26 million charge in 2024, comprised of $7 million of AFUDC equity and $19 million of net regulatory interest, relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪ $25 million from $11 million gains in 2025 compared to $14 million losses in 2024 driven by foreign currency transactional effects primarily at Sempra Infrastructure

▪ $17 million higher AFUDC equity primarily at Sempra Infrastructure

▪ $16 million higher net investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan at Parent and other

Offset by:

▪ $41 million higher non-service components of net periodic benefit cost primarily at Sempra California

▪ $7 million reduction in regulatory interest in 2025 from disallowed regulatory recovery of COVID-19 costs at Sempra California

We provide further details of the components of other income, net, in Note 1 of the Notes to Consolidated Financial Statements.

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Interest Income

In 2025 compared to 2024, Sempra’s interest income increased by $42 million to $103 million primarily due to:

▪ $33 million higher interest from interest bearing cash accounts primarily at Sempra Infrastructure

▪ $14 million change in the fair value of the Support Agreement at Sempra Infrastructure

Interest Expense

In 2025 compared to 2024, Sempra’s interest expense increased by $483 million (46%) to $1.5 billion primarily due to:

▪ $271 million at Sempra Infrastructure from:

◦ $241 million unfavorable impact in interest expense from interest rate swaps related to the PA LNG Phase 1 project comprised of:

• $215 million from $3 million unrealized losses in 2025 compared to $212 million unrealized gains in 2024

• $29 million settlement in 2024 from the termination of interest rate swaps

◦ $17 million higher interest expense related to a customer’s early termination of firm transportation agreements

▪ $134 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

▪ $78 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)
	Years ended December 31,
	2025	2024	2023
Sempra:
Income tax expense	$ 701	$ 219	$ 490
Income from continuing operations before income taxes and equity earnings	$ 1,169	$ 2,110	$ 2,627
Equity earnings, before income tax (1)	620	603	633
Pretax income	$ 1,789	$ 2,713	$ 3,260
Effective income tax rate	39 %	8 %	15 %

(1) We discuss how we recognize equity earnings in Note 5 of the Notes to Consolidated Financial Statements.

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.

In 2025 compared to 2024, Sempra’s income tax expense increased by $482 million primarily due to:

▪ $576 million from $240 million income tax expense in 2025 compared to $336 million income tax benefit in 2024 from foreign currency and inflation effects on our monetary positions in Mexico

▪ $516 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:

◦ $693 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

◦ $14 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

▪ $30 million income tax benefit in 2024 from an outside basis difference in a domestic partnership investment

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Offset by:

▪ $252 million from $78 million income tax expense in 2025 compared to $330 million income tax expense in 2024 from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the TCJA

▪ $173 million income tax benefit in 2025 from regulatory disallowances related to 2019 through 2024 associated with the 2024 GRC Track 2 FD

▪ lower pretax income

▪ higher income tax benefit in 2025 from higher ITCs from standalone energy storage projects

▪ 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

We discuss the impact of foreign currency exchange rates and inflation on income taxes below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.” See Notes 1 and 8 of the Notes to Consolidated Financial Statements for further details about our accounting for income taxes and items subject to flow-through treatment.

Equity Earnings

In 2025 compared to 2024, Sempra’s equity earnings decreased by $5 million remaining at $1.6 billion primarily due to:

▪ $93 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

▪ $19 million in 2024 related to our investment in RBS Sempra Commodities LLP from the substantial dissolution of the partnership

Offset by:

▪ $82 million at Oncor Holdings driven by:

◦ overall higher revenues primarily attributable to:

• the establishment of the UTM

• rate updates to reflect increases in invested capital

• customer growth

• higher annual energy efficiency program performance bonus

Offset by:

◦ higher interest expense and depreciation expense associated with increases in invested capital

◦ higher O&M

▪ $37 million at Cameron LNG JV primarily from lower interest expense, higher revenues from excess LNG and higher maintenance revenues

Earnings Attributable to Noncontrolling Interests

In 2025 compared to 2024, Sempra’s earnings attributable to NCI decreased by $400 million to $238 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 compared to unrealized gains in 2024 from interest rate swaps related to the PA LNG Phase 1 project.

IMPACT OF FOREIGN CURRENCY AND INFLATION RATES ON RESULTS OF OPERATIONS

Because Ecogas, our natural gas distribution utility in Mexico, uses the Mexican peso as its functional currency, its revenues and expenses are translated into U.S. dollars at average exchange rates for the period when included in Sempra’s results of operations. Year‑over‑year differences in average exchange rates used to translate Ecogas’ income statement activity can therefore create variances in our comparative results of operations. In 2025 compared to 2024, the impact of changes in average foreign currency translation rates on our earnings was $1 million.

Although the functional currency for most of our Mexican subsidiaries and equity method investees is the U.S. dollar, certain transactions are denominated in the local currency. These local currency transactions are remeasured into U.S. dollars, which results in transactional gains and losses recognized in other income, net, for consolidated entities and in equity earnings for equity method investments.

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We may utilize cross-currency swaps to convert Mexican peso-denominated principal and interest payments into U.S. dollars and swap Mexican fixed interest rates for U.S. fixed interest rates. The effects of these cross-currency swaps are initially recorded in OCI and are reclassified from AOCI into earnings through other income, net, and interest expense as settlements occur.

Certain of our Mexican pipelines (namely Los Ramones I and San Fernando at IEnova Pipelines and Los Ramones Norte at TAG Pipelines) generate revenue based on government-regulated tariffs with contracts denominated in Mexican pesos that are indexed to the U.S. dollar and adjusted annually for inflation and exchange rate movements. As a result, remeasurement of these peso-denominated amounts into U.S. dollars gives rise to foreign currency gains and losses. These impacts, together with the offsetting gains and losses from the settlement of related foreign currency forwards and swaps, are recorded in revenues: energy-related businesses or equity earnings.

In addition, our Mexican subsidiaries hold U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that are subject to Mexican currency exchange rate movements for Mexican income tax purposes. These subsidiaries also have significant deferred income tax assets and liabilities denominated in Mexican pesos that must be translated into U.S. dollars for financial reporting. Moreover, Mexican tax law requires monetary assets and liabilities and certain nonmonetary assets and liabilities to be adjusted for inflation. As a result, fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar and Mexican inflation can cause volatility in income tax expense, other income, net, and equity earnings. We may use foreign currency derivatives to help manage exposure to exchange rate movements on monetary assets and liabilities, with derivative impacts reflected in other income, net. However, we generally do not hedge our deferred income tax assets and liabilities, which makes us susceptible to volatility in income tax expense caused by exchange rate and inflationary changes.

The impact from fluctuations in foreign currency exchange rates and Mexican inflation on our results of operations is summarized in the following table.

TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION EFFECTS
(Dollars in millions)
	Total reported amounts			Transactional gains (losses) included in reported amounts
	Years ended December 31,
	2025	2024	2023	2025	2024	2023
Sempra:
Other income, net	$ 169	$ 136	$ 131	$ 11	$ (14)	$ 6
Income tax expense	(701)	(219)	(490)	(240)	336	(283)
Equity earnings	1,604	1,609	1,481	(41)	64	(68)
Net income	2,072	3,500	3,618	(270)	386	(345)
Earnings attributable to noncontrolling interests	(238)	(638)	(543)	90	(124)	110
Earnings attributable to common shares	1,796	2,817	3,030	(180)	262	(235)

At December 31, 2025, SI Partners, which holds our foreign operations, is classified as held for sale. Upon completion of the sale, which we expect to occur in the second or third quarter of 2026, we will deconsolidate SI Partners and account for our remaining 25% interest under the equity method, thereby reducing volatility in our results of operations associated with foreign currency exchange rate fluctuations and Mexican inflation.

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We discuss herein SDG&E’s results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion of SDG&E’s results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “ Part II – Item 7. MD&A – Results of Operations ” in our 2024 annual report on Form 10-K filed with the SEC on February 25, 2025.

RESULTS OF OPERATIONS

RESULTS OF OPERATIONS
(Dollars in millions)

In 2025 compared to 2024, the decrease in SDG&E’s earnings of $328 million (37%) was primarily due to:

▪ $432 million charge in 2025 from regulatory disallowances related to 2019 through 2024 associated with the 2024 GRC Track 2 FD, which we discuss in Note 4 of the Notes to Consolidated Financial Statements

▪ $29 million higher net interest expense

▪ $13 million lower income tax benefits primarily from flow-through items, including gas repairs tax benefits offset by the impacts from the election to accelerate self-developed software deductions

Offset by:

▪ $89 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪ $33 million higher CPUC base operating margin, net of operating expenses including higher depreciation, $32 million charge from regulatory disallowances associated with the 2024 GRC Track 2 FD related to 2025 and $19 million lower authorized cost of capital

▪ $12 million higher net regulatory interest income

▪ $6 million higher electric transmission margin

SIGNIFICANT CHANGES IN REVENUES AND COSTS

Electric Revenues and Cost of Electric Fuel and Purchased Power

In 2025 compared to 2024, SDG&E’s electric revenues increased by $255 million (6%) to $4.6 billion primarily due to:

▪ $140 million increase in cost of electric fuel and purchased power, which we discuss below

▪ $94 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪ $80 million higher revenues from incremental and balanced capital projects offset by lower authorized cost of capital

▪ $36 million higher CPUC-authorized base revenues, net of $20 million lower authorized cost of capital

▪ $31 million higher revenues from transmission operations

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▪ $22 million higher revenues from a $17 million cost in 2025 compared to a $5 million credit in 2024 for the non-service components of net periodic benefit cost, which fully offsets in other income, net

Offset by:

▪ $115 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax benefit (expense)

▪ $23 million lower regulatory revenues associated with refundable programs, which are fully offset in O&M

▪ $21 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax benefit (expense)

In 2025 compared to 2024, SDG&E’s cost of electric fuel and purchased power increased by $140 million (45%) to $448 million primarily due to:

▪ $151 million higher purchased power primarily due to changes in excess capacity sales and tolling agreements

▪ $55 million lower sales to the California ISO due to lower market prices

Offset by:

▪ $62 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

SDG&E’s average cost of natural gas per thousand cubic feet was $5.40 in 2025 and $5.41 in 2024. The average cost of natural gas sold at SDG&E is impacted by market prices, as well as transportation, tariff and other charges.

In 2025 compared to 2024, SDG&E’s natural gas revenues increased by $101 million (10%) to $1.1 billion primarily due to:

▪ $62 million higher regulatory revenues associated with refundable programs, which are fully offset in O&M

▪ $40 million higher CPUC-authorized base revenues, net of $6 million lower authorized cost of capital

▪ $29 million higher revenues from incremental and balanced capital projects offset by lower authorized cost of capital

Offset by:

▪ $37 million lower regulatory revenues primarily from the release of a regulatory liability in 2024 for gas repairs tax benefits as a result of the 2024 GRC FD

Operation and Maintenance

In 2025 compared to 2024, SDG&E’s O&M increased by $33 million (2%) remaining at $1.7 billion primarily due to:

▪ $39 million higher expenses associated with refundable programs, which costs are recovered in revenue

Offset by:

▪ $9 million lower non-refundable operating costs

Regulatory Disallowances

As we discuss in Note 4 of the Notes to Consolidated Financial Statements, the CPUC issued an FD in SDG&E’s 2024 GRC Track 2 request that disallowed recovery of certain WMP costs. In connection with the Track 2 FD, in the fourth quarter of 2025, SDG&E recorded a charge of $651 million ($464 million after tax), of which:

▪ $605 million ($432 million after tax) relates to 2019 through 2024

▪ $41 million ($28 million after tax) relates to the first nine months of 2025

▪ $5 million ($4 million after tax) relates to the fourth quarter of 2025

Other Income, Net

In 2025 compared to 2024, SDG&E’s other income, net, increased by $16 million (18%) to $106 million primarily due to:

▪ $26 million charge in 2024, comprised of $7 million of AFUDC equity and $19 million of net regulatory interest, relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019

▪ $17 million higher net interest income on regulatory balancing accounts

Offset by:

▪ $31 million decrease from a $27 million cost in 2025 compared to $4 million credit in 2024 for the non-service components of net periodic benefit cost

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Income Taxes

INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
SDG&E:
Income tax (benefit) expense	$ (128)	$ 153	$ (26)
Income before income taxes	$ 435	$ 1,044	$ 910
Effective income tax rate	(29) %	15 %	(3) %

In 2025 compared to 2024, SDG&E had an income tax benefit in 2025 compared to income tax expense in 2024 primarily due to:

▪ $173 million income tax benefit in 2025 from regulatory disallowances related to 2019 through 2024 associated with the 2024 GRC Track 2 FD

▪ higher income tax benefit in 2025 from higher ITCs from standalone energy storage projects

▪ 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 8 of the Notes to Consolidated Financial Statements

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We discuss herein SoCalGas’ results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion of SoCalGas’ results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “ Part II – Item 7. MD&A – Results of Operations ” in our 2024 annual report on Form 10-K filed with the SEC on February 25, 2025.

RESULTS OF OPERATIONS

RESULTS OF OPERATIONS
(Dollars in millions)

In 2025 compared to 2024, the decrease in SoCalGas’ earnings of $90 million (9%) was primarily due to:

▪ $146 million lower income tax benefits primarily from flow-through items including gas repairs tax benefits, offset by the resolution of prior year income tax items and impacts from the election to accelerate self-developed software deductions

▪ $34 million higher net interest expense

▪ $25 million charge in 2025 from disallowed regulatory recovery of COVID-19 costs

▪ $8 million lower net regulatory interest income

▪ $6 million lower regulatory award approved by the CPUC

Offset by:

▪ $115 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $25 million lower authorized cost of capital

▪ $15 million impairment in 2024 from disallowed capital costs in the 2024 GRC FD

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SIGNIFICANT CHANGES IN REVENUES AND COSTS

Natural Gas Revenues and Cost of Natural Gas

SoCalGas’ average cost of natural gas per thousand cubic feet was $3.92 in 2025 and $3.28 in 2024. The average cost of natural gas sold at SoCalGas is impacted by market prices, as well as transportation and other charges.

In 2025 compared to 2024, SoCalGas’ natural gas revenues increased by $82 million (1%) to $6.3 billion primarily due to:

▪ $162 million higher CPUC-authorized base revenues, net of $34 million lower authorized cost of capital

▪ $139 million increase in cost of natural gas sold, which we discuss below

▪ $59 million higher revenues from incremental and balanced capital projects offset by lower authorized cost of capital

Offset by:

▪ $129 million lower regulatory revenues primarily from the release of a regulatory liability in 2024 for gas repairs tax benefits as a result of the 2024 GRC FD

▪ $54 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax benefit (expense)

▪ $44 million lower regulatory revenues associated with refundable programs, which are fully offset in O&M

▪ $29 million lower revenues in 2025 from disallowed regulatory recovery of COVID-19 costs

▪ $9 million lower regulatory award approved by the CPUC

In 2025 compared to 2024, SoCalGas’ cost of natural gas increased by $139 million (14%) to $1.1 billion due to:

▪ $181 million higher average natural gas prices

Offset by:

▪ $42 million lower volumes driven by weather

Operation and Maintenance

In 2025 compared to 2024, SoCalGas’ O&M decreased by $102 million (4%) to $2.7 billion due to:

▪ $44 million lower expenses associated with refundable programs, which costs are recovered in revenue

▪ $38 million lower non-refundable operating costs

▪ $20 million impairment in 2024 from disallowed capital costs in the 2024 GRC FD

Other (Expense) Income, Net

In 2025 compared to 2024, SoCalGas’ other expense, net, was $6 million compared to other income, net, of $25 million primarily due to:

▪ $13 million higher non-service components of net periodic benefit cost

▪ $11 million lower net interest income on regulatory balancing accounts

▪ $7 million reduction in regulatory interest in 2025 from disallowed regulatory recovery of COVID-19 costs

Income Taxes

INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
SoCalGas:
Income tax (benefit) expense	$ (38)	$ 31	$ (5)
Income before income taxes	$ 828	$ 987	$ 807
Effective income tax rate	(5) %	3 %	(1) %

In 2025 compared to 2024, SoCalGas had an income tax benefit in 2025 compared to income tax expense in 2024 primarily due to:

▪ lower pretax income

▪ 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 8 of the Notes to Consolidated Financial Statements

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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 enhance shareholder value. 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. In December 2025, we entered into an agreement to sell Ecogas for 9.0 billion Mexican pesos (approximately $500 million U.S. dollar-equivalent at December 31, 2025), subject to adjustments. We expect to complete the sales in the second or third quarter of 2026, subject to closing conditions. We discuss these sales further in Note 6 of the Notes to Consolidated Financial Statements and below in “Sempra Infrastructure.”

Liquidity

We expect to meet our cash requirements primarily 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 owners 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 contributions

▪ 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 or 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 13 of the Notes to 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 below and in Note 7 of the Notes to 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 per share. 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 December 31, 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 December 31, 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 December 31, 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 13 of the Notes to Consolidated Financial Statements.

Available Funds

Our committed lines of credit provide liquidity and support commercial paper. Sempra, SDG&E and SoCalGas each have 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 are sources of available credit to Sempra Infrastructure until the planned sale of a portion of our equity interest in SI Partners closes.

AVAILABLE FUNDS AT DECEMBER 31, 2025
(Dollars in millions)
	Sempra	SDG&E	SoCalGas
Unrestricted cash and cash equivalents (1)	$ 141	$ 7	$ 14
Available unused credit (2)	7,721	968	696

(1) Sempra includes $81 held in foreign jurisdictions, which is included in the $112 that is classified as Assets Held for Sale in the Sempra Consolidated Balance Sheet. We discuss repatriation in Note 8 of the Notes to Consolidated Financial Statements.

(2) Available unused credit is the total available on committed and uncommitted lines of credit that we discuss in Note 7 of the Notes to Consolidated Financial Statements. Because our commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding 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 2025.

We discuss our short-term debt activities in Note 7 of the Notes to Consolidated Financial Statements and below in “Sources and Uses of Cash.”

The following table shows selected statistics for our commercial paper borrowings.

COMMERCIAL PAPER STATISTICS
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
	December 31,
	2025	2024	2025	2024	2025	2024
Amount outstanding at period end	$ 2,019	$ 754	$ 532	$ 417	$ 504	$ 337
Weighted-average interest rate at period end	4.00 %	4.67 %	3.96 %	4.76 %	3.89 %	4.56 %
Daily weighted-average outstanding balance	$ 1,335	$ 1,320	$ 202	$ 161	$ 356	$ 313
Daily weighted-average yield	3.63 %	4.74 %	3.02 %	2.46 %	4.33 %	4.98 %
Maximum daily amount outstanding	$ 2,593	$ 2,503	$ 670	$ 696	$ 787	$ 966

Long-Term Debt Activities

Significant issuances of and payments on long-term debt in 2025 included the following:

LONG-TERM DEBT ISSUANCES AND PAYMENTS
(Dollars in millions)
Issuances:	Amount at issuance	Maturity
Sempra 6.375% junior subordinated notes	$ 800	2056
SDG&E 5.40% first mortgage bonds	850	2035
SoCalGas 5.45% first mortgage bonds	600	2035
SoCalGas 6.00% first mortgage bonds	500	2055
Sempra Infrastructure variable rate notes (ECA LNG Phase 1 project)	449	2027
Sempra Infrastructure variable rate term loan (PA LNG Phase 1 project)	3,062	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:	Payments	Maturity
SoCalGas 3.20% first mortgage bonds	$ 350	2025
Sempra 3.30% notes	750	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, 2034	49	2034

At December 31, 2025, Sempra expects to make interest payments on long-term debt totaling $27.0 billion, of which $1.4 billion is expected to be paid in 2026 and $25.6 billion is expected to be paid in subsequent years through 2079. These amounts exclude the disposal group that is classified as held for sale, which has expected interest payments on long-term debt totaling $3.3 billion, of which $400 million is expected to be paid in 2026 and $2.9 billion is expected to be paid in subsequent years through 2051. At December 31, 2025, SDG&E expects to make interest payments on long-term debt totaling $6.7 billion, of which $400 million is expected to be paid in 2026 and $6.3 billion is expected to be paid in subsequent years through 2054. At December 31, 2025, SoCalGas expects to make interest payments on long-term debt totaling $6.5 billion, of which $400 million is expected to be paid in 2026 and $6.1 billion is expected to be paid in subsequent years through 2055. We calculate expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps. We calculate expected interest payments for variable-rate obligations based on forecasted rates in effect at December 31, 2025.

We discuss our long-term debt activities, including the use of proceeds on long-term debt issuances, and maturities in Note 7 of the Notes to Consolidated Financial Statements.

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Credit Ratings

The credit ratings of Sempra, SDG&E and SoCalGas remained at investment grade levels in 2025.

ISSUER CREDIT RATINGS AT DECEMBER 31, 2025	Sempra	SDG&E	SoCalGas
Moody’s	Baa2 with a negative outlook	A3 with a stable outlook	A2 with a stable outlook (1)
S&P	BBB+ with a negative outlook	BBB+ with a stable outlook	A- with a stable outlook
Fitch	BBB+ with a stable outlook	BBB+ with a stable outlook	A with a stable outlook

(1) Reflects the senior unsecured rating, as no issuer credit rating is available.

A downgrade of Sempra’s or any of its subsidiaries’ credit ratings or rating outlooks (which occurred in January 2025 with respect to S&P’s rating outlook for Sempra and credit rating for SoCalGas and in March 2025 with respect to Moody’s rating outlook for Sempra) 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.”

Sempra has agreed that, if the credit rating of Oncor’s senior secured debt by any of the Rating Agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. Oncor’s senior secured debt was rated A2, A and A at Moody’s, S&P and Fitch, respectively, at December 31, 2025.

Sempra, SDG&E and SoCalGas have committed lines of credit to provide liquidity and to support commercial paper. Borrowings under these facilities bear interest at benchmark rates plus a margin that varies with market index rates and each borrower’s credit rating. Each facility also requires a commitment fee on available unused credit that may be impacted by each borrower’s credit rating. For example, assuming a one-notch downgrade:

▪ If Sempra were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 bps. The commitment fee on available unused credit would also increase 5 bps.

▪ If SDG&E were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 5 bps.

▪ If SoCalGas were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 2.5 bps.

Sempra’s, SDG&E’s and SoCalGas’ credit ratings also may affect their respective credit limits related to derivative instruments, as we discuss in Note 10 of the Notes to Consolidated Financial Statements.

Postretirement Benefits

Sempra, SDG&E and SoCalGas have significant investments in several trusts to provide for future payments of pensions and PBOP. The trusts’ ability to make ongoing required benefit payments has not been materially adversely affected by changes in asset values, which are dependent on market fluctuations, contributions and withdrawals. However, changes in asset values or other factors in future periods (such as changes to discount rates, assumed rates of return, mortality tables and regulations) may impact funding requirements for pension and PBOP plans. Additionally, contributions to our plans are based on our funding policy, which generally limits payments from exceeding plan assets of 110% of the projected benefit obligation, which are subject to maximum income tax deduction limitations. Sempra, SDG&E and SoCalGas expect to contribute $240 million, $56 million and $152 million, respectively, to pension and PBOP plans in 2026 and $1.2 billion, $494 million and $590 million, respectively, in the nine years thereafter. Sempra’s amounts exclude $2 million in 2026 and $29 million in the nine years thereafter related to the disposal group that is classified as held for sale. At SDG&E and SoCalGas, funding requirements are generally recoverable in rates. We discuss our employee benefit plans and our expected contributions to those plans in Note 9 of the Notes to Consolidated Financial Statements.

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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. 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 as approved by their respective boards of directors.

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, any delay in payments by customers impacts the timing of their respective cash flows.

As we discuss in Note 4 of the Notes to 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 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. 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.

Petition for Modification. In December 2025, SDG&E and SoCalGas filed a petition for modification of the 2024 GRC, seeking to modify the post-test year mechanism for capital related costs. The petition for modification seeks increases of $55 million, $87 million and $79 million to the approved revenue requirements for SDG&E for 2025, 2026 and 2027, respectively, and increases of $86 million, $122 million and $109 million to the approved revenue requirements for SoCalGas for 2025, 2026 and 2027, respectively. There is no established timeline for the CPUC to act on this filing.

Existing and Anticipated Requests for Recovery of Specified Safety, Maintenance and Reliability Investments. 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. 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 $1,472 million of WMP costs incurred from 2019 through 2022 that were incremental to amounts authorized in the 2019 GRC and not otherwise addressed in the 2024 GRC FD. In January 2026, the CPUC issued an FD in SDG&E’s Track 2 request that approves recovery of $1,023 million of these requested costs, including $78 million of O&M costs and $945 million of capital costs. The Track 2 FD allows SDG&E to seek recovery in Track 3 of this proceeding of the drone inspection and repair program costs that were disallowed in the Track 2 FD.

The Track 2 request also addresses SDG&E’s requested revenue requirement for the period from 2019 through 2027 for ongoing capital-related costs for capital assets placed into service from 2019 through 2022. The FD authorizes a total Track 2 revenue requirement of $707 million for 2019 through 2027, which is $441 million lower than SDG&E’s requested revenue requirement of $1,148 million. In February 2024, the CPUC authorized an interim cost recovery mechanism that permitted SDG&E to collect in rates $194 million and $96 million of this revenue requirement in 2024 and 2025, respectively. The FD authorizes SDG&E to collect the remaining $417 million from 2026 through 2028.

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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 WMP costs incurred in 2023 that were in addition to the amounts authorized in the 2019 GRC and not addressed in the 2024 GRC. SDG&E expects to provide supplemental testimony in its Track 3 request for drone inspection and repair program costs that were disallowed in its Track 2 request. SDG&E expects to receive a PD for its Track 3 request related to its WMP costs in the second half of 2026. Additionally, SDG&E and SoCalGas submitted a combined request seeking review and recovery of $240 million of PSEP costs incurred from 2014 through 2019 and $499 million of PSEP costs incurred from 2015 through 2020. SDG&E and SoCalGas expect to receive a PD for their Track 3 requests related to their PSEP costs in the first half of 2026.

Revenue requirements associated with the Track 3 requests have been recorded in regulatory accounts and disallowances resulting from Track 3 would be recorded as an expense on the Sempra, SDG&E and SoCalGas Consolidated Statements of Operations. 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.

Accounting Impact of Regulatory Disallowances. In connection with the Track 2 FD, in the fourth quarter of 2025, SDG&E recorded a charge of $651 million ($464 million after tax) in Regulatory Disallowances on the SDG&E and Sempra Consolidated Statements of Operations, of which $605 million ($432 million after tax) relates to 2019 through 2024, $41 million ($28 million after tax) relates to the first nine months of 2025, and $5 million ($4 million after tax) relates to the fourth quarter of 2025.

CPUC Cost of Capital

In December 2025, the CPUC approved an FD in SDG&E’s and SoCalGas’ applications seeking to update their cost of capital, effective January 1, 2026 through December 31, 2028, subject to the CCM. The FD maintains the current authorized capital structure with an equity layer of 52% and authorizes an ROE of 9.93% and 9.78% for SDG&E and SoCalGas, respectively. We further discuss the cost of capital and CCM in Note 4 of the Notes to Consolidated Financial Statements.

SDG&E

Golden Pacific Powerlink

The California ISO’s 2022-2023 Transmission Plan identified the need for 45 transmission projects throughout the state to improve resiliency and modernize the region’s energy grid. As part of the Transmission Plan, SDG&E expects to construct, own and operate a 500-kV transmission line, referred to as the Golden Pacific Powerlink, that is slated to run through SDG&E’s service territory between the existing Imperial Valley Substation and the border of San Diego and Orange Counties.

SDG&E anticipates filing for a certificate of public convenience and necessity from the CPUC in the second half of 2026 that will include proposed routing and design elements. The Transmission Plan estimates construction on the Golden Pacific Powerlink transmission line to begin in 2029, with a target in-service date of 2034, subject to obtaining necessary state and federal agency approvals and permits.

Wildfire Fund and Continuation Account

The 2019 Wildfire Legislation established the Wildfire Fund and the 2025 Wildfire Legislation established the Continuation Account (collectively, the Wildfire Legislation), which offer liquidity to reimburse wildfire-related claims incurred by participating California electric IOUs in excess of $1 billion, subject to the coverage of each fund. The Wildfire Fund and the Continuation Account, if it becomes operative, could be materially reduced, exhausted, or terminated due to claims by SDG&E or other participating IOUs related to fires caused by utility conduct or operations, or SDG&E could fail to maintain a valid annual safety certification from the OEIS or meet other requirements, any of which could result in SDG&E losing eligibility for the Wildfire Legislation’s liability cap and the other protections afforded by these funds. As a result, a fire resulting from the conduct or operations of any participating California electric IOU could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects, with potentially material additional exposure if SDG&E’s conduct or operations is determined to be a cause of a fire and SDG&E is found to have acted imprudently.

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.

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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 $260 million at December 31, 2025.

In February 2026, a participating IOU publicly disclosed that it has received, or expects to receive, approximately $1.26 billion in aggregate reimbursements from the Wildfire Fund for eligible claims related to wildfires that occurred in 2019 and 2021. Also in February 2026, another participating IOU publicly disclosed it has received, or expects to receive, approximately $134 million in aggregate reimbursements from the Wildfire Fund for losses incurred and expected to be incurred in connection with one of the LA Fires, the cause of which remains under investigation and has not been conclusively determined. The administrator of the Wildfire Fund has confirmed that this wildfire qualifies as a “covered wildfire” for purposes of accessing the Wildfire Fund, and the scope of potential damages caused by this fire could materially reduce or exhaust the Wildfire Fund. The participating IOU 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. In addition to the risks described above, a material reduction, exhaustion or termination of the Wildfire Fund may require SDG&E to recognize a reduction to its Wildfire Fund asset up to its carrying value.

2025 Wildfire Legislation. We describe the 2025 Wildfire Legislation that was signed into law in September 2025 in Note 1 of the Notes to 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 participating California electric IOUs, including SDG&E, if (i) the Wildfire Fund is anticipated to be depleted or (ii) a catastrophic fire igniting after September 19, 2025 and before December 31, 2028 results in claims expected to exceed $1 billion. 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 standards and requirements for recovery of costs related to catastrophic wildfire-related claims, a liability cap 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 also established 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.

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 proposed, 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. In February 2026, the settlement judge in the TO6 proceeding reported to the FERC that the participants had reached an agreement in principle on all issues in the proceeding. The parties will draft an offer of settlement to be filed with the FERC for approval.

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SONGS Decommissioning

SDG&E has significant investments in the SONGS NDT to provide for future payments of nuclear decommissioning. The NDT’s ability to make ongoing required payments has not been materially or adversely affected by changes in asset values, which are dependent on market fluctuations, contributions and withdrawals. However, asset values could be materially and adversely affected by future activity in the equity and fixed income markets, and changes in the estimated decommissioning costs, or in the assumptions and judgments made by management underlying these estimates, could cause revisions to the estimated total cost associated with retiring the assets. Funding requirements are generally recoverable in rates. We discuss SDG&E’s NDT and its expected SONGS decommissioning payments in Note 15 of the Notes to Consolidated Financial Statements.

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 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 year ended December 31, 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’ Consolidated Statements of Operations. The CPUC denied SoCalGas’ request for a rehearing of the FD.

LA Fires

The LA Fires burned in SoCalGas’ service territory. The California Department of Forestry and Fire Protection estimates that the Palisades and Eaton fires destroyed approximately 16,200 structures and damaged approximately 2,000 structures. Although the majority of SoCalGas’ infrastructure in the fire-affected areas is underground, these fires resulted in service disruptions, response costs and damage to some of SoCalGas’ infrastructure and third-party property. SoCalGas and Sempra are subject to pending litigation with respect to the operation of SoCalGas’ system and damage sustained as a result of the fires, which we discuss in Note 16 of the Notes to Consolidated Financial Statements. We cannot estimate the timing, costs, other impacts or ultimate outcome of these matters, which are inherently uncertain and subject to a number of risks that we discuss in “Part I – Item 1A. Risk Factors.”

SoCalGas has mechanisms available for potential recovery of costs associated with declared disasters and related litigation, including through insurance, third parties and customer rates. Failure by SoCalGas to timely recover all or a substantial portion of its costs related to the LA Fires or any conclusion that such recovery is no longer probable could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

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, effective July 1, 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 is unable 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.

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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%, which 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.

On January 29, 2026, Oncor filed a stipulation in the comprehensive base rate review proceeding requesting PUCT approval of an unopposed, comprehensive settlement among the parties to the proceeding. Among other things, the stipulation provides for an increase of approximately 8.8% over the adjusted annualized present revenues provided in the rate application. If approved as requested, Oncor estimates the terms of the stipulation would result in an aggregate annualized increase over those revenues of approximately $560 million. Moreover, the stipulation also provides for a revised regulatory capital structure ratio of 56.5% debt to 43.5% equity, an authorized ROE of 9.75%, and an authorized cost of debt of 4.94%.

The PUCT may choose to adopt, modify, or reject the stipulation and the proposed order included in the stipulation. Oncor expects the PUCT to issue a final order in the proceeding in the first half of 2026. New billing rates would be implemented after that final order. If the proposed new rates in the stipulation are approved as requested, Oncor will surcharge the difference between those new rates and its current rates back to January 1, 2026, pursuant to a previously approved settlement regarding interim rates.

Unified Tracker Mechanism. In June 2025, Texas House Bill 5247 was signed into law and became effective. The bill established the UTM, which allows qualifying electric utilities to apply for a single interim rate update annually through 2035 for cost recovery of certain transmission and distribution capital investments.

Oncor expects to make its first comprehensive UTM filing on or after March 16, 2026 with a view toward recovering the costs associated with eligible transmission and distribution investments that were placed into service after December 31, 2024 through December 31, 2025 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 December 31, 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

In November 2025, the PUCT approved Sharyland Utilities’ 2025 rate case, setting its total revenue requirement 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%.

Off-Balance Sheet Arrangement

Our investment in Oncor Holdings is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.

Sempra Infrastructure

Sempra Infrastructure expects to fund capital expenditures, investments and operations in part with available funds, including 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 2025, 2024 and 2023, Sempra Infrastructure distributed $609 million, $297 million and $730 million, respectively, to its NCI owners, and NCI owners contributed $327 million, $1,235 million and $1,770 million, respectively, to Sempra Infrastructure.

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.

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With respect to projects in development, these risks and uncertainties include a variety of factors as applicable depending on the project and many of which are outside our control, including 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 and any applicable approvals in Mexico

▪ 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, stakeholder relations issues 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.”

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. The descriptions below also discuss certain financing arrangements for several of Sempra Infrastructure’s projects in development and under construction; we discuss these and other financing arrangements related to these projects in more detail in Note 7 of the Notes to Consolidated Financial Statements.

With respect to each project described below that has reached a positive FID, long-term definitive offtake agreements have been secured with third parties for the full initial offtake or generation capacity of the applicable project, other than an SPA with SI Partners for a portion of the offtake from the PA LNG Phase 2 project, which SI Partners intends to resell to third parties under offtake arrangements it plans to establish from time to time. We describe these SPAs in “Part I – Item 1. Business.”

SI Partners

As we discuss in Note 6 of the Notes to 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 certain conditions, including receipt of antitrust approvals in Mexico; 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. As a result of satisfying all applicable criteria in September 2025, we classified SI Partners’ assets and liabilities as held for sale and ceased depreciation and amortization.

The agreement provides that, subject to adjustments described in Note 6 of the Notes to 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. We will then deconsolidate SI Partners and account for our 25% interest in SI Partners under the equity method within the existing Sempra Infrastructure segment. For a description of Sempra’s December 31, 2025 and projected post-sale ownership interest in certain Sempra Infrastructure facilities and projects, see “Part I – Item 1. Business.”

Tab le of Cont ents

The rights and obligations of the partners of SI Partners are governed by a limited partnership agreement, which will be amended and restated at closing. This limited partnership agreement contains certain provisions on project funding and distributions that could impact Sempra’s results of operations and cash flows. For instance, the existing limited partnership agreement provides for certain priority distributions to one or more of the minority partners if certain cash flow or rate of return performance levels are not achieved or a specified project that reaches a positive FID does not meet certain other conditions by certain dates. In addition, the post-closing limited partnership agreement provides that Sempra will continue to have substantially similar funding obligations as it has before the sale for cost overruns in the ECA LNG Phase 1 project and the PA LNG Phase 1 project. For more information about the terms of the limited partnership agreement, see “Part I – Item 1. Business” and Note 6 of the Notes to Consolidated Financial Statements.

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 and FTA and non-FTA approvals associated with the potential expansion. In November 2025, we received approval from the FERC to extend the deadline for construction authorization until March 2033. 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 DOE to extend that deadline to the first quarter of 2033.

SI Partners and the other Cameron LNG JV members, namely affiliates of TotalEnergies SE, Mitsui & Co., Ltd. and Japan LNG Investment, LLC, 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 renewable sources in Louisiana.

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 certain ongoing engineering processes and selection of an EPC contractor, 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 SI Partners’ 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.

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.

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 of approximately $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. The ECA LNG Phase 1 project achieved mechanical completion in December 2025, and we expect the 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.

Tab le of Cont ents

ECA LNG Phase 1’s customers have a termination right under their SPAs if the ECA LNG Phase 1 project does not commence commercial operations under the SPAs by February 24, 2026, subject to certain additional conditions. As of February 26, 2026, no customers have given notice of their intent to terminate the SPAs.

ECA LNG Phase 1 has a loan agreement with a borrowing capacity of $1.5 billion that matures in December 2027. At December 31, 2025 and 2024, $1.3 billion and $1.1 billion, respectively, of borrowings were outstanding under the loan agreement. 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 project and the ECA LNG Phase 2 project that we discuss below, 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 16 of the Notes to Consolidated Financial Statements, could have a material adverse effect on the development and construction of these projects.

ECA LNG Phase 2 Project. SI Partners is developing a second, large-scale natural gas liquefaction project at the site of its existing ECA Regas Facility in Baja California, Mexico. We expect the proposed ECA LNG Phase 2 project to be comprised of multiple trains and one additional LNG storage tank and produce approximately 12 Mtpa of export capacity. We expect that future construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which has a firm storage and nitrogen injection service agreement that expires in May 2028, to the extent this agreement has not expired or has 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 February 2026, the DOE extended the construction deadline associated with the project to December 2029.

We have non-binding MOUs and/or HOAs that provide a framework for potential offtake of LNG from the proposed ECA LNG Phase 2 project and potential acquisition of equity interests in ECA LNG Phase 2.

PA LNG Phase 1 Project. SI Partners 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.

SI Partners has received authorizations from the DOE that permit the export of LNG to be produced from the PA LNG Phase 1 project to all current and future FTA and non-FTA countries, and from the FERC for the siting, construction and operation of the PA LNG Phase 1 project.

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, with capital expenditures for the project of 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 substantially from our estimates. The first train of the Port Arthur LNG liquefaction project remains on schedule, and we continue to expect the first and second trains to commence commercial operations at or near the end of 2027 and in 2028, respectively.

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 December 31, 2025, $3.2 billion of borrowings were outstanding and previous borrowings of $983 million have been repaid and cannot be reborrowed 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.

As we discuss in Note 13 of the Notes to 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 December 31, 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.

As we discuss in Note 16 of the Notes to 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 SI Partners but has released the site. OSHA’s inspection of SI Partners concluded without the issuance of citations to SI Partners. Bechtel is continuing construction of the PA LNG Phase 1 project. As of February 19, 2026, there are two pending lawsuits filed by 17 plaintiffs related to the incident. Bechtel is providing indemnity pursuant to the terms of Port Arthur LNG I’s EPC contract.

Tab le of Cont ents

PA LNG Phase 2 Project. Since reaching a positive FID in September 2025, SI Partners has commenced construction of a second phase of the Port Arthur LNG 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.

SI Partners has received authorizations from the DOE that permit the export of LNG to be produced from the PA LNG Phase 2 project to all current and future FTA and non-FTA countries, and from the FERC for the siting, construction and operation of the PA LNG Phase 2 project.

In addition to the definitive SPAs that we discuss in “Part I – Item 1. Business,” SI Partners has a non-binding HOA with Aramco International Gas Holding Co B.V. contemplating a 20-year SPA for 5 Mtpa of LNG offtake and a 25% participation in project-level equity from the PA LNG Phase 2 project. The HOA will terminate in March 2026.

We have an EPC contract with Bechtel to construct the PA LNG Phase 2 project, which has an estimated price of approximately $9.2 billion, with capital expenditures of 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.

As we discuss in Note 12 of the Notes to 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 CRNCI in Sempra’s Consolidated Balance Sheet.

To secure gas supply for the PA LNG Phase 2 project, SI Partners 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. SI Partners holds a contractual option to acquire the third party’s interest in the pipeline if certain construction milestones are not met, which acquisition would release SI Partners from the associated capacity commitment.

Vista Pacifico LNG Project. In partnership with the CFE, SI Partners was 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. Due to a change in SI Partners’ and the CFE’s respective priorities, in December 2025, we agreed to terminate the existing development agreement.

Asset and Supply Optimization. As we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” SI Partners 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 Consolidated Financial Statements.

In February 2025, SI Partners entered into a credit support agreement related to a customer’s secured borrowing for repayment of its past due account balance, 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 16 of the Notes to Consolidated Financial Statements.

In June 2021, Sempra provided a promissory note, which constitutes a guarantee for the benefit of Cameron LNG JV with a maximum exposure to loss of $165 million. The guarantee will terminate upon full repayment of Cameron LNG JV’s debt, scheduled to occur in 2039, or replenishment of the amount withdrawn by Sempra from the SDSRA. We discuss this guarantee in Note 16 of the Notes to Consolidated Financial Statements.

Tab le of Cont ents

In July 2020, Sempra entered into the 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 and 16 of the Notes to Consolidated Financial Statements.

Energy Networks

Ecogas. As we discuss in Note 6 of the Notes to Consolidated Financial Statements, in December 2025, we entered into an agreement to sell Ecogas to Gas Natural del Noroeste S.A. de C.V. for 9.0 billion Mexican pesos (approximately $500 million U.S. dollar-equivalent at December 31, 2025), subject to adjustments. In the first quarter of 2026, we entered into contingent foreign currency hedges that are designed to lock in the exchange rate associated with the anticipated after-tax net proceeds. We expect to complete the sale in the second or third quarter of 2026, subject to closing conditions. As a result of satisfying all applicable criteria in June 2025, we classified Ecogas’ assets and liabilities as held for sale and ceased depreciation and amortization.

Louisiana Storage. SI Partners 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. 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. We expect Louisiana Storage to be ready for service in time to support the needs of the PA LNG Phase 1 project.

Port Arthur Pipeline Louisiana Connector. SI Partners is constructing the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana.

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 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. The Port Arthur Pipeline Louisiana Connector achieved mechanical completion in January 2026, and we expect it to be ready for service ahead of the PA LNG Phase 1 project’s gas requirements.

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.

In December 2025, Sempra Infrastructure and the CFE further amended their transportation services agreement to re-route the portion of the pipeline that is in the Yaqui territory, whereby the CFE has agreed to reimburse Sempra Infrastructure for the re-routing costs with a new tariff and requires the pipeline to be back in service no later than July 2029. 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. Additionally, in December 2025, Sempra Infrastructure and the CFE entered into a non-binding agreement for potential equity participation in the Guaymas-El Oro segment of the Sonora pipeline.

We estimate the capital expenditures for re-routing the pipeline will be approximately $260 million, including capitalized interest and project contingency. The actual amount of capital expenditures may differ substantially from our estimates.

Tab le of Cont ents

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 of the Sonora pipeline will continue to be owned by and a Sole Risk Project of Sempra after closing the planned sale of a portion of our equity interest in SI Partners, which we discuss in Note 6 of the Notes to Consolidated Financial Statements. Any proceeds from a sale of the Guaymas-El Oro segment of the Sonora pipeline would be split between Sempra (90%) and ADIA (10%), subject to adjustments.

At December 31, 2025, Sempra Infrastructure had $389 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, which in each case could have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.

Low Carbon Solutions

Cimarrón Wind. The Cimarrón Wind project, an approximately 320-MW wind generation facility in Baja California, Mexico, commenced energy generation in October 2025 during its commissioning phase. 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. We expect commercial operations to commence in the first quarter of 2026.

Hackberry Carbon Sequestration Project. SI Partners 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 Conservation and Energy (LDC&E), formally known as the Louisiana Department of Energy and Natural Resources, issued a draft Class VI carbon injection well construction permit and held the required public hearing. In September 2025, LDC&E issued the final permit to construct a Class VI carbon injection well.

Legal and Regulatory Matters

See Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors” for discussions of the following legal and regulatory matters affecting our operations in Mexico and risks associated with Mexican laws, policies and government influence:

▪ Energía Costa Azul

◦ Land Disputes

◦ Environmental and Social Impact Permits

▪ Mexican Government Influence on Economic and Energy Matters

One or more unfavorable conclusions on these land disputes, environmental and social impact permit challenges, and regulatory and other actions by the Mexican government 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.

Tab le of Cont ents

SOURCES AND USES OF CASH

We discuss herein our sources and uses of cash for the year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion of our sources and uses of cash for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “ Part II – Item 7. MD&A – Sources and Uses of Cash ” in our 2024 annual report on Form 10-K filed with the SEC on February 25, 2025.

The following tables include only significant changes in cash flow activities for each of the Registrants.

CASH FLOWS FROM OPERATING ACTIVITIES
(Dollars in millions)
Years ended December 31,	Sempra	SDG&E	SoCalGas
2025	$ 4,565	$ 1,664	$ 1,748
2024	4,907	2,073	1,791
Change	$ (342)	$ (409)	$ (43)
Change in regulatory accounts, current and noncurrent	$ (407)	$ (307)	$ (100)
Change in accounts receivable	(184)	(174)	(43)
Change in income taxes receivable/payable, net	(138)	(212)
Satisfaction of performance obligations related to a contract modification	(98)
Change in net margin posted, current and noncurrent	(59)
Higher (lower) net income, adjusted for noncash items included in earnings		106	(186)
Customer ’ s early termination of firm transportation agreements	55
Change in noncurrent qualified pension assets/liabilities, net	84	48	41
Change in fixed-price contracts and other derivatives, current and noncurrent	95		97
Change in accrued franchise fees	97	87
Change in GHG allowances, current and noncurrent	103	83	36
Change in accounts payable	124		123
Other	(14)	(40)	(11)
	$ (342)	$ (409)	$ (43)

CASH FLOWS FROM INVESTING ACTIVITIES
(Dollars in millions)
Years ended December 31,	Sempra	SDG&E	SoCalGas
2025	$ (12,537)	$ (2,369)	$ (2,116)
2024	(9,118)	(2,461)	(2,231)
Change	$ (3,419)	$ 92	$ 115
(Increase) decrease in capital expenditures	$ (2,397)	$ 95	$ 115
Higher contributions to Oncor Holdings	(1,037)
Other	15	(3)
	$ (3,419)	$ 92	$ 115

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CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
Years ended December 31,	Sempra	SDG&E	SoCalGas
2025	$ 9,930	$ 712	$ 370
2024	5,424	338	450
Change	$ 4,506	$ 374	$ (80)
Contributions from CRNCI, net of transaction costs	$ 5,294
Change in borrowings and repayments of short-term debt, net	1,819	$ (303)	$ 775
Higher (lower) issuances of short-term debt with maturities greater than 90 days	1,455		(300)
Higher issuances of long-term debt	1,153	254
Proceeds from investor equity subscription	106
Higher advances from unconsolidated affiliates	65
Termination of interest rate swaps	(46)
Higher common dividends paid	(104)
Higher distributions to NCI	(312)
Higher payments on short-term debt with maturities greater than 90 days	(440)		(700)
Redemption of preferred stock	(900)
Lower contributions from NCI	(908)
Lower issuances of common stock	(1,187)
(Higher) lower payments on long-term debt and finance leases	(1,441)	399	148
Other	(48)	24	(3)
	$ 4,506	$ 374	$ (80)

Capital Expenditures for PP&E

We invested most of our capital expenditures at Sempra Infrastructure, primarily for LNG projects in development and under construction, and at Sempra California, primarily for transmission and distribution improvements, including pipeline and wildfire safety. The following table summarizes, by segment, capital expenditures for PP&E for the last three years.

CAPITAL EXPENDITURES FOR PP&E
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra:
Sempra California (1)	$ 4,543	$ 4,753	$ 4,560
Sempra Infrastructure	6,063	3,459	3,832
Segment totals	10,606	8,212	8,392
Parent and other	6	3	5
Total Sempra	$ 10,612	$ 8,215	$ 8,397

(1) Includes capital expenditures for PP&E of $2,427, $2,522, and $2,540 at SDG&E and $2,116, $2,231, and $2,020 at SoCalGas for 2025, 2024, and 2023, respectively.

Capital Expenditures for Investments

The following table summarizes, by segment, capital expenditures for investments in entities that we account for under the equity method for the last three years.

CAPITAL EXPENDITURES FOR INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra:
Sempra Texas Utilities	$ 2,013	$ 976	$ 367
Sempra Infrastructure	2	12	15
Total Sempra	$ 2,015	$ 988	$ 382

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Future Capital Expenditures for PP&E and Investments

The amounts and timing of capital expenditures for PP&E and certain investments are generally subject to approvals by various regulatory and other governmental and environmental bodies, including the CPUC, the FERC and the PUCT, and various other factors described in this MD&A and in “Part I – Item 1A. Risk Factors.” We expect to make capital expenditures for PP&E, including capitalized interest and AFUDC related to debt, and investments of approximately $8.6 billion in 2026 and $38.7 billion during the five-year period covered by our 2026 through 2030 capital expenditures plan, as summarized by segment in the following table.

FUTURE CAPITAL EXPENDITURES FOR PP&E AND INVESTMENTS
(Dollars in millions)
	Year ending December 31, 2026	Capital plan for 2026 - 2030
Sempra:
Sempra California (1)	$ 4,300	$ 23,500
Sempra Texas Utilities	2,700	11,100
Sempra Infrastructure (2)	1,600	4,100
Total Sempra	$ 8,600	$ 38,700

(1) Includes expected future capital expenditures of $2,200 and $2,100 at SDG&E and SoCalGas, respectively, for the year ending December 31, 2026 and $12,900 and $10,600 at SDG&E and SoCalGas, respectively, during the period covered by their 2026 through 2030 capital expenditures plans.

(2) Sempra's Capital Plan assumes Sempra's 70% consolidated ownership of SI Partners for the first three months of 2026 and 25% thereafter, which represents Sempra's remaining interest under the equity method upon completion of the sale of a 45% equity interest in SI Partners.

We expect the majority of our capital expenditures for PP&E and investments in 2026 will relate to investments in transmission and distribution safety and reliability at our regulated public utilities and construction of the PA LNG Phase 1 project and PA LNG Phase 2 project at Sempra Infrastructure.

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 from 2026 through 2030 to total $64.9 billion.

Oncor announced a new five-year base capital expenditures plan from 2026 through 2030 of approximately $47.5 billion, which is 32% higher than Oncor’s 2025 through 2029 base capital expenditures plan. This increase is largely attributable to Oncor’s targeted completion by December 31, 2030 of its Permian Basin Reliability Plan projects, as well as other new transmission projects and distribution upgrades. Oncor’s base capital expenditures plan does not include certain incremental capital expenditure opportunities, including various transmission and customer interconnection projects, that may be completed over the 2026 through 2030 period and could potentially increase its five-year base capital expenditures plan by as much as $10.0 billion over that period. Changes in Oncor’s capital expenditures plan could result in corresponding changes to our projected capital expenditures for PP&E and investments based on our ownership interest in Oncor.

Periodically, we review our construction, investment and financing programs and revise them in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost and availability of capital, safety and environmental requirements, and other relevant factors.

Our level of capital expenditures for PP&E and investments in the next few years may differ substantially from our estimates and 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.” 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 we may not be able to do so.

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Rate Base

For SDG&E and SoCalGas, rate base is the value of assets on which SDG&E and SoCalGas are permitted to earn a specified rate of return in accordance with rules set by regulatory agencies, including the CPUC and the FERC (for SDG&E), which is calculated using a 13-month average pursuant to CPUC methodology as adopted in rate-setting proceedings. The following table summarizes the weighted-average rate base for SDG&E and SoCalGas for the last three years.

WEIGHTED-AVERAGE RATE BASE
(Dollars in millions)
	2025	2024	2023
SDG&E	$ 18,019	$ 16,842	$ 15,220
SoCalGas	13,985	12,446	11,671

The increase in weighted-average rate base reflects the significant capital investments that SDG&E and SoCalGas have made in transmission and distribution safety and reliability. We expect the weighted-average rate base to continue to increase in 2026 and beyond based on our expected capital investments.

For Oncor, rate base represents the total invested capital, as adjusted in accordance with PUCT rules, at the end of the previous calendar year as reported in the Earnings Monitoring Report filed with the PUCT on an annual basis. Oncor’s regulatory rate base as reported in these filings as of December 31, 2024 and 2023 was $26.6 billion and $23.1 billion, respectively. As calculated on a similar basis, its estimated regulatory rate base at December 31, 2025 was $31.5 billion. The increase in rate base reflects the significant capital investments that Oncor has made in its transmission and distribution system, and we expect rate base to continue to increase in 2026 and beyond based on Oncor’s expected capital investments.

Capital Stock Transactions

Sempra

Cash provided by issuances of common stock was:

▪ $32 million in 2025

▪ $1,219 million in 2024

▪ $145 million in 2023

Cash used for repurchases of common stock was:

▪ $58 million in 2025

▪ $43 million in 2024

▪ $32 million in 2023

We discuss the issuances and repurchases of common stock in Note 13 of the Notes to Consolidated Financial Statements.

Dividends

Sempra

Sempra paid cash dividends of:

▪ $1,603 million for common stock and $40 million for preferred stock in 2025

▪ $1,499 million for common stock and $44 million for preferred stock in 2024

▪ $1,483 million for common stock and $44 million for preferred stock in 2023

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DIVIDENDS PER SHARE ON SEMPRA COMMON STOCK
(As approved by our board of directors)

On February 25, 2026, our board of directors declared a dividend of $0.6575 per share on our common stock payable on April 15, 2026.

All declarations of dividends on our common stock are made at the discretion of the board of directors. While we view dividends as an integral component of shareholder return, the amount of future dividends will depend on earnings, cash flows, financial and legal requirements, and other relevant factors at that time. As a result, Sempra’s dividends on common stock declared on a historical basis may not be indicative of future declarations.

SDG&E

In 2025, 2024 and 2023, SDG&E paid common stock dividends to Enova Corporation and Enova Corporation paid corresponding dividends to Sempra of $200 million, $225 million and $100 million, respectively. SDG&E’s dividends on common stock declared on an annual historical basis may not be indicative of future declarations.

Enova Corporation, a wholly owned subsidiary of Sempra, owns all of SDG&E’s outstanding common stock. Accordingly, dividends paid by SDG&E to Enova Corporation and dividends paid by Enova Corporation to Sempra are eliminated in Sempra’s consolidated financial statements.

SoCalGas

In 2025, 2024 and 2023, SoCalGas paid common stock dividends to Pacific Enterprises and Pacific Enterprises paid corresponding dividends to Sempra of $200 million, $200 million and $100 million, respectively. SoCalGas’ dividends on common stock declared on an annual historical basis may not be indicative of future declarations.

Pacific Enterprises, a wholly owned subsidiary of Sempra, owns all of SoCalGas’ outstanding common stock. Accordingly, dividends paid by SoCalGas to Pacific Enterprises and dividends paid by Pacific Enterprises to Sempra are eliminated in Sempra’s consolidated financial statements.

Dividend Restrictions

The board of directors for each of Sempra, SDG&E and SoCalGas has the discretion to determine whether to declare and, if declared, the amount of any dividends by each such entity. The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts that are available for loans and dividends to Sempra. At December 31, 2025, based on these regulations, Sempra could have received combined loans and dividends of approximately $868 million from SDG&E and $350 million from SoCalGas.

We provide additional information about dividend restrictions in “Restricted Net Assets” in Note 1 of the Notes to Consolidated Financial Statements and in Note 13 of the Notes to Consolidated Financial Statements.

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Capitalization

Our total capitalization, which is the sum of total debt and equity, and our debt-to-capitalization ratio, which is calculated as total debt as a percentage of total capitalization, was as follows:

TOTAL CAPITALIZATION AND DEBT-TO-CAPITALIZATION RATIO
(Dollars in millions)
	Total capitalization		Debt-to-capitalization ratio
	December 31,
	2025	2024	2025	2024
Sempra	81,969	$ 73,636	53 %	49 %
SDG&E	22,343	21,041	51	50
SoCalGas	17,887	16,602	51	51

In 2025 compared to 2024, Sempra’s total capitalization increased by $8.3 billion (11%) due to:

▪ increase in long-term debt, which includes long-term debt that is within the disposal group that is classified as held for sale

▪ increase in equity primarily from contributions from CRNCI and NCI, as well as comprehensive income exceeding dividends

Offset by:

▪ redemption of preferred stock and distributions to NCI

In 2025 compared to 2024, SDG&E’s and SoCalGas’ total capitalization increased by $1.3 billion (6%) and $1.3 billion (8%), respectively, due to increases in debt and increases in equity from comprehensive income exceeding dividends.

CRITICAL ACCOUNTING ESTIMATES

Management views the accounting estimates that we describe below 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 these critical accounting estimates, which are material to our financial statements with the Audit Committee of Sempra’s board of directors.

REGULATORY ACCOUNTING

Sempra, SDG&E, SoCalGas

As regulated entities, SDG&E’s and SoCalGas’ customer rates, as set and monitored by regulators, are designed to recover the cost of providing service and to provide the opportunity to realize their authorized rates of return on their investments. SDG&E and SoCalGas assess probabilities of future rate recovery associated with regulatory account balances at the end of each reporting period and whenever new and/or unusual events occur, such as:

▪ changes in the regulatory and political environment or the utility’s competitive position

▪ issuance of a regulatory commission order

▪ passage of new legislation

To the extent that circumstances associated with regulatory balances change, the regulatory balances are evaluated and adjusted if appropriate.

Significant management judgment is required to evaluate the anticipated recovery of regulatory assets and revenues subject to refund, as well as the existence and amount of regulatory liabilities. Adverse regulatory or legislative actions could materially impact the amounts of our regulatory assets and liabilities and could materially adversely impact our results of operations and financial condition. Specifically, if future recovery of costs ceases to be probable, all or part of the associated regulatory assets would need to be written off against current period earnings, or adverse regulatory or legislative actions could give rise to material new or higher regulatory liabilities. We discuss details of SDG&E’s and SoCalGas’ regulatory assets and liabilities and additional factors that management considers when assessing probabilities associated with regulatory balances in Notes 1, 4, 15 and 16 of the Notes to Consolidated Financial Statements.

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INCOME TAXES

Sempra, SDG&E, SoCalGas

Our income tax expense and related balance sheet amounts involve significant management judgments and estimates. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. When we evaluate the anticipated resolution of income tax issues, we consider:

▪ past resolutions of the same issue or similar issues

▪ the status of any income tax examination in progress

▪ positions taken by taxing authorities with other taxpayers with similar issues

The likelihood of deferred income tax recovery is based on analyses of the deferred income tax assets and our expectation of future taxable income, based on our strategic planning. Should a change in facts or circumstances lead to a change in judgment about the ultimate realizability of a deferred tax asset, we would record or adjust the related valuation allowance in the period that the change in facts and circumstances occurs, along with a corresponding increase or decrease in the provision for income taxes.

Actual income taxes could vary from estimated amounts because of:

▪ future impacts of various items, including changes in tax laws, regulations, interpretations and rulings

▪ our financial condition in future periods

▪ the resolution of various income tax issues between us and taxing and regulatory authorities

Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our results of operations, financial condition and cash flows.

We discuss these matters and additional information related to accounting for income taxes, including uncertainty in income taxes, in Note 8 of the Notes to Consolidated Financial Statements.

PENSION AND PBOP PLANS

Sempra, SDG&E, SoCalGas

To measure our pension and PBOP obligations, costs and liabilities, we rely on several assumptions. We consider current market conditions, including interest rates, in making these assumptions. We review these assumptions annually and update when appropriate.

The critical assumptions used to develop the required estimates include the following key factors:

▪ discount rates

▪ expected return on plan assets

▪ health care cost trend rates

▪ interest crediting rate on cash balance accounts

▪ mortality rate

▪ rate of compensation increases

▪ termination and retirement rates

▪ utilization of postretirement welfare benefits

▪ payout elections (lump sum or annuity)

▪ lump sum interest rates

The actuarial assumptions we use may differ materially from actual results due to:

▪ return on plan assets

▪ changing market and economic conditions

▪ higher or lower withdrawal rates

▪ longer or shorter participant life spans

▪ more or fewer lump sum versus annuity payout elections made by plan participants

▪ higher or lower retirement rates

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Changes in the estimated costs or timing of pension and PBOP, or the assumptions and judgments used by management underlying these estimates (primarily the discount rate and expected return on plan assets), as well as changes in the circumstances associated with rate recovery, could have a material effect on the recorded expenses and liabilities. The following tables summarize the impact to our projected benefit obligation for pension and accumulated benefit obligation for PBOP at December 31, 2025, and 2025 net periodic benefit costs, in each case if the discount rate or expected return on plan assets were changed by 1%.

IMPACT DUE TO INCREASE/DECREASE IN DISCOUNT RATE
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
	Increase	Decrease	Increase	Decrease	Increase	Decrease
Pension:
(Decrease) increase to projected benefit obligation, net	$ (229)	$ 288	$ (32)	$ 38	$ (186)	$ 236
(Decrease) increase to net periodic benefit cost	4	11	3	(2)	—	14
PBOP:
(Decrease) increase to accumulated benefit obligation, net	(76)	93	(14)	17	(60)	74
(Decrease) increase to net periodic benefit cost	(6)	5	(1)	1	(5)	4

IMPACT DUE TO INCREASE/DECREASE IN RETURN ON PLAN ASSETS
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
	Increase	Decrease	Increase	Decrease	Increase	Decrease
Pension:
(Decrease) increase to net periodic benefit cost	$ (27)	$ 27	$ (7)	$ 7	$ (18)	$ 18
PBOP:
(Decrease) increase to net periodic benefit cost	(11)	11	(1)	1	(10)	10

For SDG&E and SoCalGas plans, the effects of the assumptions on earnings are expected to be recovered in rates and therefore are offset in regulatory accounts. We provide details of our pension and PBOP plans in Note 9 of the Notes to Consolidated Financial Statements.

SONGS ASSET RETIREMENT OBLIGATIONS

Sempra, SDG&E

SDG&E’s legal AROs related to the decommissioning of SONGS are estimated based on a site-specific study performed no less than every three years. The estimate of the obligations includes:

▪ estimated decommissioning costs, including labor, equipment, material and other disposal costs

▪ inflation adjustment applied to estimated cash flows

▪ discount rate based on a credit-adjusted risk-free rate

▪ actual decommissioning costs, progress to date and expected duration of decommissioning activities

SDG&E’s nuclear decommissioning expenses are subject to rate recovery and, therefore, rate-making accounting treatment is applied to SDG&E’s nuclear decommissioning activities. SDG&E recognizes a regulatory asset, or liability, to the extent that its SONGS ARO exceeds, or is less than, the amount collected from customers and the amount earned in SDG&E’s NDT.

SDG&E’s ARO related to the decommissioning of SONGS was $446 million as of December 31, 2025, based on the decommissioning cost study prepared in 2024. Changes in the estimated costs, execution strategy or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission this facility, which could have a material effect on the recorded liability.

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The following table illustrates the increase to SDG&E’s and Sempra’s ARO liability if the cost escalation rate was adjusted while leaving all other assumptions constant:

INCREASE TO ARO AND REGULATORY ASSET
(Dollars in millions)
	December 31, 2025
Uniform increase in escalation percentage of 1%	$ 63

The increase in the ARO liability driven by an increase in the cost escalation rate would result in a decrease in the regulatory liability for recoveries in excess of ARO liabilities. We provide additional detail in Note 15 of the Notes to Consolidated Financial Statements.

IMPAIRMENT TESTING OF LONG-LIVED ASSETS

Sempra

Whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable, we consider if the estimated future undiscounted cash flows are less than the carrying amount of the asset. If so, we estimate the fair value of the asset to determine the extent to which carrying value exceeds fair value. For such an estimate, we may consider data from multiple valuation methods, including data from market participants. We exercise judgment to estimate the future cash flows and the useful life of a long-lived asset and to determine our intent to use the asset. Our intent to use or dispose of a long-lived asset is subject to re-evaluation and can change over time. If such an impairment test is required, the fair value of a long-lived asset can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. Critical assumptions that affect our estimates of fair value may include:

▪ consideration of market transactions

▪ future cash flows

▪ the appropriate risk-adjusted discount rate, including the impacts of country risk and entity risk

We discuss impairment of long-lived assets in Note 1 of the Notes to Consolidated Financial Statements.

IMPAIRMENT TESTING OF GOODWILL

Sempra

When determining if goodwill is impaired, the fair value of the reporting unit can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. As a result, recognizing a goodwill impairment may or may not be required. When we perform a quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and compare that to its carrying value. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as a discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include:

▪ consideration of market transactions

▪ future cash flows

▪ projected revenue and expense growth rates

▪ the appropriate risk-adjusted discount rate, including the impacts of country risk, customer creditworthiness and entity risk

At December 31, 2025, goodwill is classified as held for sale. In 2025, we performed a quantitative goodwill impairment test and determined that the estimated fair values of our reporting units in Mexico to which goodwill was allocated were substantially above their respective carrying values as of October 1, our annual goodwill impairment testing date. Upon performing a qualitative analysis as of October 1, 2024, we determined that it was not more likely than not that the fair value of such reporting units was less than their respective carrying values. Our goodwill impairment test is determined based on assumptions existing as of that point in time. Changes in the business (such as loss of future cash flows from customer disputes, renegotiation of customer contracts or the macroeconomic environment, including rising interest rates) may result in us having to perform an interim goodwill impairment test, which could result in an impairment of our goodwill.

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NEW ACCOUNTING STANDARDS

We discuss the recent accounting pronouncements that have had or may have a significant effect on our financial statements and/or disclosures in Note 2 of the Notes to Consolidated Financial Statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk of erosion of our cash flows, earnings, asset values or equity due to adverse changes in commodity market prices, interest rates and foreign currency and inflation rates.

MARKET RISK POLICIES

Sempra has policies governing its market risk management and trading activities. Sempra, SDG&E, SoCalGas and SI Partners maintain separate risk management committees, organizations and processes to provide oversight of these activities for their respective businesses. The committees consist of senior officers who establish policy, oversee energy risk management activities, and monitor the results of trading and other activities to help ensure compliance with our energy risk management and trading policies. These activities include, but are not limited to, monitoring of market positions that create credit, liquidity and market risk. The respective oversight organizations and committees are independent from energy procurement departments.

Along with other tools, we use VaR and liquidity metrics to measure our exposure to market risk associated with commodity portfolios. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence interval. We use a variance-covariance VaR model at a 95% confidence level. A liquidity metric is intended to monitor the amount of financial resources needed for meeting potential margin calls as forward market prices move. VaR and liquidity risk metrics are independently verified by the respective risk management oversight organizations.

SDG&E and SoCalGas use natural gas derivatives and SDG&E uses electricity derivatives with the objective of managing natural gas and electric price and basis risk associated with servicing load requirements. The use of natural gas and electricity derivatives is subject to certain limitations imposed by company policy and regulatory requirements. SDG&E’s risk management and transacting activity plans for electricity derivatives are also required to be filed with, and have been approved by, the CPUC. SoCalGas is also subject to certain regulatory requirements and thresholds related to natural gas procurement under the GCIM. We discuss revenue recognition in Note 3 and additional market-risk information regarding derivative instruments in Note 10 of the Notes to Consolidated Financial Statements.

We have exposure to changes in commodity prices, interest rates and foreign currency and inflation rates. The following discussions of these primary market-risk exposures as of December 31, 2025 includes discussions of how these exposures are managed.

COMMODITY PRICE RISK

Market risk related to physical commodities is created by volatility in the prices and basis of certain commodities. Our various subsidiaries are exposed, in varying degrees, to commodity price risk, primarily in the natural gas and electricity markets. Our policy is to manage this risk within a framework that considers the specific markets and operating and regulatory environments of each subsidiary.

SI Partners is exposed to commodity price risk indirectly through its LNG, natural gas pipelines and storage, and power-generating assets. SI Partners has utilized and may continue to utilize commodity contracts, including physical and financial derivatives, in an effort to mitigate these risks and optimize the value of these assets. These transactions are typically priced based on market indices but may also include fixed price purchases and sales of commodities. Any residual exposure is monitored as described above. Some of these derivatives that we use as economic hedges do not meet the requirements for hedge accounting, or hedge accounting is not elected, and as a result, the changes in fair value of these derivatives are recorded in earnings. Consequently, significant changes in commodity prices have in the past and could in the future result in earnings volatility as the economic offset of these derivatives may not be recorded at fair value. A significant decrease in the fair value of these economic hedges could also result in higher collateral requirements, which could negatively impact our liquidity and our ability to continue to mitigate our commodity risk exposure. We try to structure our hedging transactions with the objective that over time (i) realized gains and losses on our economic hedges would be largely offset by gains and losses related to our purchases or sales of natural gas and (ii) we would realize the economic benefit we anticipated at the time we structured the original transaction.

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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 $11 million and $13 million at December 31, 2025 and 2024, respectively. The impact of a change in energy commodity prices on our commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled and does not typically include the generally offsetting impact of our underlying asset positions.

SDG&E and SoCalGas separately manage risk within the parameters of their market risk management frameworks. In addition, their market-risk exposure is limited due to CPUC-authorized rate recovery of the costs of commodity purchases, interstate and intrastate transportation, and storage activity. However, SoCalGas may, at times, be exposed to market risk as a result of the GCIM, which awards or penalizes the utility for commodity costs below or above certain benchmarks. The one-day VaR for SDG&E’s and SoCalGas’ commodity positions were $2 million and $6 million, respectively, at December 31, 2025 and both $2 million at December 31, 2024.

INTEREST RATE RISK

We are exposed to fluctuations in interest rates primarily from our short- and long-term debt. Subject to regulatory constraints, we periodically enter into interest rate swap agreements intended to moderate our exposure to interest rate changes and to lower our overall cost of borrowing.

The table below shows the nominal amount of our debt:

NOMINAL AMOUNT OF DEBT (1)
(Dollars in millions)
	December 31, 2025			December 31, 2024
	Sempra (2)	SDG&E	SoCalGas	Sempra	SDG&E	SoCalGas
Short-term:
Sempra California	$ 1,436	$ 532	$ 904	$ 1,454	$ 417	$ 1,037
Other	2,733	—	—	562	—	—
Long-term:
Sempra California fixed-rate	$ 17,909	$ 9,800	$ 8,109	$ 16,309	$ 8,950	$ 7,359
Other fixed-rate	11,958	—	—	15,527	—	—
Other variable-rate	—	—	—	1,063	—	—

(1) After the effects of interest rate swaps. Before reductions for unamortized discount and debt issuance costs and excluding finance lease obligations.

(2) Excludes $8,287 that is included in Liabilities Held for Sale on the Sempra Consolidated Balance Sheet, which consists of $362 of short-term debt, $5,766 of long-term fixed-rate debt, and $2,159 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 December 31, 2025, including short-term debt classified as held for sale, increased or decreased by 10%, the change in earnings attributable to common shares over the 12-month period ending December 31, 2026 would be approximately $14 million. If interest rates increased or decreased by 10% on all variable-rate long-term debt outstanding at December 31, 2025, all of which relates to variable-rate long-term debt classified as held for sale, after considering the effects of interest rate swaps, the change in earnings attributable to common shares over the 12-month period ending December 31, 2026 would be approximately $4 million.

We provide further information about debt and interest rate swap transactions in Notes 7 and 10, respectively, of the Notes to Consolidated Financial Statements.

We also are subject to the effect of interest rate fluctuations on the assets of our pension plans, PBOP plans, and SDG&E’s NDT. We expect the effects of these fluctuations, as they relate to Sempra California, to be reflected in future rates .

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FOREIGN CURRENCY EXCHANGE RATE RISK AND INFLATION EXPOSURE

At December 31, 2025, SI Partners, which holds our foreign operations, is classified as held for sale. Upon completion of the sale, which we expect to occur in the second or third quarter of 2026, we will deconsolidate SI Partners and account for our remaining 25% interest under the equity method, thereby reducing volatility in our results of operations associated with foreign currency exchange rate fluctuations and Mexican inflation. We discuss our foreign currency exchange rate risk and inflation exposure in “Part II – Item 7. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations.”

The hypothetical effect for every 10% appreciation in the U.S. dollar against the Mexican peso, in which we have operations and investments, is as follows:

HYPOTHETICAL EFFECTS FROM 10% STRENGTHENING OF U.S. DOLLAR (1)
(Dollars in millions)
	Hypothetical effects
Sempra:
Translation of 2025 earnings to U.S. dollars (2)	$ (2)
Transactional exposure (3)	124
Translation of net assets of foreign subsidiaries and investment in foreign entities (4)	(24)

(1) After the effects of foreign currency derivatives.

(2) Amount represents the impact to earnings for a change in the average exchange rate throughout the reporting period.

(3) Amount primarily represents the effects of currency exchange rate movement from December 31, 2025 on monetary assets and liabilities and remeasurement of foreign deferred income tax balances at our Mexican subsidiaries.

(4) Amount represents the effects of currency exchange rate movement from December 31, 2025 that would be recorded to OCI at the end of the reporting period.

Monetary assets and liabilities at our Mexican subsidiaries and equity method investees that are denominated in U.S. dollars may fluctuate significantly throughout the year. These monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. Based on a net monetary liability position of $4.5 billion, including those related to our equity method investments, at December 31, 2025, the hypothetical effect of a 10% increase in the Mexican inflation rate is approximately $89 million lower earnings attributable to common shares as a result of higher income tax expense for our consolidated entities, as well as lower equity earnings for our equity method investees.

In 2025 and 2024, SDG&E and SoCalGas experienced inflationary pressures from increases in various costs, including the cost of natural gas, electric fuel and purchased power, labor, materials, equipment and supplies, as well as decreased availability of many of these items. During this period, Sempra Texas Utilities experienced increased costs, including labor and contractor-related costs, materials, equipment and supplies, 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, UTM filings and base rate reviews, which may result in partial non-recovery due to regulatory lag. If such costs continue to be subject to 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.

In 2025 and 2024, SI Partners experienced inflationary pressures from increases in various costs, including the cost of commodities, labor, materials, equipment and supplies, as well as decreased availability of many of these items. SI Partners generally secures long-term contracts that are U.S. dollar-denominated or referenced and are periodically adjusted for market factors, including inflation, and SI Partners 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 inflationary pressures, we may not be able to fully recover such higher costs through contractual adjustments for inflation, which may have a significant effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated financial statements are listed on the Index to Consolidated Financial Statements set forth on page F-1 of this annual report on Form 10-K.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Sempra, SDG&E, SoCalGas

Sempra, SDG&E and SoCalGas maintain disclosure controls and procedures designed to ensure that information required to be disclosed in their respective reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and is accumulated and communicated to the management of each company, including each respective principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision and with the participation of the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas, each such company’s management evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 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.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Sempra, SDG&E, SoCalGas

The respective management of Sempra, SDG&E and SoCalGas is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f).

Under the supervision and with the participation of the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas, each such company’s management evaluated the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on these evaluations, each company’s management concluded that its internal control over financial reporting was effective as of December 31, 2025. Deloitte & Touche LLP audited the effectiveness of each company’s internal control over financial reporting as of December 31, 2025, as stated in their reports, which are included in this annual report on Form 10-K.

There have been no changes in Sempra’s, SDG&E’s or SoCalGas’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, any such company’s internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Board of Directors of Sempra:

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Sempra and subsidiaries (“Sempra”) as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, Sempra maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements as of and for the year ended December 31, 2025, of Sempra and our report dated February 26, 2026, expressed an unqualified opinion on those financial statements.

Basis for Opinion

Sempra’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Sempra’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sempra in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2026

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholder and Board of Directors of San Diego Gas & Electric Company:

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of San Diego Gas & Electric Company (“SDG&E”) as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, SDG&E maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the financial statements as of and for the year ended December 31, 2025, of SDG&E and our report dated February 26, 2026, expressed an unqualified opinion on those financial statements .

Basis for Opinion

SDG&E’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on SDG&E’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SDG&E in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2026

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Board of Directors of Southern California Gas Company:

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Southern California Gas Company (“SoCalGas”) as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, SoCalGas maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the financial statements as of and for the year ended December 31, 2025, of SoCalGas and our report dated February 26, 2026, expressed an unqualified opinion on those financial statements.

Basis for Opinion

SoCalGas’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on SoCalGas’ internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SoCalGas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2026

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ITEM 9B. OTHER INFORMATION

(a) As we discuss in Note 13 of the Notes to Consolidated Financial Statements, in October 2025, Sempra redeemed 900,000 issued and outstanding shares of its series C preferred stock and, after such redemption, no shares of series C preferred stock remain outstanding. In addition, as we have previously reported, (i) in January and July of 2021, all outstanding shares of Sempra’s former 6% mandatory convertible preferred stock, series A, and 6.75% mandatory convertible preferred stock, series B, were converted into shares of Sempra’s common stock and, after such conversions, no shares of either such series of preferred stock remain outstanding, and (ii) in May 2024, Sempra submitted a filing with the Secretary of State of the State of California that implemented the revocation of such former series of preferred stock, such that the number of authorized shares of each such series was decreased to zero and each is no longer an authorized series of Sempra’s capital stock.

On February 23, 2026, Sempra filed restated articles of incorporation with the Secretary of State of the State of California that (i) implement the revocation of the series C preferred stock, such that the number of authorized shares of such series is decreased to zero and it is no longer an authorized series of Sempra’s capital stock, (ii) eliminate from Sempra’s articles of incorporation the certificates of determination of preference of each of its former series of preferred stock, and (iii) incorporate all amendments to Sempra’s articles of incorporation since its last restatement in May 2008.

A copy of such restated articles of incorporation is filed as Exhibit 3.1 hereto and incorporated herein by reference. The summary set forth above is qualified in its entirety by reference to such exhibit.

(b) During the last fiscal quarter, (i) the individual listed below, who was at the time a Sempra director or officer, 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.

RULE 10B5-1 TRADING ARRANGEMENTS
(In the three months ended December 31, 2025)
Name and title of the director or officer	Date on which the director or officer adopted or terminated the trading arrangement	Duration of the trading arrangement	Aggregate number of securities to be purchased or sold pursuant to the trading arrangement
Dyan Z. Wold , Vice President, Controller and Chief Accounting Officer	November 19, 2025	From March 16, 2026 until all shares are sold or the trading arrangement is otherwise terminated	▪ 1,057 shares of Sempra common stock, which were subject to time-based RSUs that vested in January 2026 ▪ 482 shares of Sempra common stock, which were subject to performance-based RSUs that vested in January 2026 in each case, including the dividend equivalents related to such RSUs and less shares to which Ms. Wold would otherwise have been entitled that were withheld to satisfy minimum statutory tax withholding requirements

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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PART III.

Because SDG&E meets the conditions of General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this report with a reduced disclosure format as permitted by General Instruction I(2), the information required by Part III – Items 10, 11, 12 and 13 below is not required for SDG&E. We have, however, voluntarily provided the information required by Item 401 of SEC Regulation S-K, as required by Part III – Item 10. with respect to SDG&E’s executive officers in “Part I – Item 1. Business – Other Matters – Information About Our Executive Officers.”

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

We provide the information required by Item 401 of SEC Regulation S-K, as required by this item, with respect to executive officers of Sempra and SoCalGas in “Part I – Item 1. Business – Other Matters – Information About Our Executive Officers.” The other information required by this item is incorporated by reference from “Corporate Governance” and “Proposal 1: Election of Directors” in the proxy statement to be filed for the May 2026 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2026 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference. Sempra’s insider trading and information confidentiality policy is incorporated by reference as Exhibit 19.1 to this report.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item is incorporated by reference from “Executive Compensation,” including “Compensation Discussion and Analysis,” “Compensation and Talent Development Committee Report” and “Compensation Tables” (except for the disclosure under the heading “Pay-Versus-Performance”), in the proxy statement to be filed for the May 2026 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2026 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

Sempra has LTIPs that permit the grant of a wide variety of equity and equity-based incentive awards to directors, officers and key employees. At December 31, 2025, outstanding awards consisted of stock options and RSUs held by 440 employees and non-employees.

The following table sets forth information regarding our equity compensation plans, which we describe in Note 14 of the Notes to Consolidated Financial Statements, at December 31, 2025.

EQUITY COMPENSATION PLANS (1) — Plan category	Number of shares to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights (2)	Number of additional shares remaining available for future issuance (3)
Sempra:
Equity compensation plans approved by security holders (4)	5,165,346	$ 70.68	6,544,164

(1) Excludes dividend equivalents and phantom shares that can only be settled for cash. Includes phantom shares, which are fully vested RSUs held in our deferred compensation plan that will be issued as actual shares at a future date specified by each holder.

(2) The weighted-average exercise price does not take into account 2,336,598 of RSUs or 494,468 of phantom shares.

(3) The number of shares available for future issuance is increased by the number of shares to which each participant would otherwise be entitled that are withheld or surrendered to satisfy the exercise price or to satisfy tax withholding obligations relating to any plan awards, and is also increased by the number of shares subject to awards that expire or are forfeited, canceled or otherwise terminated without the issuance of shares.

(4) Each performance-based RSU that has not vested represents the right to receive from 0% to 200% of the shares of our common stock represented by the RSUs, depending on the degree to which applicable performance conditions are satisfied. For purposes of this table, the number of shares of common stock shown to be subject to each performance-based RSU is 100% of the shares represented by the RSUs, which assumes performance conditions are satisfied at the target level.

We provide additional discussion of share-based compensation in Note 14 of the Notes to Consolidated Financial Statements.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by Item 403 of SEC Regulation S-K, as required by this item, is incorporated by reference from “Share Ownership” in the proxy statement to be filed for the May 2026 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2026 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item is incorporated by reference from “Corporate Governance” in the proxy statement to be filed for the May 2026 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2026 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding principal accountant fees and services is presented below for Sempra, SDG&E and SoCalGas. The following table shows the fees paid to Deloitte & Touche LLP, the independent registered public accounting firm for Sempra, SDG&E and SoCalGas, for services provided in 2025 and 2024.

PRINCIPAL ACCOUNTANT FEES
(Dollars in thousands)
	Sempra		SDG&E		SoCalGas
	Fees	Percent of total	Fees	Percent of total	Fees	Percent of total
2025:
Audit fees:
Consolidated financial statements, internal controls audits and subsidiary audits	$ 13,115		$ 3,235		$ 4,169
Regulatory filings and related services	710		75		75
Total audit fees	13,825	82 %	3,310	88 %	4,244	92 %
Audit-related fees:
Employee benefit plan audits	582		185		323
Other audit-related services (1)	1,878		118		20
Total audit-related fees	2,460	15	303	8	343	7
Tax fees (2)	499	3	165	4	42	1
All other fees (3)	74	—	—	—	—	—
Total fees	$ 16,858	100 %	$ 3,778	100 %	$ 4,629	100 %
2024:
Audit fees:
Consolidated financial statements, internal controls audits and subsidiary audits	$ 11,708		$ 3,092		$ 4,118
Regulatory filings and related services	798		75		150
Total audit fees	12,506	81 %	3,167	85 %	4,268	92 %
Audit-related fees:
Employee benefit plan audits	565		181		315
Other audit-related services (1)	2,101		190		20
Total audit-related fees	2,666	17	371	10	335	7
Tax fees (2)	299	2	178	5	47	1
All other fees (3)	40	—	—	—	—	—
Total fees	$ 15,511	100 %	$ 3,716	100 %	$ 4,650	100 %

(1) Other audit-related services primarily relate to statutory audits and agreed upon procedures.

(2) Tax fees relate to tax consulting and compliance services.

(3) All other fees relate to training and conferences.

The Audit Committee of Sempra’s board of directors is directly responsible for the appointment, compensation, retention and oversight, including the oversight of the audit fee negotiations, of the independent registered public accounting firm for Sempra and its subsidiaries, including SDG&E and SoCalGas. As a matter of good corporate governance, each of the Sempra, SDG&E and SoCalGas boards of directors reviewed the performance of Deloitte & Touche LLP and concurred with the determination by Sempra’s Audit Committee to retain the firm as the independent registered public accounting firm for 2026, 2025 and 2024 for each of Sempra, SDG&E and SoCalGas, respectively. Sempra’s board of directors has determined that each member of its Audit Committee is an independent director and is financially literate, and that Mr. Jack T. Taylor, who chairs the committee, and Mss. Jennifer M. Kirk and Anya Weaving, who are members of the committee, are audit committee financial experts as defined by the rules of the SEC.

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Except where pre-approval is not required by SEC rules, Sempra’s Audit Committee pre-approves all audit, audit-related and permissible non-audit services provided by Deloitte & Touche LLP for Sempra and its subsidiaries, including all services provided by Deloitte & Touche LLP for Sempra, SDG&E and SoCalGas in 2025 and 2024. The committee’s pre-approval policies and procedures provide for the general pre-approval of specific types of services and give detailed guidance to management as to the services that are eligible for general pre-approval, and they require specific pre-approval of all other permitted services. For both types of pre-approval, the committee considers whether the services to be provided are consistent with maintaining the firm’s independence. The committee’s policies and procedures also delegate authority to the Chair of the committee to address any requests for pre-approval of services between committee meetings, with any pre-approval decisions to be reported to the committee at its next scheduled meeting.

PART IV.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as part of this report:

FINANCIAL STATEMENTS

Our consolidated financial statements are listed on the Index to Consolidated Financial Statements set forth on page F-1 of this annual report on Form 10-K.

FINANCIAL STATEMENT SCHEDULES

Schedule I is listed on the Index to Condensed Financial Information of Parent as set forth on page S-1 of this annual report on Form 10-K.

Any other schedule for which provision is made in SEC Regulation S-X is not required under the instructions contained therein, is inapplicable or the information is included in the Consolidated Financial Statements and Notes thereto in this annual report on Form 10-K.

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EXHIBITS

EXHIBIT INDEX

The exhibits listed below relate to each Registrant as indicated. Unless otherwise indicated, the exhibits that are incorporated by reference herein were filed under File Number 1-14201 (Sempra), 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 Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
EXHIBIT 3 -- ARTICLES OF INCORPORATION AND BYLAWS
Sempra
3.1	Restated Articles of Incorporation of Sempra effective February 23, 2026.	X
3.2	Bylaws of Sempra (as amended through May 12, 2023).		8-K	3.2	05/16/23
San Diego Gas & Electric Company
3.3	Amended and Restated Articles of Incorporation of San Diego Gas & Electric Company effective August 15, 2014.		10-K	3.4	02/26/15
3.4	Bylaws of San Diego Gas & Electric (as amended through October 26, 2016).		10-Q	3.1	11/02/16
Southern California Gas Company
3.5	Restated Articles of Incorporation of Southern California Gas Company effective October 7, 1996.		10-K	3.01	03/28/97
3.6	Bylaws of Southern California Gas Company (as amended through January 30, 2017).		8-K	3.1	01/31/17
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	Description of rights of Sempra Common Stock (Restated Articles of Incorporation of Sempra effective February 23, 2026) (included as Exhibit 3.1 above).	X
4.2	Description of Securities.	X
4.3	Indenture dated as of February 23, 2000, between Sempra and U.S. Bank Trust National Association, as Trustee.		S-3ASR 333-153425	4.1	09/11/08
4.4	Officers’ Certificate of Sempra, dated as of October 8, 2009, including the form of its 6.00% Note due 2039.		8-K	4.1	10/08/09
4.5	Officers’ Certificate of Sempra, dated as of June 9, 2017, including the form of its 3.250% Note due 2027.		8-K	4.1	06/09/17
4.6	Officers’ Certificate of Sempra, dated as of January 12, 2018, including the forms of its 3.400% Note due 2028, its 3.800% Note due 2038, and its 4.000% Note due 2048.		8-K	4.1	01/12/18
4.7	Officers’ Certificate of Sempra, dated as of March 24, 2022, including the form of its 3.300% Note due 2025 and the form of its 3.700% Note due 2029.		8-K	4.1	03/24/22

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EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
4.8	Officers’ Certificate of Sempra, dated as of June 23, 2023, including the form of its 5.400% Note due 2026 and the form of its 5.500% Note due 2033.		8-K	4.1	06/23/23
4.9	Subordinated Indenture, dated as of June 26, 2019, between Sempra and U.S. Bank National Association, as trustee.		8-K	4.2	06/26/19
4.10	Officers’ Certificate of Sempra, dated as of June 26, 2019, including the form of its 5.750% Junior Subordinated Note due 2079.		8-K	4.1	06/26/19
4.11	Officers' Certificate of Sempra, dated as of November 19, 2021, including the form of its 4.125% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2052.		8-K	4.1	11/19/21
4.12	Officers’ Certificate of Sempra, dated as of March 14, 2024, including the form of 6.875% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2054.		8-K	4.1	03/14/24
4.13	Officers’ Certificate of Sempra, dated as of May 31, 2024, including the form of 6.875% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2054.		8-K	4.1	05/31/24
4.14	Officers’ Certificate of Sempra, dated as of September 9, 2024, including the form of 6.400% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2054.		8-K	4.1	09/09/24
4.15	Officers’ Certificate of Sempra, dated as of November 21, 2024, including the form of 6.625% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2055 and the form of 6.550% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2055.		8-K	4.1	11/21/24
4.16	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-K	4.1	08/29/25
Southern California Gas Company
4.17	Description of preferences of Preferred Stock, Preference Stock and Series Preferred Stock (Southern California Gas Company Restated Articles of Incorporation) (included as Exhibit 3.5 above).		10-K	3.01	03/28/97
4.18	Description of Securities.		10-K	4.9	02/27/20
Sempra / San Diego Gas & Electric Company
4.19	Mortgage and Deed of Trust dated July 1, 1940.		2-4769	B-3	(1)
4.20	Second Supplemental Indenture dated as of March 1, 1948.		2-7418	B-5B	(1)
4.21	Ninth Supplemental Indenture dated as of August 1, 1968.		333-52150	4.5	(1)
4.22	Tenth Supplemental Indenture dated as of December 1, 1968.		2-36042	2-K	(1)
4.23	Sixteenth Supplemental Indenture dated August 28, 1975.		33-34017	4.2	(1)
4.24	Fiftieth Supplemental Indenture, dated as of May 19, 2005.		8-K	4.1	05/19/05
4.25	Fifty-Second Supplemental Indenture, dated as of June 8, 2006.		8-K	4.1	06/08/06
4.26	Fifty-Fourth Supplemental Indenture, dated as of September 20, 2007.		8-K	4.1	09/20/07
4.27	Fifty-Fifth Supplemental Indenture, dated as of May 14, 2009.		8-K	4.1	05/15/09
4.28	Fifty-Sixth Supplemental Indenture, dated as of May 13, 2010.		8-K	4.1	05/13/10
4.29	Fifty-Seventh Supplemental Indenture, dated as of August 26, 2010.		8-K	4.1	08/26/10

(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates the SEC’s Electronic Data Gathering, Analysis, and Retrieval (EDGAR) database.

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EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
4.30	Sixtieth Supplemental Indenture, dated as of November 17, 2011.		8-K	4.1	11/17/11
4.31	Sixty-First Supplemental Indenture, dated as of March 22, 2012.		8-K	4.1	03/23/12
4.32	Sixty-Fifth Supplemental Indenture, dated as of May 19, 2016.		8-K	4.1	05/19/16
4.33	Sixty-Sixth Supplemental Indenture, dated as of June 8, 2017.		8-K	4.1	06/08/17
4.34	Sixty-Seventh Supplemental Indenture, dated as of May 17, 2018.		8-K	4.1	05/17/18
4.35	Sixty-Eighth Supplemental Indenture, dated as of May 31, 2019.		8-K	4.1	05/31/19
4.36	Sixty-Ninth Supplemental Indenture, dated as of April 7, 2020.		8-K	4.1	04/07/20
4.37	Seventieth Supplemental Indenture, dated as of September 28, 2020.		8-K	4.1	09/28/20
4.38	Seventy-First Supplemental Indenture, dated as of August 13, 2021.		8-K	4.1	08/13/21
4.39	Seventy-Second Supplemental Indenture, dated as of March 11, 2022.		8-K	4.1	03/11/22
4.40	Seventy-Third Supplemental Indenture, dated as of March 11, 2022.		8-K	4.2	03/11/22
4.41	Seventy-Fourth Supplemental Indenture, dated as of March 10, 2023.		8-K	4.1	03/10/23
4.42	Seventy-Fifth Supplemental Indenture, dated as of August 11, 2023.		8-K	4.1	08/11/23
4.43	Seventy-Sixth Supplemental Indenture, dated as of March 22, 2024.		8-K	4.1	03/22/24
4.44	Supplemental Indenture of San Diego Gas & Electric Company to U.S. Bank National Association, dated as of March 18, 2025.		10-Q	4.1	05/08/25
4.45	Seventy-Seventh Supplemental Indenture, dated as of March 28, 2025.		8-K	4.1	03/28/25
Sempra / Southern California Gas Company
4.46	First Mortgage Indenture of Southern California Gas Company to American Trust Company, dated October 1, 1940.		2-4504	B-4	(1)
4.47	Supplemental Indenture of Southern California Gas Company to American Trust Company, dated as of July 1, 1947.		10-K	4.40	02/28/23
4.48	Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of August 1, 1955.		2-11997	4.07	(1)
4.49	Supplemental Indenture of Southern California Gas Company to American Trust Company, dated as of December 1, 1956.		10-K	4.09	02/23/07
4.50	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, dated as of June 1, 1965.		10-K	4.10	02/23/07
4.51	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association, dated as of August 1, 1972.		2-59832	2.19	(1)
4.52	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association, dated as of May 1, 1976.		2-56034	2.20	(1)
4.53	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association, dated as of September 15, 1981.		333-70654	4.24	(1)

(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates EDGAR.

Tab le of Cont ents

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
4.54	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of November 18, 2005.		8-K	4.1	11/18/05
4.55	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of November 18, 2010.		8-K	4.1	11/18/10
4.56	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of September 21, 2012.		8-K	4.1	09/21/12
4.57	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of March 13, 2014.		8-K	4.1	03/13/14
4.58	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of June 3, 2016.		8-K	4.1	06/03/16
4.59	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of May 15, 2018.		8-K	4.1	05/15/18
4.60	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of September 24, 2018.		8-K	4.1	09/24/18
4.61	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of June 4, 2019.		8-K	4.1	06/04/19
4.62	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of January 9, 2020.		8-K	4.1	01/09/20
4.63	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of March 29, 2022.		10-Q	4.5	05/05/22
4.64	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of November 14, 2022.		8-K	4.1	11/14/22
4.65	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of May 23, 2023.		8-K	4.1	05/23/23
4.66	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of May 23, 2023.		8-K	4.2	05/23/23
4.67	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of March 18, 2024.		8-K	4.1	03/18/24
4.68	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of August 14, 2024.		8-K	4.1	08/14/24
4.69	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of May 16, 2025.		8-K	4.1	05/16/25
4.70	Supplemental Indenture of Southern California Gas Company to U.S. Bank National Association, dated as of May 16, 2025.		8-K	4.2	05/16/25
4.71	Indenture, dated as of May 1, 1989, between Southern California Gas Company and Citibank, N.A., as trustee.		333-28260	4.1.1	(1)
4.72	First Supplemental Indenture, dated as of October 1, 1992, between Southern California Gas Company and Citibank, N.A., as trustee.		8-K	4.1.2	(1)

(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates EDGAR.

Tab le of Cont ents

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
4.73	Form of 5.670% Medium Term Note due 2028.		8-K	4.2.1	(1)
4.74	Senior Indenture, dated as of September 21, 2020, between Southern California Gas Company and U.S. Bank National Association, as trustee.		8-K	4.1	09/21/20
4.75	Officers’ Certificate of Southern California Gas Company, dated as of March 14, 2022, including the form of its 2.950% Note due 2027.		8-K	4.1	03/14/22
EXHIBIT 10 -- MATERIAL CONTRACTS
Sempra
10.1	ATM 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, as sales agents and forward sellers, 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, as forward purchasers.		10-Q	10.1	11/06/24
Management Contract or Compensatory Plan, Contract or Arrangement
Sempra / San Diego Gas & Electric Company / Southern California Gas Company
10.2	Form of Sempra 2019 Long-Term Incentive Plan 2026 Performance-Based Restricted Stock Unit Award - EPS Growth Performance Measure.	X
10.3	Form of Sempra 2019 Long-Term Incentive Plan 2026 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure-S&P 500 Utilities Index.	X
10.4	Form of Sempra 2019 Long-Term Incentive Plan 2025 Time-Based Restricted Stock Unit Award – One Year Award Vest.		10-Q	10.3	08/07/25
10.5	Form of Sempra 2019 Long-Term Incentive Plan 2024, 2025 and 2026 Nonqualified Stock Option Award Agreement.		10-K	10.8	02/27/24
10.6	Form of Sempra 2019 Long-Term Incentive Plan 2024 and 2025 Performance-Based Restricted Stock Unit Award - EPS Growth Performance Measure.		10-K	10.9	02/27/24
10.7	Form of Sempra 2019 Long-Term Incentive Plan 2024, 2025 and 2026 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure-S&P 500 Index.		10-K	10.10	02/27/24
10.8	Form of Sempra 2019 Long-Term Incentive Plan 2024 and 2025 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure-S&P 500 Utilities Index.		10-K	10.11	02/27/24
10.9	Form of Sempra 2019 Long-Term Incentive Plan 2024, 2025 and 2026 Time-Based Restricted Stock Unit Award - Two Year Award Vest.		10-K	10.11	02/25/25
10.10	Form of Sempra 2019 Long-Term Incentive Plan 2024, 2025 and 2026 Time-Based Restricted Stock Unit Award - Three Year Ratable Vest.		10-K	10.12	02/27/24
10.11	Form of Sempra 2019 Long-Term Incentive Plan 2024 Time-Based Restricted Stock Unit Award - Four Year Award Vest.		10-Q	10.2	11/06/24

(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates EDGAR.

Tab le of Cont ents

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
10.12	Form of Sempra 2019 Long-Term Incentive Plan 2021, 2022 and 2023 Nonqualified Stock Option Award Agreement.		10-K	10.6	02/25/21
10.13	Form of Sempra 2019 Long-Term Incentive Plan 2023 Time-Based Restricted Stock Unit Award - Four Year Award Vest.		10-Q	10.1	11/05/20
10.14	Form of Sempra 2019 Long-Term Incentive Plan 2020 Nonqualified Stock Option Award Agreement.		10-K	10.5	02/27/20
10.15	Amended and Restated Sempra 2019 Long-Term Incentive Plan.		10-Q	10.1	11/03/23
10.16	Form of Sempra 2013 Long-Term Incentive Plan 2019 Nonqualified Stock Option Award Agreement.		10-Q	10.1	05/07/19
10.17	Form of Indemnification Agreement with Directors and Executive Officers (executed before January 2011).		10-Q	10.2	08/07/08
10.18	Form of Indemnification Agreement with Directors and Executive Officers (executed after January 2011).		10-Q	10.1	05/04/16
10.19	Form of Sempra Shared Services Executive Incentive Compensation Plan.		10-K	10.19	02/27/14
10.20	Amendment Number 1 to the Amended and Restated Sempra 2013 Long-Term Incentive Plan.		10-K	10.26	02/25/21
10.21	Amended and Restated Sempra 2013 Long-Term Incentive Plan.		10-K	10.5	02/26/16
10.22	Amended and Restated Sempra Employee and Director Savings Plan, formerly known as the Sempra 2005 Deferred Compensation Plan.		10-Q	10.2	11/03/23
10.23	Amended and Restated Sempra Deferred Compensation and Excess Savings Plan.		10-K	10.28	02/28/17
10.24	2009 Amendment and Restatement of the Sempra Supplemental Executive Retirement Plan effective July 1, 2009.		10-K	10.28	02/26/16
10.25	First Amendment to the 2009 Amendment and Restatement of the Sempra Supplemental Executive Retirement Plan effective February 11, 2010.		10-K	10.29	02/26/16
10.26	Second Amendment to the 2009 Amendment and Restatement of the Sempra Supplemental Executive Retirement Plan effective January 1, 2014.		10-K	10.43	02/26/15
10.27	2015 Amendment and Restatement of the Sempra Cash Balance Restoration Plan effective November 10, 2015.		10-K	10.31	02/26/16
10.28	Sempra Amended and Restated Executive Life Insurance Plan.		10-K	10.22	02/26/13
10.29	Sempra Executive Personal Financial Planning Program Policy Document.		10-K	10.35	02/27/20
10.30	Amended and Restated Severance Pay Agreement between Sempra and Valerie A. Bille, signed April 14, 2025 and effective March 1, 2025.		10-Q	10.5	05/08/25
10.31	Severance Pay Agreement between Sempra and Robert J. Borthwick, signed March 20, 2023 and effective March 1, 2023.	X

Tab le of Cont ents

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
Sempra
10.32	Form of Sempra 2019 Long-Term Incentive Plan Non-Employee Directors’ Annual Restricted Stock Unit Award.		10-K	10.34	02/27/24
10.33	Form of Sempra 2019 Long-Term Incentive Plan Non-Employee Directors’ Initial Restricted Stock Unit Award.		10-K	10.35	02/27/24
10.34	Sempra Amended and Restated Retirement Plan for Directors.		10-Q	10.7	08/07/08
10.35	Sempra Annual Incentive Plan.		10-Q	10.7	05/07/18
10.36	Severance Pay Agreement between Sempra and Justin C. Bird, signed January 24, 2024 and effective January 1, 2024.		10-K	10.38	02/27/24
10.37	Severance Pay Agreement between Sempra and Diana L. Day, signed March 8, 2023 and effective March 1, 2023.		10-K	10.39	02/27/24
10.38	Severance Pay Agreement between Sempra and Lisa M. Larroque Alexander, signed March 8, 2023 and effective March 1, 2023.		10-K	10.42	02/25/25
10.39	Amended and Restated Severance Pay Agreement between Sempra and Jeffrey W. Martin, signed January 4, 2023 and effective January 1, 2023.		10-K	10.38	02/28/23
10.40	Amendment to Severance Pay Agreement, dated February 20, 2025, between Sempra and Jeffrey W. Martin.		8-K	10.1	02/20/25
10.41	Amended and Restated Severance Pay Agreement between Sempra and Karen L. Sedgwick, signed January 25, 2024 and effective January 1, 2024.		10-K	10.42	02/27/24
10.42	Amended and Restated Severance Pay Agreement between Sempra and Caroline A. Winn, signed July 14, 2025 and effective July 5, 2025.		10-Q	10.1	08/07/25
10.43	Severance Pay Agreement between Sempra and Dyan Z. Wold, signed March 8, 2023 and effective March 1, 2023.		10-Q	10.2	08/07/25
10.44*	Letter Agreement from Sempra Infrastructure to Justin C. Bird dated April 18, 2023.		10-K	10.47*	02/25/25
10.45*	Aircraft Time Sharing Agreement, effective March 11, 2024, between Sempra and Jeffrey W. Martin.		10-Q	10.11*	05/07/24
10.46	Sempra Cash Severance Payments Policy.		10-Q	10.12	05/07/24
Sempra / San Diego Gas & Electric Company
10.47	Form of San Diego Gas & Electric Company Executive Incentive Compensation Plan.		10-K	10.64	02/27/14
10.48	Severance Pay Agreement between Sempra and Scott Crider, signed March 8, 2023 and effective March 1, 2023.		10-K	10.52	02/25/25
10.49	Amended and Restated Severance Pay Agreement between Sempra and Kevin C. Geraghty, signed March 6, 2023 and effective March 1, 2023.		10-Q	10.9	05/04/23
10.50	Severance Pay Agreement between Sempra and Maritza Mekitarian, signed February 12, 2026 and effective as of January 31, 2026.	X

• Portions of the exhibit have been omitted in accordance with applicable SEC rules.

Tab le of Cont ents

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
Sempra / Southern California Gas Company
10.51	Form of Southern California Gas Company Executive Incentive Compensation Plan.		10-K	10.71	02/27/14
10.52	Amended and Restated Severance Pay Agreement between Sempra and David J. Barrett, signed March 9, 2023 and effective March 1, 2023.		10-Q	10.12	05/04/23
10.53	Amended and Restated Severance Pay Agreement between Sempra and Maryam S. Brown, signed January 22, 2025 and effective January 1, 2025.		10-K	10.59	02/25/25
10.54	Amended and Restated Severance Pay Agreement between Sempra and Mia L. DeMontigny, signed March 8, 2023 and effective March 1, 2023.		10-Q	10.15	05/04/23
10.55	Severance Pay Agreement between Sempra and Sara P. Mijares, signed March 8, 2023 and effective March 1, 2023.		10-Q	10.1	08/06/24
10.56	Severance Pay Agreement between Sempra and Rodger R. Schwecke, signed March 8, 2023 and effective March 1, 2023.		10-Q	10.7	05/08/25
10.57	Severance Pay Agreement between Sempra and Erin M. Smith, signed March 10, 2023 and effective March 1, 2023.		10-Q	10.4	08/07/25
10.58*	Letter Agreement from Southern California Gas Company to Mia DeMontigny dated June 2, 2025.		10-Q	10.5*	08/07/25
10.59*	Letter Agreement from Southern California Gas Company to Sara Mijares dated June 2, 2025.		10-Q	10.1*	11/05/25
10.60*	Letter Agreement from Southern California Gas Company to Erin Smith dated June 3, 2025.		10-Q	10.2*	11/05/25
EXHIBIT 14 -- CODE OF ETHICS
Sempra / San Diego Gas & Electric Company / Southern California Gas Company
14.1	Sempra Code of Business Conduct and Ethics for Directors and Principal and Executive Officers (also applies to Principal Officers of San Diego Gas & Electric Company and Southern California Gas Company).		10-K	14.1	02/25/22
EXHIBIT 19 -- INSIDER TRADING POLICIES AND PROCEDURES
Sempra / San Diego Gas & Electric Company / Southern California Gas Company
19.1	Insider Trading and Information Confidentiality Policy.		10-K	19.1	02/25/25

• Portions of the exhibit have been omitted in accordance with applicable SEC rules.

Tab le of Cont ents

EXHIBIT INDEX (CONTINUED) — Exhibit Number	Exhibit Description	Filed or Furnished Herewith
EXHIBIT 21 -- SUBSIDIARIES
Sempra
21.1	Sempra Schedule of Certain Subsidiaries at December 31, 2025.	X
EXHIBIT 23 -- CONSENTS OF EXPERTS AND COUNSEL
Sempra
23.1	Sempra Consent of Independent Registered Public Accounting Firm.	X
23.2	Oncor Electric Delivery Holdings Company LLC Consent of Independent Auditors.	X
San Diego Gas & Electric Company
23.3	San Diego Gas & Electric Company Consent of Independent Registered Public Accounting Firm.	X
Southern California Gas Company
23.4	Southern California Gas Company Consent of Independent Registered Public Accounting Firm.	X
EXHIBIT 24 -- POWERS OF ATTORNEY
Sempra
24.1	Power of attorney of Sempra signatories (incorporated by reference to the signature page hereto).	X
San Diego Gas & Electric Company
24.2	Power of attorney of San Diego Gas & Electric Company signatories (incorporated by reference to the signature page hereto).	X
Southern California Gas Company
24.3	Power of attorney of Southern California Gas Company signatories (incorporated by reference to the signature page hereto).	X
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

Tab le of Cont ents

EXHIBIT INDEX (CONTINUED)
			Incorporated by Reference
Exhibit Number	Exhibit Description	Filed or Furnished Herewith	Form or Registration Statement No.	Exhibit or Appendix	Filing Date
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 97 -- POLICY RELATING TO RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION
Sempra / San Diego Gas & Electric Company / Southern California Gas Company
97.1	Compensation Recovery Policy.		10-K	97.1	02/27/24
EXHIBIT 99 -- ADDITIONAL EXHIBITS
Sempra
99.1	Audited consolidated financial statements of Oncor Electric Delivery Holdings Company LLC and subsidiaries as of December 31, 2025 and 2024 for each of the three years ended in the period ended December 31, 2025, and the related Independent Auditors’ Report.	X
EXHIBIT 101 -- INTERACTIVE DATA FILE
101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document.	X
101.SCH	XBRL Taxonomy Extension Schema Document.	X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.	X
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.	X
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.	X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	X
EXHIBIT 104 -- COVER PAGE
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

Tab le of Cont ents

ITEM 16. FORM 10-K SUMMARY

Not applicable.

Tab le of Cont ents

Sempra:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SEMPRA, (Registrant)
By: /s/ J. Walker Martin
J. Walker Martin Chairman, Chief Executive Officer and President
Date: February 26, 2026
POWER OF ATTORNEY
Each of the undersigned officers and directors of the registrant hereby severally constitutes and appoints each individual who, at the time of acting under this power of attorney, is the Principal Executive Officer (however designated), the Principal Financial Officer (however designated) or the Principal Accounting Officer (however designated) of Sempra, and each of them singly (with full power to each of them to act alone), as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution in each of them, for him or her and in his or her name, place and stead, and in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto and other documents in connection therewith, with the U.S. Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. This power of attorney shall be governed by and construed in accordance with the laws of the State of California and applicable federal securities laws. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Name/Title	Signature	Date
Principal Executive Officer: J. Walker Martin Chief Executive Officer and President	/s/ J. Walker Martin	February 26, 2026
Principal Financial Officer: Karen L. Sedgwick Executive Vice President and Chief Financial Officer	/s/ Karen L. Sedgwick	February 26, 2026
Principal Accounting Officer: Dyan Z. Wold Vice President, Controller and Chief Accounting Officer	/s/ Dyan Z. Wold	February 26, 2026

Tab le of Cont ents

Directors:	Signature	Date
J. Walker Martin, Chairman	/s/ J. Walker Martin	February 26, 2026
Andrés Conesa, Director	/s/ Andrés Conesa	February 26, 2026
Pablo A. Ferrero, Director	/s/ Pablo A. Ferrero	February 26, 2026
Jennifer M. Kirk, Director	/s/ Jennifer M. Kirk	February 26, 2026
Richard J. Mark, Director	/s/ Richard J. Mark	February 26, 2026
Michael N. Mears, Director	/s/ Michael N. Mears	February 26, 2026
Kevin C. Sagara, Director	/s/ Kevin C. Sagara	February 26, 2026
Jack T. Taylor, Director	/s/ Jack T. Taylor	February 26, 2026
Cynthia J. Warner, Director	/s/ Cynthia J. Warner	February 26, 2026
Anya Weaving, Director	/s/ Anya Weaving	February 26, 2026
James C. Yardley, Director	/s/ James C. Yardley	February 26, 2026

Tab le of Cont ents

San Diego Gas & Electric Company:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SAN DIEGO GAS & ELECTRIC COMPANY, (Registrant)
By: /s/ Scott B. Crider
Scott B. Crider President
Date: February 26, 2026
POWER OF ATTORNEY
Each of the undersigned officers and directors of the registrant hereby severally constitutes and appoints each individual who, at the time of acting under this power of attorney, is the Principal Executive Officer (however designated), the Principal Financial Officer (however designated) or the Principal Accounting Officer (however designated) of San Diego Gas & Electric Company, and each of them singly (with full power to each of them to act alone), as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution in each of them, for him or her and in his or her name, place and stead, and in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto and other documents in connection therewith, with the U.S. Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. This power of attorney shall be governed by and construed in accordance with the laws of the State of California and applicable federal securities laws. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Name/Title	Signature	Date
Principal Executive Officer: Scott B. Crider President	/s/ Scott B. Crider	February 26, 2026
Principal Financial Officer: Valerie A. Bille Senior Vice President and Chief Financial Officer	/s/ Valerie A. Bille	February 26, 2026
Principal Accounting Officer: Maritza Mekitarian Vice President, Controller and Chief Accounting Officer	/s/ Maritza Mekitarian	February 26, 2026

Tab le of Cont ents

Directors:	Signature	Date
Caroline A. Winn, Non-Executive Chairman	/s/ Caroline A. Winn	February 26, 2026
David J. Barrett, Director	/s/ David J. Barrett	February 26, 2026
Diana L. Day, Director	/s/ Diana L. Day	February 26, 2026
Glen A. Donovan, Director	/s/ Glen A. Donovan	February 26, 2026
Karen L. Sedgwick, Director	/s/ Karen L. Sedgwick	February 26, 2026

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT:

No annual report to security holders covering the registrant’s last fiscal year and no proxy statement, form of proxy or other proxy soliciting material with respect to any annual or other meeting of security holders has been sent to security holders during the period covered by this annual report on Form 10-K, and no such materials are to be furnished to security holders subsequent to the filing of this annual report on Form 10-K.

Tab le of Cont ents

Southern California Gas Company:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SOUTHERN CALIFORNIA GAS COMPANY, (Registrant)
By: /s/ Maryam S. Brown
Maryam S. Brown Chief Executive Officer and President
Date: February 26, 2026
POWER OF ATTORNEY
Each of the undersigned officers and directors of the registrant hereby severally constitutes and appoints each individual who, at the time of acting under this power of attorney, is the Principal Executive Officer (however designated), the Principal Financial Officer (however designated) or the Principal Accounting Officer (however designated) of Southern California Gas Company, and each of them singly (with full power to each of them to act alone), as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution in each of them, for him or her and in his or her name, place and stead, and in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto and other documents in connection therewith, with the U.S. Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. This power of attorney shall be governed by and construed in accordance with the laws of the State of California and applicable federal securities laws. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Name/Title	Signature	Date
Principal Executive Officer: Maryam S. Brown Chief Executive Officer and President	/s/ Maryam S. Brown	February 26, 2026
Principal Financial Officer: Valerie A. Bille Senior Vice President and Chief Financial Officer	/s/ Valerie A. Bille	February 26, 2026
Principal Accounting Officer: Sara P. Mijares Vice President, Controller and Chief Accounting Officer	/s/ Sara P. Mijares	February 26, 2026

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Directors:	Signature	Date
Caroline A. Winn, Non-Executive Chairman	/s/ Caroline A. Winn	February 26, 2026
Maryam S. Brown, Director	/s/ Maryam S. Brown	February 26, 2026
Diana L. Day, Director	/s/ Diana L. Day	February 26, 2026
Lisa M. Larroque Alexander, Director	/s/ Lisa M. Larroque Alexander	February 26, 2026
Karen L. Sedgwick, Director	/s/ Karen L. Sedgwick	February 26, 2026

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS — Reports of Independent Registered Public Accounting Firm (PCAOB ID 34 )			F-2
Consolidated Financial Statements:	Sempra	San Diego Gas & Electric Company	Southern California Gas Company
Consolidated Statements of Operations for the years ended December 31, 2025, 2024 and 2023	F-8	F-16	F-22
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2025, 2024 and 2023	F-9	F-17	F-23
Consolidated Balance Sheets at December 31, 2025 and 2024	F-10	F-18	F-24
Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024 and 2023	F-12	F-20	F-26
Consolidated Statements of Changes in Contingently Redeemable Noncontrolling Interest and Equity for the years ended December 31, 2025, 2024 and 2023	F-14	N/A	N/A
Statements of Changes in Shareholders Equity for the years ended December 31, 2025, 2024 and 2023	N/A	F-21	F-27
Notes to Consolidated Financial Statements
Note 1. Significant Accounting Policies and Other Financial Data			F-28
Note 2. New Accounting Standards			F-52
Note 3. Revenues			F-53
Note 4. Regulatory Matters			F-59
Note 5. Sempra – Investments in Unconsolidated Entities			F-63
Note 6. Sempra – Divestitures			F-68
Note 7. Debt and Credit Facilities			F-71
Note 8. Income Taxes			F-79
Note 9. Employee Benefit Plans			F-88
Note 10. Derivative Financial Instruments			F-104
Note 11. Fair Value Measurements			F-112
Note 12. Sempra – Contingently Redeemable Noncontrolling Interest			F-119
Note 13. Equity and Earnings Per Common Share			F-120
Note 1 4 . Share-Based Compensation			F-126
Note 1 5 . San Onofre Nuclear Generating Station			F-130
Note 1 6 . Commitments, Contingencies and Guarantees			F-132
Note 1 7 . Segment Information			F-147

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Board of Directors of Sempra:

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Sempra and subsidiaries (“Sempra”) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income (loss), changes in contingently redeemable noncontrolling interest and equity, and cash flows for each of the three years in the period ended December 31, 2025, the related notes, and the schedule listed in Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of Sempra as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), Sempra’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2026, expressed an unqualified opinion on Sempra’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of Sempra’s management. Our responsibility is to express an opinion on Sempra’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sempra in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Regulatory Accounting – Impact of Rate Regulation on the Financial Statements – Refer to Note 1 of the Notes to Financial Statements

Critical Audit Matter Description

Sempra is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

We identified the impact of rate regulation as a critical audit matter due to the high degree of subjectivity involved in assessing the impact of regulatory orders and future actions by the Commissions on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:

▪ We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

▪ We read relevant regulatory orders issued by the Commissions for Sempra and other publicly available information to assess the likelihood of recovery in future rates, or of a future reduction in rates, based on precedents of the Commissions’ treatment of similar costs under similar circumstances.

▪ We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

▪ We evaluated Sempra’s disclosures related to the impacts of rate regulation.

Accounting for the PA2 JVCo Equity Subscription and CRNCI Classification— Refer to Note 12 of the Notes to Financial Statements

Critical Audit Matter Description

As more fully described in Note 12 to the financial statements, in September 2025, a subsidiary of Sempra that owns Port Arthur LNG II (“PA2 JVCo”) issued 49.9% of its equity interests to an affiliate of 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. Management recorded the closing effects of the equity subscription, including cash proceeds received, transaction costs, and related equity impacts, including increases to contingently redeemable noncontrolling interest (“CRNCI”) presented outside of permanent equity.

We identified management’s evaluation of the appropriate classification and presentation of Blackstone’s interest, specifically, whether it should be presented outside of permanent equity as CRNCI (as opposed to within permanent equity or as a liability). Management applied significant judgment in assessing the relevant terms and conditions of the equity subscription and related arrangements, including the nature of the contingent redemption provisions and the likelihood of such contingent redemption provisions being met. Auditing these matters involved challenging auditor judgment and the use of specialized accounting knowledge to evaluate equity classification under the applicable accounting guidance.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the accounting for the PA2 JVCo equity subscription included the following, among others:

• We tested the effectiveness of management’s controls over the evaluation and classification of Blackstone’s interest as CRNCI, including the assessment of contingent redemption provisions and their likelihood.

• We obtained and read the executed transaction agreements and related governing documents (including the equity subscription and related arrangements) to evaluate key terms impacting contingent redemption provisions relevant to CRNCI classification.

• We involved professionals with specialized accounting knowledge to assist in evaluating management’s application of the relevant accounting guidance for classification and presentation outside of permanent equity, including evaluating whether any terms (including those with redemption features) would require Blackstone’s interest to be classified as a liability.

• We evaluated the financial statement disclosures for completeness and consistency with the underlying agreements and recorded amounts.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2026

We have served as Sempra’s auditor since 1935.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholder and Board of Directors of San Diego Gas & Electric Company:

Opinion on the Financial Statements

We have audited the accompanying balance sheets of San Diego Gas & Electric Company (“SDG&E”) as of December 31, 2025 and 2024, the related statements of operations, comprehensive income (loss), changes in shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of SDG&E as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), SDG&E’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2026, expressed an unqualified opinion on SDG&E’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of SDG&E’s management. Our responsibility is to express an opinion on SDG&E’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SDG&E in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Accounting – Impact of Rate Regulation on the Financial Statements – Refer to Note 1 of the Notes to Financial Statements

Critical Audit Matter Description

SDG&E is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

We identified the impact of rate regulation as a critical audit matter due to the high degree of subjectivity involved in assessing the impact of regulatory orders and future actions by the Commissions on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:

▪ We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

▪ We read relevant regulatory orders issued by the Commissions for SDG&E and other publicly available information to assess the likelihood of recovery in future rates, or of a future reduction in rates, based on precedents of the Commissions’ treatment of similar costs under similar circumstances.

▪ We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

▪ We evaluated SDG&E’s disclosures related to the impacts of rate regulation.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2026

We have served as SDG&E’s auditor since 1935.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Board of Directors of Southern California Gas Company:

Opinion on the Financial Statements

We have audited the accompanying balance sheets of Southern California Gas Company (“SoCalGas”) as of December 31, 2025 and 2024, the related statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of SoCalGas as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), SoCalGas’ internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2026, expressed an unqualified opinion on SoCalGas’ internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of SoCalGas’ management. Our responsibility is to express an opinion on SoCalGas’ financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SoCalGas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Accounting – Impact of Rate Regulation on the Financial Statements – Refer to Note 1 of the Notes to Financial Statements

Critical Audit Matter Description

SoCalGas is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

We identified the impact of rate regulation as a critical audit matter due to the high degree of subjectivity involved in assessing the impact of regulatory orders and future actions by the Commissions on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

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How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:

▪ We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

▪ We read relevant regulatory orders issued by the Commissions for SoCalGas and other publicly available information to assess the likelihood of recovery in future rates, or of a future reduction in rates, based on precedents of the Commissions’ treatment of similar costs under similar circumstances.

▪ We evaluated the external information and compared it to management’s recorded regulatory asset and liability balances for completeness.

▪ We evaluated SoCalGas’ disclosures related to the impacts of rate regulation.

/s/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2026

We have served as SoCalGas’ auditor since 1937.

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SEMPRA
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Years ended December 31,
	2025	2024	2023
REVENUES
Utilities:
Natural gas	$ 7,319	$ 7,141	$ 9,495
Electric	4,552	4,296	4,334
Energy-related businesses	1,831	1,748	2,891
Total revenues	13,702	13,185	16,720
EXPENSES AND OTHER INCOME
Utilities:
Cost of natural gas	( 1,282 )	( 1,132 )	( 3,719 )
Cost of electric fuel and purchased power	( 385 )	( 245 )	( 375 )
Energy-related businesses cost of sales	( 367 )	( 380 )	( 548 )
Operation and maintenance	( 5,281 )	( 5,336 )	( 5,458 )
Regulatory disallowances	( 651 )	—	—
Depreciation and amortization	( 2,563 )	( 2,437 )	( 2,227 )
Franchise fees and other taxes	( 744 )	( 693 )	( 677 )
Other income, net	169	136	131
Interest income	103	61	89
Interest expense	( 1,532 )	( 1,049 )	( 1,309 )
Income before income taxes and equity earnings	1,169	2,110	2,627
Income tax expense	( 701 )	( 219 )	( 490 )
Equity earnings	1,604	1,609	1,481
Net income	2,072	3,500	3,618
Earnings attributable to noncontrolling interests	( 238 )	( 638 )	( 543 )
Losses attributable to contingently redeemable noncontrolling interest	3	—	—
Preferred deemed dividends	( 11 )	—	—
Preferred dividends	( 29 )	( 44 )	( 44 )
Preferred dividends of subsidiary	( 1 )	( 1 )	( 1 )
Earnings attributable to common shares	$ 1,796	$ 2,817	$ 3,030
Basic EPS:
Earnings	$ 2.75	$ 4.44	$ 4.81
Weighted-average common shares outstanding	652,697	633,795	630,296
Diluted EPS:
Earnings	$ 2.75	$ 4.42	$ 4.79
Weighted-average common shares outstanding	653,826	637,943	632,733

See Notes to Consolidated Financial Statements.

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SEMPRA
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2025, 2024 and 2023
	Sempra shareholders’ equity
	Pretax amount	Income tax (expense) benefit	Net-of-tax amount	NCI (after tax)	CRNCI (after tax)	Total
2025:
Net income (loss)	$ 2,538	$ ( 701 )	$ 1,837	$ 238	$ ( 3 )	$ 2,072
Other comprehensive income (loss):
Foreign currency translation adjustments	21	—	21	9	—	30
Financial instruments	( 76 )	7	( 69 )	( 14 )	—	( 83 )
Pension and other postretirement benefits	19	( 2 )	17	—	—	17
Total other comprehensive loss	( 36 )	5	( 31 )	( 5 )	—	( 36 )
Comprehensive income (loss)	2,502	( 696 )	1,806	233	( 3 )	2,036
Preferred dividends of subsidiary	( 1 )	—	( 1 )	—	—	( 1 )
Comprehensive income, after preferred dividends of subsidiary	$ 2,501	$ ( 696 )	$ 1,805	$ 233	$ ( 3 )	$ 2,035
2024:
Net income	$ 3,081	$ ( 219 )	$ 2,862	$ 638	$ —	$ 3,500
Other comprehensive income (loss):
Foreign currency translation adjustments	( 30 )	—	( 30 )	( 14 )	—	( 44 )
Financial instruments	14	( 2 )	12	25	—	37
Pension and other postretirement benefits	18	( 16 )	2	—	—	2
Total other comprehensive income (loss)	2	( 18 )	( 16 )	11	—	( 5 )
Comprehensive income	3,083	( 237 )	2,846	649	—	3,495
Preferred dividends of subsidiary	( 1 )	—	( 1 )	—	—	( 1 )
Comprehensive income, after preferred dividends of subsidiary	$ 3,082	$ ( 237 )	$ 2,845	$ 649	$ —	$ 3,494
2023:
Net income	$ 3,565	$ ( 490 )	$ 3,075	$ 543	$ —	$ 3,618
Other comprehensive income (loss):
Foreign currency translation adjustments	23	—	23	10	—	33
Financial instruments	57	( 18 )	39	( 38 )	—	1
Pension and other postretirement benefits	( 39 )	8	( 31 )	—	—	( 31 )
Total other comprehensive income (loss)	41	( 10 )	31	( 28 )	—	3
Comprehensive income	3,606	( 500 )	3,106	515	—	3,621
Preferred dividends of subsidiary	( 1 )	—	( 1 )	—	—	( 1 )
Comprehensive income, after preferred dividends of subsidiary	$ 3,605	$ ( 500 )	$ 3,105	$ 515	$ —	$ 3,620

See Notes to Consolidated Financial Statements.

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SEMPRA
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,
	2025	2024
ASSETS
Current assets:
Cash and cash equivalents	$ 29	$ 1,565
Restricted cash	2	21
Accounts receivable – trade, net	1,767	1,983
Accounts receivable – other, net	157	397
Due from unconsolidated affiliates	—	13
Income taxes receivable	71	90
Inventories	561	559
Regulatory assets	761	60
Greenhouse gas allowances	203	217
Assets held for sale	31,024	—
Other current assets	262	380
Total current assets	34,837	5,285
Other assets:
Restricted cash	—	3
Regulatory assets	3,868	3,937
Greenhouse gas allowances	1,221	845
Nuclear decommissioning trusts	899	875
Dedicated assets in support of certain benefit plans	605	585
Deferred income taxes	10	172
Right-of-use assets – operating leases	1,262	1,177
Investment in Oncor Holdings	17,472	15,400
Other investments	147	2,534
Goodwill	—	1,602
Other intangible assets	—	292
Wildfire fund	246	262
Other long-term assets	1,300	1,749
Total other assets	27,030	29,433
Property, plant and equipment:
Property, plant and equipment	66,900	80,397
Less accumulated depreciation and amortization	( 17,889 )	( 18,960 )
Property, plant and equipment, net	49,011	61,437
Total assets	$ 110,878	$ 96,155

See Notes to Consolidated Financial Statements.

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SEMPRA
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31,
	2025	2024
LIABILITIES, CONTINGENTLY REDEEMABLE NONCONTROLLING INTEREST, AND EQUITY
Current liabilities:
Short-term debt	$ 4,166	$ 2,016
Accounts payable – trade	1,461	2,238
Accounts payable – other	203	208
Due to unconsolidated affiliates	8	—
Dividends and interest payable	770	773
Accrued compensation and benefits	521	558
Regulatory liabilities	3	141
Current portion of long-term debt and finance leases	1,876	2,274
Greenhouse gas obligations	203	217
Liabilities held for sale	11,704	—
Other current liabilities	979	1,251
Total current liabilities	21,894	9,676
Long-term debt and finance leases	28,979	31,558
Deferred credits and other liabilities:
Due to unconsolidated affiliates	—	352
Regulatory liabilities	4,250	3,817
Greenhouse gas obligations	957	506
Pension and other postretirement benefit plan obligations, net of plan assets	124	168
Deferred income taxes	6,127	5,845
Asset retirement obligations	3,743	3,737
Deferred credits and other	2,805	2,708
Total deferred credits and other liabilities	18,006	17,133
Commitments and contingencies (Note 16)
Contingently redeemable noncontrolling interest	3,206	—
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; 652,731,668 and 650,629,876 shares outstanding at December 31, 2025 and 2024, respectively; no par value)	14,699	13,520
Retained earnings	17,092	16,979
Accumulated other comprehensive income (loss)	( 197 )	( 166 )
Total Sempra shareholders’ equity	31,594	31,222
Preferred stock of subsidiary	20	20
Other noncontrolling interests	7,179	6,546
Total equity	38,793	37,788
Total liabilities, contingently redeemable noncontrolling interest, and equity	$ 110,878	$ 96,155

See Notes to Consolidated Financial Statements.

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SEMPRA
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 2,072	$ 3,500	$ 3,618
Adjustments to reconcile net income to net cash provided by operating activities:
Regulatory disallowances	651	—	—
Depreciation and amortization	2,563	2,437	2,227
Deferred income taxes and investment tax credits	533	( 20 )	249
Equity earnings	( 1,604 )	( 1,609 )	( 1,481 )
Share-based compensation expense	64	86	80
Fixed-price contracts and other derivatives	92	( 197 )	( 666 )
Bad debt expense	65	209	458
Other	( 16 )	20	( 14 )
Net change in working capital components:
Accounts receivable	( 66 )	118	168
Due to/from unconsolidated affiliates, net	17	30	26
Income taxes receivable/payable, net	( 187 )	( 49 )	142
Inventories	( 64 )	( 74 )	( 80 )
Other current assets	( 296 )	( 30 )	11
Accounts payable	( 7 )	( 131 )	( 270 )
Regulatory balancing accounts, net	( 829 )	( 456 )	260
Other current liabilities	177	130	1,172
Distributions from investments	1,120	1,093	912
Changes in other noncurrent assets and liabilities, net	280	( 150 )	( 594 )
Net cash provided by operating activities	4,565	4,907	6,218
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	( 10,612 )	( 8,215 )	( 8,397 )
Expenditures for investments	( 2,015 )	( 988 )	( 382 )
Distributions from investments	—	9	—
Purchases of nuclear decommissioning and other trust assets	( 1,031 )	( 889 )	( 610 )
Proceeds from sales of nuclear decommissioning and other trust assets	1,098	942	661
Other	23	23	12
Net cash used in investing activities	$ ( 12,537 )	$ ( 9,118 )	$ ( 8,716 )

See Notes to Consolidated Financial Statements.

Tab le of Cont ents

SEMPRA
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	$ ( 1,603 )	$ ( 1,499 )	$ ( 1,483 )
Preferred dividends paid	( 40 )	( 44 )	( 44 )
Redemption of preferred stock	( 900 )	—	—
Issuances of common stock, net	32	1,219	145
Repurchases of common stock	( 58 )	( 43 )	( 32 )
Issuances of debt (maturities greater than 90 days)	11,282	8,674	7,669
Payments on debt (maturities greater than 90 days) and finance leases	( 5,220 )	( 3,339 )	( 6,294 )
Increase (decrease) in short-term debt, net	1,262	( 557 )	552
Advances from unconsolidated affiliates	150	85	31
Contributions from contingently redeemable noncontrolling interest, net of transaction costs	5,294	—	—
Proceeds from investor equity subscription	106	—	—
Proceeds from sales of noncontrolling interests, net	—	—	1,219
Contributions from noncontrolling interests	327	1,235	1,570
Distributions to noncontrolling interests	( 609 )	( 297 )	( 730 )
Termination of interest rate and settlement of cross-currency swaps	—	46	( 99 )
Other	( 93 )	( 56 )	( 85 )
Net cash provided by financing activities	9,930	5,424	2,419
Effect of exchange rate changes on cash, cash equivalents and restricted cash	5	( 13 )	6
Increase (decrease) in cash, cash equivalents and restricted cash	1,963	1,200	( 73 )
Cash, cash equivalents and restricted cash, January 1	1,589	389	462
Cash, cash equivalents and restricted cash, December 31	$ 3,552	$ 1,589	$ 389
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$ 1,449	$ 1,205	$ 1,172
Income tax payments, net of refunds	376	289	197
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued interest receivable capitalized to note receivable	$ 18	$ 17	$ 16
Repayments of advances from unconsolidated affiliate in lieu of distributions	45	62	36
Accrued capital expenditures for PP&E	1,653	1,181	1,052
Capital expenditures reclassified from other assets to PP&E	3	53	18
Increase in ARO capitalized to PP&E	11	1	33
Increase in finance lease obligations capitalized to PP&E	47	41	57
Amortized debt issuance costs capitalized to PP&E	22	13	4
Unamortized debt issuance costs reclassified from noncurrent assets to long-term debt	67	27	9
Accrued interest payable capitalized to due to unconsolidated affiliate	18	16	—
Change in equity related to allocation of interests, net of tax	1,771	—	—
Preferred deemed dividends	11	—	—
Preferred dividends declared but not paid	—	11	11
Common dividends declared but not paid	421	393	376
Common dividends issued in stock	52	54	—
Contributions from NCI	—	—	200

See Notes to Consolidated Financial Statements.

Tab le of Cont ents

SEMPRA
CONSOLIDATED STATEMENTS OF CHANGES IN CONTINGENTLY REDEEMABLE NONCONTROLLING INTEREST AND EQUITY
(Dollars in millions)
	Years ended December 31, 2025, 2024 and 2023
	CRNCI	Preferred stock	Common stock	Retained earnings	AOCI	Sempra shareholders' equity	NCI	Total equity
Balance at December 31, 2022	$ —	$ 889	$ 12,160	$ 14,201	$ ( 135 )	$ 27,115	$ 2,141	$ 29,256
Net income				3,075		3,075	543	3,618
Other comprehensive income (loss)					31	31	( 28 )	3
Share-based compensation expense			80			80		80
Dividends declared:
Series C preferred stock ($ 48.75 /share)				( 44 )		( 44 )		( 44 )
Common stock ($ 2.38 /share)				( 1,499 )		( 1,499 )		( 1,499 )
Preferred dividends of subsidiary				( 1 )		( 1 )		( 1 )
Issuances of common stock			144			144		144
Repurchases of common stock			( 32 )			( 32 )		( 32 )
CRNCI and NCI activities:
Contributions from NCI			( 145 )			( 145 )	1,770	1,625
Distributions to NCI							( 730 )	( 730 )
Sales			( 3 )		( 46 )	( 49 )	1,283	1,234
Balance at December 31, 2023	—	889	12,204	15,732	( 150 )	28,675	4,979	33,654
Net income				2,862		2,862	638	3,500
Other comprehensive (loss) income					( 16 )	( 16 )	11	( 5 )
Share-based compensation expense			86			86		86
Dividends declared:
Series C preferred stock ($ 48.75 /share)				( 44 )		( 44 )		( 44 )
Common stock ($ 2.48 /share)				( 1,570 )		( 1,570 )		( 1,570 )
Preferred dividends of subsidiary				( 1 )		( 1 )		( 1 )
Issuances of common stock			1,273			1,273		1,273
Repurchases of common stock			( 43 )			( 43 )		( 43 )
CRNCI and NCI activities:
Contributions from NCI							1,235	1,235
Distributions to NCI							( 297 )	( 297 )
Balance at December 31, 2024	$ —	$ 889	$ 13,520	$ 16,979	$ ( 166 )	$ 31,222	$ 6,566	$ 37,788

See Notes to Consolidated Financial Statements.

Tab le of Cont ents

SEMPRA
CONSOLIDATED STATEMENTS OF CHANGES IN CONTINGENTLY REDEEMABLE NONCONTROLLING INTEREST AND EQUITY (CONTINUED)
(Dollars in millions)
	Years ended December 31, 2025, 2024 and 2023
	CRNCI	Preferred stock	Common stock	Retained earnings	AOCI	Sempra shareholders' equity	NCI	Total equity
Balance at December 31, 2024	$ —	$ 889	$ 13,520	$ 16,979	$ ( 166 )	$ 31,222	$ 6,566	$ 37,788
Net (loss) income	( 3 )			1,837		1,837	238	2,075
Other comprehensive loss					( 31 )	( 31 )	( 5 )	( 36 )
Share-based compensation expense			64			64		64
Dividends declared:
Series C preferred stock ($ 36.57 /share)				( 29 )		( 29 )		( 29 )
Common stock ($ 2.58 /share)				( 1,683 )		( 1,683 )		( 1,683 )
Redemption of preferred stock		( 900 )				( 900 )		( 900 )
Preferred deemed dividends		11		( 11 )		—		—
Preferred dividends of subsidiary				( 1 )		( 1 )		( 1 )
Issuances of common stock			84			84		84
Repurchases of common stock			( 58 )			( 58 )		( 58 )
CRNCI and NCI activities:
Contributions from CRNCI	5,248
Investor equity subscription	76		16			16	9	25
Allocation of interests	( 2,115 )		1,073			1,073	673	1,746
Contributions from NCI							327	327
Distributions to NCI							( 609 )	( 609 )
Balance at December 31, 2025	$ 3,206	$ —	$ 14,699	$ 17,092	$ ( 197 )	$ 31,594	$ 7,199	$ 38,793

See Notes to Consolidated Financial Statements.

Tab le of Cont ents

SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF OPERATIONS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Operating revenues:
Electric	$ 4,568	$ 4,313	$ 4,349
Natural gas	1,129	1,028	1,248
Total operating revenues	5,697	5,341	5,597
Operating expenses:
Cost of electric fuel and purchased power	448	308	445
Cost of natural gas	237	242	532
Operation and maintenance	1,725	1,692	1,846
Regulatory disallowances	651	—	—
Depreciation and amortization	1,316	1,223	1,098
Franchise fees and other taxes	434	402	381
Total operating expenses	4,811	3,867	4,302
Operating income	886	1,474	1,295
Other income, net	106	90	97
Interest income	2	5	15
Interest expense	( 559 )	( 525 )	( 497 )
Income before income taxes	435	1,044	910
Income tax benefit (expense)	128	( 153 )	26
Net income/Earnings attributable to common shares	$ 563	$ 891	$ 936

See Notes to Financial Statements.

Tab le of Cont ents

SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2025, 2024 and 2023
	Pretax amount	Income tax benefit (expense)	Net-of-tax amount
2025:
Net income	$ 435	$ 128	$ 563
Other comprehensive income (loss):
Pension and other postretirement benefits	6	—	6
Total other comprehensive income	6	—	6
Comprehensive income	$ 441	$ 128	$ 569
2024:
Net income	$ 1,044	$ ( 153 )	$ 891
Other comprehensive income (loss):
Pension and other postretirement benefits	( 3 )	( 1 )	( 4 )
Total other comprehensive loss	( 3 )	( 1 )	( 4 )
Comprehensive income	$ 1,041	$ ( 154 )	$ 887
2023:
Net income	$ 910	$ 26	$ 936
Other comprehensive income (loss):
Pension and other postretirement benefits	( 2 )	1	( 1 )
Total other comprehensive loss	( 2 )	1	( 1 )
Comprehensive income	$ 908	$ 27	$ 935

See Notes to Financial Statements.

Tab le of Cont ents

SAN DIEGO GAS & ELECTRIC COMPANY
BALANCE SHEETS
(Dollars in millions)
	December 31,
	2025	2024
ASSETS
Current assets:
Cash and cash equivalents	$ 7	$ —
Accounts receivable – trade, net	809	774
Accounts receivable – other, net	92	89
Due from unconsolidated affiliates	1	—
Income taxes receivable, net	30	27
Inventories	267	202
Prepaid expenses	121	139
Regulatory assets	433	16
Greenhouse gas allowances	28	27
Other current assets	18	27
Total current assets	1,806	1,301
Other assets:
Regulatory assets	1,953	2,024
Greenhouse gas allowances	286	272
Nuclear decommissioning trusts	899	875
Right-of-use assets – operating leases	1,047	795
Wildfire fund	246	262
Other long-term assets	141	133
Total other assets	4,572	4,361
Property, plant and equipment:
Property, plant and equipment	35,033	33,162
Less accumulated depreciation and amortization	( 8,729 )	( 8,051 )
Property, plant and equipment, net	26,304	25,111
Total assets	$ 32,682	$ 30,773

See Notes to Financial Statements.

Tab le of Cont ents

SAN DIEGO GAS & ELECTRIC COMPANY
BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31,
	2025	2024
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities:
Short-term debt	$ 531	$ 417
Accounts payable – trade	712	704
Accounts payable – other	42	38
Due to unconsolidated affiliates	59	59
Interest payable	94	84
Accrued compensation and benefits	174	175
Regulatory liabilities	3	75
Current portion of long-term debt and finance leases	798	42
Greenhouse gas obligations	28	27
Asset retirement obligations	107	97
Other current liabilities	273	269
Total current liabilities	2,821	1,987
Long-term debt and finance leases	10,081	10,018
Deferred credits and other liabilities:
Regulatory liabilities	2,960	2,701
Greenhouse gas obligations	137	62
Pension obligation, net of plan assets	19	28
Deferred income taxes	3,286	3,211
Asset retirement obligations	746	803
Deferred credits and other	1,699	1,399
Total deferred credits and other liabilities	8,847	8,204
Commitments and contingencies (Note 16)
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 earnings	9,279	8,916
Accumulated other comprehensive income (loss)	( 6 )	( 12 )
Total shareholder’s equity	10,933	10,564
Total liabilities and shareholder’s equity	$ 32,682	$ 30,773

See Notes to Financial Statements.

Tab le of Cont ents

SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 563	$ 891	$ 936
Adjustments to reconcile net income to net cash provided by operating activities:
Regulatory disallowances	651	—	—
Depreciation and amortization	1,316	1,223	1,098
Deferred income taxes and investment tax credits	( 145 )	169	135
Bad debt expense	45	55	112
Other	—	( 14 )	( 35 )
Net change in working capital components:
Accounts receivable	( 82 )	92	( 213 )
Due to/from unconsolidated affiliates, net	( 8 )	( 14 )	( 62 )
Income taxes receivable/payable, net	( 3 )	209	( 236 )
Inventories	( 65 )	( 49 )	( 19 )
Other current assets	( 3 )	( 21 )	( 17 )
Accounts payable	—	( 32 )	31
Regulatory balancing accounts, net	( 535 )	( 429 )	571
Other current liabilities	46	( 21 )	129
Changes in noncurrent assets and liabilities, net	( 116 )	14	( 494 )
Net cash provided by operating activities	1,664	2,073	1,936
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	( 2,427 )	( 2,522 )	( 2,540 )
Purchases of nuclear decommissioning trust assets	( 926 )	( 826 )	( 532 )
Proceeds from sales of nuclear decommissioning trust assets	974	874	592
Other	10	13	8
Net cash used in investing activities	( 2,369 )	( 2,461 )	( 2,472 )
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	( 200 )	( 225 )	( 100 )
Issuances of debt (maturities greater than 90 days)	848	594	1,389
Payments on debt (maturities greater than 90 days) and finance leases	( 43 )	( 442 )	( 490 )
Increase (decrease) in short-term debt, net	114	417	( 205 )
Debt issuance costs	( 7 )	( 6 )	( 13 )
Other	—	—	( 2 )
Net cash provided by financing activities	712	338	579
Increase (decrease) in cash and cash equivalents	7	( 50 )	43
Cash and cash equivalents, January 1	—	50	7
Cash and cash equivalents, December 31	$ 7	$ —	$ 50
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$ 541	$ 514	$ 472
Income tax payments (refunds), net	23	( 225 )	76
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued capital expenditures for PP&E	$ 243	$ 230	$ 264
(Decrease) increase in ARO capitalized to PP&E	( 40 )	24	29
Increase in finance lease obligations capitalized to PP&E	14	14	17

See Notes to Financial Statements.

Tab le of Cont ents

SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Dollars in millions)
	Years ended December 31, 2025, 2024 and 2023
	Common stock	Retained earnings	Accumulated other comprehensive income (loss)	Total shareholder's equity
Balance at December 31, 2022	$ 1,660	$ 7,414	$ ( 7 )	$ 9,067
Net income		936		936
Other comprehensive loss			( 1 )	( 1 )
Common stock dividends declared ($ 0.86 /share)		( 100 )		( 100 )
Balance at December 31, 2023	1,660	8,250	( 8 )	9,902
Net income		891		891
Other comprehensive loss			( 4 )	( 4 )
Common stock dividends declared ($ 1.93 /share)		( 225 )		( 225 )
Balance at December 31, 2024	1,660	8,916	( 12 )	10,564
Net income		563		563
Other comprehensive income			6	6
Common stock dividends declared ($ 1.72 /share)		( 200 )		( 200 )
Balance at December 31, 2025	$ 1,660	$ 9,279	$ ( 6 )	$ 10,933

See Notes to Financial Statements.

Tab le of Cont ents

SOUTHERN CALIFORNIA GAS COMPANY
STATEMENTS OF OPERATIONS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Operating revenues	$ 6,291	$ 6,209	$ 8,289
Operating expenses:
Cost of natural gas	1,098	959	3,264
Operation and maintenance	2,689	2,791	2,821
Depreciation and amortization	1,016	910	839
Franchise fees and other taxes	293	273	278
Total operating expenses	5,096	4,933	7,202
Operating income	1,195	1,276	1,087
Other (expense) income, net	( 6 )	25	( 4 )
Interest income	6	9	9
Interest expense	( 367 )	( 323 )	( 285 )
Income before income taxes	828	987	807
Income tax benefit (expense)	38	( 31 )	5
Net income	866	956	812
Preferred dividends	( 1 )	( 1 )	( 1 )
Earnings attributable to common shares	$ 865	$ 955	$ 811

See Notes to Financial Statements.

Tab le of Cont ents

SOUTHERN CALIFORNIA GAS COMPANY
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2025, 2024 and 2023
	Pretax amount	Income tax benefit (expense)	Net-of-tax amount
2025:
Net income	$ 828	$ 38	$ 866
Other comprehensive income (loss):
Financial instruments	1	—	1
Pension and other postretirement benefits	10	( 1 )	9
Total other comprehensive income	11	( 1 )	10
Comprehensive income	$ 839	$ 37	$ 876
2024:
Net income	$ 987	$ ( 31 )	$ 956
Other comprehensive income (loss):
Financial instruments	1	—	1
Pension and other postretirement benefits	( 4 )	( 1 )	( 5 )
Total other comprehensive loss	( 3 )	( 1 )	( 4 )
Comprehensive income	$ 984	$ ( 32 )	$ 952
2023:
Net income	$ 807	$ 5	$ 812
Other comprehensive income (loss):
Financial instruments	1	—	1
Total other comprehensive income	1	—	1
Comprehensive income	$ 808	$ 5	$ 813

See Notes to Financial Statements.

Tab le of Cont ents

SOUTHERN CALIFORNIA GAS COMPANY
BALANCE SHEETS
(Dollars in millions)
	December 31,
	2025	2024
ASSETS
Current assets:
Cash and cash equivalents	$ 14	$ 12
Accounts receivable – trade, net	958	932
Accounts receivable – other, net	61	71
Due from unconsolidated affiliates	8	16
Inventories	294	287
Regulatory assets	328	42
Greenhouse gas allowances	175	176
Other current assets	91	71
Total current assets	1,929	1,607
Other assets:
Regulatory assets	1,888	1,844
Greenhouse gas allowances	935	526
Right-of-use assets – operating leases	68	18
Other long-term assets	738	609
Total other assets	3,629	2,997
Property, plant and equipment:
Property, plant and equipment	31,078	29,084
Less accumulated depreciation and amortization	( 8,948 )	( 8,330 )
Property, plant and equipment, net	22,130	20,754
Total assets	$ 27,688	$ 25,358

See Notes to Financial Statements.

Tab le of Cont ents

SOUTHERN CALIFORNIA GAS COMPANY
BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31,
	2025	2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Short-term debt	$ 903	$ 1,037
Accounts payable – trade	727	752
Accounts payable – other	161	158
Due to unconsolidated affiliates	35	38
Accrued compensation and benefits	219	245
Regulatory liabilities	—	64
Current portion of long-term debt and finance leases	529	373
Greenhouse gas obligations	175	176
Asset retirement obligations	98	91
Other current liabilities	536	451
Total current liabilities	3,383	3,385
Long-term debt and finance leases	7,619	7,031
Deferred credits and other liabilities:
Regulatory liabilities	1,290	1,115
Greenhouse gas obligations	820	410
Pension obligation, net of plan assets	18	45
Deferred income taxes	2,271	2,005
Asset retirement obligations	2,994	2,839
Deferred credits and other	457	367
Total deferred credits and other liabilities	7,850	6,781
Commitments and contingencies (Note 16)
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 earnings	6,515	5,850
Accumulated other comprehensive income (loss)	( 17 )	( 27 )
Total shareholders’ equity	8,836	8,161
Total liabilities and shareholders’ equity	$ 27,688	$ 25,358

See Notes to Financial Statements.

Tab le of Cont ents

SOUTHERN CALIFORNIA GAS COMPANY
STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 866	$ 956	$ 812
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,016	910	839
Deferred income taxes and investment tax credits	( 107 )	28	12
Bad debt expense	40	97	294
Other	( 16 )	( 6 )	( 12 )
Net change in working capital components:
Accounts receivable	( 56 )	( 13 )	207
Due to/from unconsolidated affiliates, net	5	6	57
Income taxes receivable/payable, net	1	13	( 8 )
Inventories	( 7 )	( 10 )	( 118 )
Other current assets	( 244 )	6	( 1,053 )
Accounts payable	20	( 103 )	( 179 )
Regulatory balancing accounts, net	( 294 )	( 27 )	( 311 )
Other current liabilities	160	34	949
Changes in noncurrent assets and liabilities, net	364	( 100 )	( 100 )
Net cash provided by operating activities	1,748	1,791	1,389
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	( 2,116 )	( 2,231 )	( 2,020 )
Net cash used in investing activities	( 2,116 )	( 2,231 )	( 2,020 )
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid	( 200 )	( 200 )	( 100 )
Preferred dividends paid	( 1 )	( 1 )	( 1 )
Issuances of debt (maturities greater than 90 days)	1,490	1,794	997
Payments on debt (maturities greater than 90 days) and finance leases	( 1,076 )	( 524 )	( 1,120 )
Increase (decrease) in short-term debt, net	166	( 609 )	846
Debt issuance costs	( 9 )	( 10 )	( 10 )
Net cash provided by financing activities	370	450	612
Increase (decrease) in cash and cash equivalents	2	10	( 19 )
Cash and cash equivalents, January 1	12	2	21
Cash and cash equivalents, December 31	$ 14	$ 12	$ 2
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$ 358	$ 299	$ 279
Income tax payments (refunds), net	69	( 9 )	6
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued capital expenditures for PP&E	$ 264	$ 308	$ 290
Capital expenditures reclassified from other assets to PP&E	—	50	—
Increase (decrease) in ARO capitalized to PP&E	54	( 23 )	1
Increase in finance lease obligations capitalized to PP&E	33	27	40

See Notes to Financial Statements.

Tab le of Cont ents

SOUTHERN CALIFORNIA GAS COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Dollars in millions)
	Years ended December 31, 2025, 2024 and 2023
	Preferred stock	Common stock	Retained earnings	Accumulated other comprehensive income (loss)	Total shareholders’ equity
Balance at December 31, 2022	$ 22	$ 2,316	$ 4,384	$ ( 24 )	$ 6,698
Net income			812		812
Other comprehensive income				1	1
Dividends declared:
Preferred stock ($ 1.50 /share)			( 1 )		( 1 )
Common stock ($ 1.10 /share)			( 100 )		( 100 )
Balance at December 31, 2023	22	2,316	5,095	( 23 )	7,410
Net income			956		956
Other comprehensive loss				( 4 )	( 4 )
Dividends declared:
Preferred stock ($ 1.50 /share)			( 1 )		( 1 )
Common stock ($ 2.19 /share)			( 200 )		( 200 )
Balance at December 31, 2024	22	2,316	5,850	( 27 )	8,161
Net income			866		866
Other comprehensive income				10	10
Dividends declared:
Preferred stock ($ 1.50 /share)			( 1 )		( 1 )
Common stock ($ 2.19 /share)			( 200 )		( 200 )
Balance at December 31, 2025	$ 22	$ 2,316	$ 6,515	$ ( 17 )	$ 8,836

See Notes to Financial Statements.

Tab le of Cont ents

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA

PRINCIPLES OF CONSOLIDATION

Sempra

Sempra’s Consolidated Financial Statements include the accounts of Sempra and its consolidated entities. Sempra is a holding company whose principal businesses are regulated utilities in California and Texas. Our businesses invest in and operate electric and gas utilities and other energy infrastructure that provide energy services to customers. Sempra has three operating and reportable segments, which we describe in Note 17. All references in these Notes to our reportable segments are not intended to refer to any legal entity with the same or similar name.

SDG&E

SDG&E’s common stock is wholly owned by Enova 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 consolidated financial statements.

Use of Estimates in the Preparation of the Financial Statements

We have prepared our financial statements in conformity with U.S. GAAP. This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates.

Subsequent Events

We evaluated events and transactions that occurred after December 31, 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.

REGULATED OPERATIONS

SDG&E’s and SoCalGas’ accounting policies and financial statements reflect the application of U.S. GAAP provisions governing rate-regulated operations and the policies of the CPUC and the FERC. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from customers, the excess would be refunded to customers, generally by reducing future rates. Regulatory assets and liabilities may also arise from other transactions such as unrealized losses and/or gains on fixed-price contracts and other derivatives or certain deferred income tax expenses or benefits that are passed through to customers in future rates. In addition, SDG&E and SoCalGas record regulatory liabilities when the CPUC or, in the case of SDG&E, the FERC, requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods.

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Determining probability of recovery of regulatory assets requires judgment by management and may include, but is not limited to, consideration of:

▪ the nature of the event giving rise to the assessment

▪ existing statutes and regulatory code

▪ legal precedents

▪ regulatory principles and analogous regulatory actions

▪ testimony presented in regulatory hearings

▪ regulatory orders

▪ a commission-authorized mechanism established for the accumulation of costs

▪ status of applications for rehearings or state court appeals

▪ specific approval from a commission

▪ historical experience

Our Sempra Texas Utilities segment is comprised of our equity method investments in Oncor Holdings, which owns an 80.25 % interest in Oncor, and Sharyland Holdings, which owns 100 % of Sharyland Utilities. Oncor and Sharyland Utilities are regulated electric transmission and distribution utilities in Texas and their rates are regulated by the PUCT and, in the case of Oncor, certain cities and are subject to regulatory rate-setting processes and earnings oversight. Oncor and Sharyland Utilities prepare their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations.

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.

FAIR VALUE MEASUREMENTS

We measure certain assets and liabilities at fair value on a recurring basis, primarily NDT and benefit plan trust assets and derivatives. We also measure certain assets at fair value on a non-recurring basis in certain circumstances.

A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value.

We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 – Pricing inputs are unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities, short-term investments, and U.S. government treasury securities, primarily in the NDT and benefit plan trusts, and exchange-traded derivatives.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including:

▪ quoted forward prices for commodities

▪ time value

▪ current market and contractual prices for the underlying instruments

▪ volatility factors

▪ other relevant economic measures

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Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as interest rate instruments and over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that are generally less observable than from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs at SDG&E and natural gas derivatives and the Support Agreement at Sempra Infrastructure.

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

Nonconsolidated VIEs

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.

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SDG&E determined that none of its PPAs and tolling agreements resulted in SDG&E being the primary beneficiary of a VIE at December 31, 2025 and 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 $ 1,109 million and $ 1,138 million at December 31, 2025 and 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 16. As a result, SDG&E’s potential exposure to loss from its variable interest in these VIEs is not significant.

Other Sempra

Nonconsolidated VIEs

Oncor Holdings. Oncor Holdings is a VIE. Sempra is not the primary beneficiary of this VIE because of the structural and operational ring-fencing measures, governance mechanisms and commitments 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 for additional information about our equity method investment in Oncor Holdings and restrictions on our ability to influence its activities. Our maximum exposure to loss, which fluctuates over time, from our interest in Oncor Holdings does not exceed the carrying value of our investment, which was $ 17,472 million and $ 15,400 million at December 31, 2025 and 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 $ 1,259 million, of which $ 1,242 million is classified as held for sale (see Note 6), at December 31, 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 16.

CFIN. As we discuss in Note 16, in July 2020, Sempra entered into the 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 11). Sempra’s maximum exposure to loss under the terms of the Support Agreement is $ 979 million.

Consolidated 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 $ 15,950 million and $ 8,177 million of assets at December 31, 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 $ 6,335 million and $ 2,664 million of liabilities at December 31, 2025 and 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 December 31, 2025, these assets and liabilities are classified as held for sale (see Note 6).

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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 13). 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 12). 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).

CASH, CASH EQUIVALENTS AND RESTRICTED CASH

Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase.

Restricted cash includes:

▪ certain funds at the Port Arthur LNG liquefaction project for which withdrawals and usage are dictated by debt and equity agreements

▪ distributions in 2026 from SI Partners to Sempra that the KKR Partners would be entitled to, subject to the closing of the planned sale of a portion of our equity interest in SI Partners, which we discuss in Note 6

▪ 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

▪ funds held in a delisting trust for the purpose of purchasing the remaining publicly owned IEnova shares

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on Sempra’s Consolidated Balance Sheets to the sum of such amounts reported on Sempra’s Consolidated Statements of Cash Flows.

RECONCILIATION OF CASH, CASH EQUIVALENTS AND RESTRICTED CASH
(Dollars in millions)
	December 31,
	2025	2024
Sempra:
Cash and cash equivalents	$ 29	$ 1,565
Restricted cash, current	2	21
Restricted cash, noncurrent	—	3
Assets held for sale	3,521	—
Total cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows	$ 3,552	$ 1,589

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)
	2025	2024	2023
Sempra:
Allowances for credit losses at January 1	$ 519	$ 539	$ 188
Provisions for expected credit losses (1)	61	202	467
Write-offs (1)	( 193 )	( 222 )	( 116 )
Reclassification to assets held for sale	( 89 )	—	—
Allowances for credit losses at December 31	$ 298	$ 519	$ 539
SDG&E:
Allowances for credit losses at January 1	$ 114	$ 144	$ 78
Provisions for expected credit losses	47	52	115
Write-offs	( 81 )	( 82 )	( 49 )
Allowances for credit losses at December 31	$ 80	$ 114	$ 144
SoCalGas:
Allowances for credit losses at January 1	$ 285	$ 331	$ 98
Provisions for expected credit losses	37	94	300
Write-offs	( 108 )	( 140 )	( 67 )
Allowances for credit losses at December 31	$ 214	$ 285	$ 331

(1) Includes activities in 2025 within the disposal group that is classified as held for sale.

Allowances for credit losses related to trade receivables, other receivables and a note receivable are included in the Consolidated Balance Sheets as follows:

ALLOWANCES FOR CREDIT LOSSES
(Dollars in millions)
	December 31,
	2025	2024
Sempra:
Accounts receivable – trade, net	$ 235	$ 447
Accounts receivable – other, net	47	53
Other long-term assets (1)(2)	16	19
Total allowances for credit losses	$ 298	$ 519
SDG&E:
Accounts receivable – trade, net	$ 49	$ 81
Accounts receivable – other, net	26	25
Other long-term assets (1)	5	8
Total allowances for credit losses	$ 80	$ 114
SoCalGas:
Accounts receivable – trade, net	$ 186	$ 251
Accounts receivable – other, net	21	28
Other long-term assets (1)	7	6
Total allowances for credit losses	$ 214	$ 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 December 31, 2025 and 2024, includes $ 4 and $ 5 , respectively, of expected credit losses on an interest-bearing promissory note due from KKR Pinnacle.

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Off-Balance Sheet Credit Exposures

We are exposed to credit losses from off-balance sheet arrangements through Sempra’s guarantees related to the SDSRA and SI Partners’ February 2025 credit support agreement, which we discuss in Note 16. 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 Consolidated Balance Sheets, expected credit losses of $ 5 million are included in Deferred Credits and Other at both December 31, 2025 and 2024, and $ 2 million are included in Liabilities Held for Sale at December 31, 2025.

CONCENTRATION OF CREDIT RISK

Credit risk is the risk of loss that would be incurred as a result of nonperformance by our counterparties on their contractual obligations. We have policies governing the management of credit risk that are administered by the respective credit departments at each of the Registrants and overseen by their separate risk management committees.

This oversight includes calculating current and potential credit risk on a regular basis and monitoring actual balances in comparison to approved limits. We establish credit limits based on risk and return considerations under terms customarily available in the industry. We avoid concentration of counterparties whenever possible, and we believe our credit policies significantly reduce overall credit risk. These policies include an evaluation of:

▪ prospective counterparties’ financial condition (including credit ratings)

▪ collateral requirements

▪ the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty

▪ downgrade triggers

We believe that we have provided adequate reserves for counterparty nonperformance in our allowances for credit losses.

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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)
	December 31,
	2025	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	$ ( 8 )	$ —
Total due to unconsolidated affiliates – current	$ ( 8 )	$ —
TAG Pipelines (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:
Various affiliates	$ 1	$ —
Total due from unconsolidated affiliates – current	$ 1	$ —
Sempra	$ ( 48 )	$ ( 42 )
SoCalGas	( 6 )	( 14 )
Various affiliates	( 5 )	( 3 )
Total due to unconsolidated affiliates – current	$ ( 59 )	$ ( 59 )
Income taxes due from Sempra (3)	$ 43	$ 38
SoCalGas:
SDG&E	$ 6	$ 14
Various affiliates	2	2
Total due from unconsolidated affiliates – current	$ 8	$ 16
Sempra	$ ( 35 )	$ ( 38 )
Total due to unconsolidated affiliates – current	$ ( 35 )	$ ( 38 )
Income taxes due to Sempra (3)	$ ( 6 )	$ ( 6 )

(1) At December 31, 2025, $ 3 due from unconsolidated affiliates is included in Assets Held for Sale and $ 477 due to unconsolidated affiliates is included in Liabilities Held for Sale on the Sempra 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)
	Years ended December 31,
	2025	2024	2023
Sempra:
Revenues	$ 34	$ 40	$ 44
Interest expense	18	16	15
SDG&E:
Revenues	$ 22	$ 23	$ 21
Cost of sales	134	146	113
SoCalGas:
Revenues	$ 173	$ 169	$ 124
Cost of sales (1)	( 3 )	( 5 )	35

(1) Includes net commodity costs from natural gas transactions with unconsolidated affiliates.

Sempra, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Also, from time-to-time, SDG&E and SoCalGas may make short-term advances of surplus cash to Sempra at interest rates based on the federal funds effective rate plus a margin of 13 to 20 bps, depending on the loan balance. Such amounts are eliminated in consolidation at Sempra.

SDG&E and SoCalGas charge one another, as well as other Sempra affiliates, for shared asset depreciation. SoCalGas and SDG&E record revenues and the affiliates record corresponding amounts to O&M. Such amounts are eliminated in consolidation at Sempra.

SDG&E has a 20-year contract that commenced in June 2015 for up to 155 MW of renewable power supplied from the ESJ wind power generation facility, a consolidated subsidiary of Sempra. A second 20-year contract between SDG&E and ESJ for up to 108 MW of renewable power supplied from the same facility commenced in January 2022. Such amounts are eliminated in consolidation at Sempra.

The natural gas supply for SDG&E’s and SoCalGas’ core natural gas customers is purchased by SoCalGas as a combined procurement portfolio managed by SoCalGas. Core customers are primarily residential and small commercial and industrial customers. This core gas procurement function is considered a shared service; therefore, SoCalGas records revenues net of costs in cost of sales. Such amounts are eliminated in consolidation at Sempra.

SoCalGas provides natural gas transportation and storage services to SDG&E and charges SDG&E for such services monthly. SoCalGas records revenues and SDG&E records a corresponding amount to cost of sales. Such amounts are eliminated in consolidation at Sempra.

SoCalGas provides transportation services to Ecogas. SoCalGas records revenues and Ecogas records a corresponding amount to cost of sales. Such amounts are eliminated in consolidation at Sempra.

SoCalGas and SI Partners may buy and sell natural gas from and to each other in open market transactions to help satisfy supply needs. SoCalGas records revenues and costs in cost of sales. SI Partners records revenues and costs in revenues. Such amounts are eliminated in consolidation at Sempra.

SI Partners has agreements with Cameron LNG JV to provide certain business services and project development services related to the Cameron LNG Phase 2 project.

SI Partners provides maintenance and administrative services to TAG Pipelines. Additionally, SI Partners subleases office space for personnel to TAG Pipelines and TAG Norte.

Sempra provides guarantees to certain unconsolidated affiliates, which we discuss in Note 16.

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INVENTORIES

SDG&E and SoCalGas value natural gas inventory using the last-in first-out method. SI Partners values natural gas inventory at the lower of average cost or net realizable value. We record natural gas to inventory when injected and then to expense when the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.

SI Partners values LNG inventory at the lower of average cost or net realizable value. We record LNG to inventory when delivered to our terminals and then to expense when transported from our terminals.

SDG&E, SoCalGas and SI Partners generally value materials and supplies at the lower of average cost or net realizable value. We record materials and supplies to inventory when purchased and then to expense or capitalized to PP&E, as appropriate, when used.

The components of inventories are as follows:

INVENTORY BALANCES AT DECEMBER 31
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
	2025 (1)	2024	2025	2024	2025	2024
Natural gas	$ 158	$ 163	$ 2	$ 1	$ 156	$ 148
LNG	—	27	—	—	—	—
Materials and supplies	403	369	265	201	138	139
Total	$ 561	$ 559	$ 267	$ 202	$ 294	$ 287

(1) Total inventories of $ 109 is included in Assets Held for Sale on the Sempra Consolidated Balance Sheet, which consists of $ 12 of natural gas, $ 12 of LNG and $ 85 of materials and supplies.

GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS

SDG&E, SoCalGas and SI Partners are required by AB 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas consumption. SDG&E and SoCalGas purchase required GHG allowances based on their customers’ natural gas consumption and receive a fraction of allocated allowances at no cost to meet compliance obligations. SDG&E receives allocations of GHG allowances on behalf of its electric customers at no cost and purchases any additional allowances required. We record purchased and allocated GHG allowances at the lower of weighted-average cost or market. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. SDG&E and SoCalGas balance costs and revenues associated with the GHG program through regulatory balancing accounts. SI Partners records the cost of GHG obligations in cost of sales. We remove the assets and liabilities from the balance sheets as the allowances are surrendered.

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. Investor-owned gas distribution utilities such as SoCalGas are not covered by this legislation. The issues addressed include wildfire mitigation, cost recovery standards and requirements, a wildfire fund, a liability cap and the establishment of a wildfire safety board.

The 2019 Wildfire Legislation established a revised legal standard for the recovery of wildfire costs (Revised Prudent Manager Standard) and established a fund (the Wildfire Fund) designed to provide liquidity to SDG&E, PG&E and Edison to pay IOU wildfire-related claims in the event that the governmental agency responsible for determining causation determines the applicable IOU’s equipment caused the ignition of a wildfire, primary insurance coverage is exceeded and certain other conditions are satisfied. A primary purpose of the Wildfire Fund is to pool resources provided by shareholders and ratepayers of the IOUs and make those resources available to reimburse the IOUs for third-party wildfire claims incurred after July 12, 2019, the effective date of the 2019 Wildfire Legislation, subject to certain limitations.

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An IOU may seek payment from the Wildfire Fund for settled or adjudicated third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $ 1.0 billion or the IOU’s required amount of insurance coverage as recommended by the Wildfire Fund’s administrator. Wildfire claims approved by the Wildfire Fund’s administrator will be paid by the Wildfire Fund to the IOU to the extent funds are available. These utilized funds will be subject to review by the CPUC, which will make a determination as to the degree an IOU’s conduct related to an ignition of a wildfire was prudent or imprudent. The Revised Prudent Manager Standard requires that the CPUC apply clear standards when reviewing wildfire liability losses paid when determining the reasonableness of an IOU’s conduct related to an ignition. Under this standard, the conduct under review related to the ignition may include factors within and beyond the IOU’s control, including humidity, temperature and winds. Costs and expenses may be allocated for cost recovery in full or in part. Also, under this standard, an IOU’s conduct will be deemed reasonable if a valid annual safety certification is in place at the time of the ignition, unless a serious doubt is raised, in which case the burden shifts to the utility to dispel that doubt. The IOUs will receive an annual safety certification from OEIS if they meet various requirements.

If an IOU has maintained a valid annual safety certification, to the extent it is found to be imprudent, claims will be reimbursable by the IOU to the Wildfire Fund up to a liability cap based on the IOU’s rate base. The aggregate requirement to reimburse the Wildfire Fund over a trailing three calendar year period is capped at 20 % of the equity portion of an IOU’s electric transmission and distribution rate base in the year of the prudency determination. Based on its 2025 rate base, the liability cap for SDG&E is approximately $ 1.5 billion, which is adjusted annually. The liability cap will apply on a rolling three-year basis so long as future annual safety certifications are received and the Wildfire Fund has not been terminated, which could occur if funds are exhausted. Amounts in excess of the liability cap and amounts that are determined to be prudently incurred do not need to be reimbursed by an IOU to the Wildfire Fund. The Wildfire Fund does not have a specified term and coverage will continue until the assets of the Wildfire Fund are exhausted and the Wildfire Fund is terminated, in which case, the remaining funds, if any, will be transferred to California’s general fund to be used for fire risk mitigation programs.

SDG&E submitted 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.

The Wildfire Fund was initially funded up to $ 10.5 billion by a loan from the California Surplus Money Investment Fund. The loan is financed through a DWR bond, which was put in place in October 2020 and is securitized through a dedicated surcharge on ratepayers’ bills attributable to the DWR. In October 2019, the CPUC adopted a decision authorizing a non-bypassable charge to be collected by the IOUs to support the anticipated DWR bond issuance authorized by AB 1054. The CPUC decision also determined that ratepayers of non-participating electrical corporations shall not pay the non-bypassable charge.

The Wildfire Fund was also funded by initial shareholder contributions from the IOUs totaling $ 7.5 billion. SDG&E’s share was $ 322.5 million. The IOUs are also required to make annual shareholder contributions to the Wildfire Fund with an aggregate value of $ 3 billion over a 10-year period starting in 2019. SDG&E’s share is $ 129 million. The contributions are not subject to rate recovery.

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 participating California electric IOUs, including SDG&E, if certain conditions are met. The 2025 Wildfire Legislation preserves key elements of the 2019 Wildfire Legislation, including cost recovery standards and requirements, a liability cap 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.

Tab le of Cont ents

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 DWR 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 .

Only claims arising from wildfires that ignited on or after September 19, 2025 and 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 liability 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 liability 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 liability cap, which will vary over time, is approximately $ 1.5 billion based on its 2025 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.

Wildfire Fund Asset and Obligation

In 2019, SDG&E recorded both a Wildfire Fund asset and a related obligation for its commitment to make shareholder contributions of $ 451.5 million to the Wildfire Fund. SDG&E paid its initial shareholder contribution of $ 322.5 million to the Wildfire Fund in September 2019. SDG&E funded this contribution with proceeds from an equity contribution from Sempra. SDG&E expects to continue to make annual shareholder contributions of $ 12.9 million through December 31, 2028. SDG&E is accreting the present value of the Wildfire Fund obligation until the liability is settled.

SDG&E is amortizing the Wildfire Fund asset on a straight-line basis over the estimated period of benefit, as adjusted for utilization by the IOUs. In 2024, SDG&E revised its estimate of the period of benefit from 15 years to 25 years. The estimated period of benefit of the Wildfire Fund asset is based on several assumptions, including, but not limited to:

▪ historical wildfire experience of each IOU in California, including frequency and severity of the wildfires

▪ the value of property potentially damaged by wildfires

▪ the effectiveness of wildfire risk mitigation efforts by each IOU

▪ liability cap of each IOU

▪ IOU prudency determination levels

▪ FERC jurisdictional allocation levels

▪ insurance coverage levels

Tab le of Cont ents

The use of different assumptions, or changes to the assumptions used, could have a significant impact on the estimated period of benefit of the Wildfire Fund asset. SDG&E periodically evaluates the estimated period of benefit of the Wildfire Fund asset based on actual experience and changes in these assumptions. SDG&E recognizes a reduction of its Wildfire Fund asset and records a charge against earnings in the period when there is a reduction of the available coverage due to recoverable claims from any of the participating IOUs. Wildfire claims that are recoverable from the Wildfire Fund, net of anticipated or actual reimbursement to the Wildfire Fund by the responsible IOU, decrease the Wildfire Fund asset and remaining available coverage.

In February 2026, a participating IOU publicly disclosed that it has received, or expects to receive, approximately $ 1.26 billion in aggregate reimbursements from the Wildfire Fund for eligible claims related to wildfires that occurred in 2019 and 2021. Also in February 2026, another participating IOU publicly disclosed it has received, or expects to receive, approximately $ 134 million in aggregate reimbursements from the Wildfire Fund for losses incurred and expected to be incurred in connection with one of the LA Fires, the cause of which remains under investigation and has not been conclusively determined. The administrator of the Wildfire Fund has confirmed that this wildfire qualifies as a “covered wildfire” for purposes of accessing the Wildfire Fund, and the scope of potential damages caused by this fire could materially reduce or exhaust the Wildfire Fund. The participating IOU 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.

The following table summarizes the location of balances related to the Wildfire Fund on Sempra’s and SDG&E’s Consolidated Balance Sheets.

WILDFIRE FUND
(Dollars in millions)
		December 31,
	Location	2025	2024
Wildfire Fund asset:
Current	Prepaid Expenses	$ 14	$ 14
Noncurrent	Wildfire Fund	246	262
Wildfire Fund obligation:
Current	Other Current Liabilities	13	13
Noncurrent	Deferred Credits and Other	20	31

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 December 31, 2025 and 2024, Other Long-Term Assets includes $ 368 million and $ 349 million, respectively, of outstanding principal, compounded interest and unamortized transaction costs, net of allowance for credit losses, on Sempra’s Consolidated Balance Sheets.

At the closing of the planned 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 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.

LONG-LIVED ASSETS

We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated entities. A long-lived asset may be impaired when the estimated future undiscounted cash flows are less than the carrying amount of the asset. If that comparison indicates that the asset’s carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the asset. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

Tab le of Cont ents

GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized, but we test it for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, we record a goodwill impairment loss as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill.

For our annual goodwill impairment testing, we have the option to first make a qualitative assessment of whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount before applying the quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, then we perform the quantitative goodwill impairment test. If, after performing the quantitative goodwill impairment test, we determine that goodwill is impaired, we record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill.

Goodwill of $ 1,602 million at both December 31, 2025 and 2024 primarily relates to the 2016 acquisitions of IEnova Pipelines and the Ventika wind power generation facilities at Sempra Infrastructure. At December 31, 2025, goodwill is included in Assets Held for Sale on the Sempra Consolidated Balance Sheet.

Other Intangible Assets

Other Intangible Assets included on Sempra’s Consolidated Balance Sheet is as follows:

OTHER INTANGIBLE ASSETS
(Dollars in millions)
	December 31, 2024
Sempra (1) :
Renewable energy transmission and consumption permits	$ 169
O&M agreement	66
ESJ PPA	190
Other	15
	440
Less accumulated amortization:
Renewable energy transmission and consumption permits	( 68 )
O&M agreement	( 20 )
ESJ PPA	( 51 )
Other	( 9 )
	( 148 )
	$ 292

(1) At December 31, 2025, excludes total other intangible assets of $ 273 , which is included in Assets Held for Sale on the Sempra Consolidated Balance Sheet and is comprised of $ 440 of gross other intangible assets, net of $ 167 of accumulated amortization.

Other intangible assets primarily include:

▪ renewable energy transmission and consumption permits granted by the CNE at the Ventika wind power generation facilities, Don Diego Solar and Border Solar;

▪ a favorable O&M agreement acquired in connection with the acquisition of Ductos y Energéticos del Norte, S. de R.L. de C.V.; and

▪ the relative fair value of the PPA that was acquired in connection with the acquisition of ESJ.

Intangible assets subject to amortization are amortized over their estimated useful lives. Amortization expense for intangible assets was $ 19 million (including $ 10 million recorded against revenues) in 2025 and $ 26 million (including $ 13.5 million recorded against revenues) in both 2024 and 2023. In September 2025, we classified SI Partners as held for sale and ceased recording amortization.

Tab le of Cont ents

PROPERTY, PLANT AND EQUIPMENT

PP&E is recorded at cost and primarily represents the equipment, buildings, other facilities and information systems used by SDG&E and SoCalGas to provide natural gas and electric utility services, and by Other Sempra businesses in their operations, including construction work in progress, leasehold improvements and other equipment. Our PP&E costs include labor, materials and contract services and expenditures for replacement parts incurred during a major maintenance outage of a plant. In addition, the cost of utility plant at our rate-regulated businesses and PP&E under regulated projects that meet the regulatory accounting requirements of U.S. GAAP includes AFUDC. The cost of PP&E for our non-regulated projects includes capitalized interest. Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage value is charged to accumulated depreciation. We discuss assets collateralized as security for certain indebtedness in Note 7.

PROPERTY, PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY
(Dollars in millions)
	December 31,		Depreciation rates for years ended December 31,
	2025	2024	2025	2024	2023
SDG&E (1) :
Natural gas operations	$ 4,742	$ 4,531	2.63 %	2.62 %	2.60 %
Electric distribution	13,357	12,542	4.26	4.21	4.05
Electric transmission (2)	9,501	8,878	3.07	3.06	3.04
Electric generation	2,532	2,527	4.27	5.43	5.18
Other electric	2,915	2,722	6.72	6.95	7.05
Construction work in progress (2)	1,986	1,962	N/A	N/A	N/A
Total SDG&E	35,033	33,162
SoCalGas:
Natural gas operations	29,262	27,191	3.81	3.68	3.64
Other non-utility	37	32	0.97	0.98	1.03
Construction work in progress	1,779	1,861	N/A	N/A	N/A
Total SoCalGas	31,078	29,084
Other Sempra (3)(4) :			Estimated useful life (in years) (5)		Weighted-average useful life (in years) (5)
Land and land rights	—	498	N/A		N/A
Machinery and equipment:
Pipelines and storage	481	4,355	19 to 49		44
Generating plants	—	1,820	N/A		N/A
LNG terminal	—	1,156	N/A		N/A
Refined products terminals	—	876	N/A		N/A
Other	96	348	1 to 9		2
Construction work in progress	160	8,781	N/A		N/A
Other	52	317	4 to 25		10
	789	18,151
Total Sempra	$ 66,900	$ 80,397

(1) Includes $ 214 decrease in 2025 from regulatory disallowances associated with SDG&E’s 2024 GRC Track 2 FD, which we discuss in Note 4.

(2) At December 31, 2025, includes $ 553 in electric transmission assets and $ 3 in construction work in progress related to SDG&E’s 86 % interest in the Southwest Powerlink transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures. SDG&E’s share of operating expenses is included in SDG&E’s and Sempra’s Consolidated Statements of Operations.

(3) At December 31, 2025, excludes total PP&E of $ 23,579 , which is included in Assets Held for Sale on the Sempra Consolidated Balance Sheet and is comprised of $ 500 in land and land rights; machinery and equipment of $ 3,646 in pipelines and storage, $ 1,809 in generating plants, $ 1,160 in LNG terminal, $ 872 in refined products terminals, and $ 255 in other; $ 15,077 in construction work in progress; and $ 260 in other.

(4) At December 31, 2025, $ 362 of utility plant, primarily pipelines and other distribution assets at Ecogas, is included in Assets Held for Sale on the Sempra Consolidated Balance Sheet.

(5) Estimated useful life relates to PP&E that is held and used as of December 31, 2025. PP&E included in the disposal group that is classified as held for sale in 2025 is no longer depreciated.

Tab le of Cont ents

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 December 2025, Sempra Infrastructure and the CFE further amended their transportation services agreement to re-route the portion of the pipeline that is in the Yaqui territory, whereby the CFE has agreed to reimburse Sempra Infrastructure for the re-routing costs with a new tariff and requires the pipeline to be back in service no later than July 2029. 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. Additionally, in December 2025, Sempra Infrastructure and the CFE entered into a non-binding agreement for potential equity participation in the Guaymas-El Oro segment of the Sonora pipeline.

The Guaymas-El Oro segment of the Sonora pipeline will continue to be owned by and a Sole Risk Project of Sempra after closing the planned sale of a portion of our equity interest in SI Partners, which we discuss in Note 6. At December 31, 2025, Sempra Infrastructure had $ 389 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.

Depreciation expense is computed using the straight-line method over the asset’s estimated composite useful life, the CPUC-prescribed period for SDG&E and SoCalGas, or the remaining term of the site leases, whichever is shortest. In September 2025, we classified SI Partners as held for sale and ceased recording depreciation.

DEPRECIATION EXPENSE
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra	$ 2,537	$ 2,409	$ 2,202
SDG&E	1,309	1,216	1,092
SoCalGas	1,007	903	833

ACCUMULATED DEPRECIATION AND AMORTIZATION
(Dollars in millions)
	December 31,
	2025	2024
SDG&E (1) :
Accumulated depreciation:
Natural gas operations	$ 1,191	$ 1,121
Electric transmission, distribution and generation (2)	7,538	6,930
Total SDG&E	8,729	8,051
SoCalGas:
Accumulated depreciation:
Natural gas operations	8,933	8,315
Other non-utility	15	15
Total SoCalGas	8,948	8,330
Other Sempra:
Accumulated depreciation – other (3)(4)	212	2,579
Total Sempra	$ 17,889	$ 18,960

(1) Includes $ 71 decrease in 2025 from regulatory disallowances associated with SDG&E’s 2024 GRC Track 2 FD, which we discuss in Note 4.

(2) At December 31, 2025, includes $ 347 related to SDG&E’s 86 % interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.

(3) At December 31, 2025, $ 2,497 of accumulated depreciation is included in Assets Held for Sale on the Sempra Consolidated Balance Sheet.

(4) At December 31, 2025, $ 88 of accumulated depreciation for utility plant at Ecogas is included in Assets Held for Sale on the Sempra Consolidated Balance Sheet.

SDG&E and SoCalGas finance construction projects with debt and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of PP&E. SDG&E and SoCalGas earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from their customers over the expected useful lives of the assets.

Tab le of Cont ents

Pipeline projects under construction by Sempra Infrastructure that are both subject to certain regulation and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC.

We capitalize interest costs incurred to finance capital projects and interest at equity method investments that have not commenced planned principal operations.

The table below summarizes capitalized financing costs, comprised of capitalized interest and AFUDC related to debt.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra	$ 801	$ 629	$ 448
SDG&E	108	100	116
SoCalGas	98	101	77

ASSET RETIREMENT OBLIGATIONS

For tangible long-lived assets, we record AROs for the present value of liabilities of future costs expected to be incurred when assets are retired from service if the retirement process is legally required and if a reasonable estimate of fair value can be made. We also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated but performance is conditional upon a future event. We record the estimated retirement cost using the present value of the obligation at the time the asset is placed into service and recognize that cost over the life of the related asset by depreciating the asset retirement cost and accreting the obligation until the liability is settled. Our rate-regulated entities record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through the rate-making process.

We have recorded AROs related to various assets, including:

SDG&E and SoCalGas

▪ fuel and storage tanks

▪ natural gas transmission and distribution systems

▪ hazardous waste storage facilities

▪ asbestos-containing construction materials

SDG&E

▪ nuclear power facilities

▪ electric transmission and distribution systems

▪ energy storage systems

▪ power generation plants

SoCalGas

▪ underground natural gas storage facilities and wells

Other Sempra

▪ LNG terminal

▪ natural gas transportation and distribution systems

▪ LPG storage facilities

▪ refined products terminals

▪ power generating plants

Tab le of Cont ents

The changes in AROs are as follows:

CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
	Sempra			SDG&E			SoCalGas
	2025	2024	2023	2025	2024	2023	2025	2024	2023
Balance at January 1 (1)	$ 3,925	$ 3,831	$ 3,712	$ 900	$ 894	$ 887	$ 2,930	$ 2,847	$ 2,743
Accretion expense (2)	164	156	148	40	37	37	119	114	106
Liabilities incurred	10	—	18	10	—	15	—	—	—
Payments	( 58 )	( 65 )	( 62 )	( 47 )	( 57 )	( 59 )	( 11 )	( 8 )	( 3 )
Revisions (2)	1	3	15	( 50 )	26	14	54	( 23 )	1
Reclassification to liabilities held for sale	( 94 )	—	—	—	—	—	—	—	—
Balance at December 31 (1)	$ 3,948	$ 3,925	$ 3,831	$ 853	$ 900	$ 894	$ 3,092	$ 2,930	$ 2,847

(1) Current portion of the ARO for Sempra is included in Other Current Liabilities on the Consolidated Balance Sheets.

(2) Sempra includes activities in 2025 within the disposal group that is classified as held for sale.

CONTINGENCIES

We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and if:

▪ information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and

▪ the amount of the loss or a range of possible losses can be reasonably estimated.

We do not accrue contingencies that might result in gains. We assess contingencies for litigation claims, environmental remediation and other events.

COMPREHENSIVE INCOME

Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including:

▪ foreign currency translation adjustments

▪ certain hedging activities

▪ changes in unamortized net actuarial gain or loss and prior service cost related to pension and PBOP plans

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The Consolidated Statements of Comprehensive Income (Loss) show the changes in the components of OCI, including the amounts attributable to NCI. The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, 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
Sempra:
Balance at December 31, 2022	$ ( 59 )	$ 10	$ ( 86 )	$ ( 135 )
OCI before reclassifications	23	59	( 35 )	47
Amounts reclassified from AOCI (2)	—	( 66 )	4	( 62 )
Net OCI (2)	23	( 7 )	( 31 )	( 15 )
Balance at December 31, 2023	( 36 )	3	( 117 )	( 150 )
OCI before reclassifications	( 30 )	34	( 1 )	3
Amounts reclassified from AOCI	—	( 22 )	3	( 19 )
Net OCI	( 30 )	12	2	( 16 )
Balance at December 31, 2024	( 66 )	15	( 115 )	( 166 )
OCI before reclassifications (3)	21	( 68 )	( 10 )	( 57 )
Amounts reclassified from AOCI (3)	—	( 1 )	27	26
Net OCI	21	( 69 )	17	( 31 )
Balance at December 31, 2025	$ ( 45 )	$ ( 54 )	$ ( 98 )	$ ( 197 )
SDG&E:
Balance at December 31, 2022			$ ( 7 )	$ ( 7 )
OCI before reclassifications			( 2 )	( 2 )
Amounts reclassified from AOCI			1	1
Net OCI			( 1 )	( 1 )
Balance at December 31, 2023			( 8 )	( 8 )
OCI before reclassifications			( 3 )	( 3 )
Amounts reclassified from AOCI			( 1 )	( 1 )
Net OCI			( 4 )	( 4 )
Balance at December 31, 2024			( 12 )	( 12 )
OCI before reclassifications			( 1 )	( 1 )
Amounts reclassified from AOCI (3)			7	7
Net OCI			6	6
Balance at December 31, 2025			$ ( 6 )	$ ( 6 )
SoCalGas:
Balance at December 31, 2022		$ ( 12 )	$ ( 12 )	$ ( 24 )
OCI before reclassifications		—	( 1 )	( 1 )
Amounts reclassified from AOCI		1	1	2
Net OCI		1	—	1
Balance at December 31, 2023		( 11 )	( 12 )	( 23 )
OCI before reclassifications		—	( 5 )	( 5 )
Amounts reclassified from AOCI		1	—	1
Net OCI		1	( 5 )	( 4 )
Balance at December 31, 2024		( 10 )	( 17 )	( 27 )
OCI before reclassifications		—	( 2 )	( 2 )
Amounts reclassified from AOCI		1	11	12
Net OCI		1	9	10
Balance at December 31, 2025		$ ( 9 )	$ ( 8 )	$ ( 17 )

(1) All amounts are net of income tax, if subject to tax, and after NCI.

(2) Total AOCI includes $( 46 ) of financial instruments associated with sale of NCI to KKR Denali in 2023, which we discuss in Note 13 in “Noncontrolling Interests – SI Partners Subsidiaries.” This transaction did not impact the Consolidated Statement of Comprehensive Income (Loss).

(3) Pension and PBOP and Total AOCI include a $ 6 transfer of liabilities from SDG&E to Sempra related to the nonqualified pension plan.

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RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about AOCI components	Amounts reclassified from AOCI			Affected line item on Consolidated Statements of Operations
	Years ended December 31,
	2025	2024	2023
Sempra:
Financial instruments:
Interest rate instruments	$ ( 7 )	$ ( 11 )	$ 1	Interest expense
Interest rate instruments	( 10 )	( 23 )	( 48 )	Equity earnings (1)
Foreign exchange instruments	3	( 5 )	1	Revenues: Energy-related businesses
	2	( 2 )	2	Other income, net
Foreign exchange instruments	5	( 6 )	2	Equity earnings (1)
Interest rate and foreign exchange instruments	—	—	( 1 )	Interest expense
	—	—	( 6 )	Other income, net
Total, before income tax	( 7 )	( 47 )	( 49 )
	3	11	6	Income tax expense
Total, net of income tax	( 4 )	( 36 )	( 43 )
	3	14	23	Earnings attributable to noncontrolling interests
Total, net of income tax and after NCI	$ ( 1 )	$ ( 22 )	$ ( 20 )
Pension and PBOP (2) :
Amortization of actuarial loss	$ 6	$ 6	$ 3	Other income, net
Amortization of prior service cost	2	3	2	Other income, net
Settlement charges	16	9	—	Other income, net
Total, before income tax	24	18	5
	( 3 )	( 15 )	( 1 )	Income tax expense
Total, net of income tax	$ 21	$ 3	$ 4
Total reclassifications for the period, net of income tax and after NCI	$ 20	$ ( 19 )	$ ( 16 )
SDG&E:
Pension and PBOP (2) :
Amortization of actuarial loss	$ 1	$ 1	$ —	Other income, net
Amortization of prior service cost	—	—	1	Other income, net
Total, before income tax	1	1	1
	—	( 2 )	—	Income tax benefit (expense)
Total reclassifications for the period, net of income tax	$ 1	$ ( 1 )	$ 1
SoCalGas:
Financial instruments:
Interest rate instruments	$ 1	$ 1	$ 1	Interest expense
Pension and PBOP (2) :
Amortization of actuarial loss	$ 1	$ 1	$ 1	Other (expense) income, net
Amortization of prior service cost	1	1	1	Other (expense) income, net
Settlement charges	10	—	—	Other income (expense), net
Total, before income tax	12	2	2
	( 1 )	( 2 )	( 1 )	Income tax benefit (expense)
Total, net of income tax	$ 11	$ —	$ 1
Total reclassifications for the period, net of income tax	$ 12	$ 1	$ 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” in Note 9).

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REVENUES

See Note 3 for a description of significant accounting policies for revenues.

RENEWABLE ENERGY CERTIFICATES

RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.

Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market to comply with the RPS Program established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS Program. The cost of RECs at SDG&E, which is recoverable in rates, is recorded in Cost of Electric Fuel and Purchased Power on the Statements of Operations.

OPERATION AND MAINTENANCE EXPENSES

Operation and Maintenance includes O&M and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, insurance, rent, provisions for expected credit losses and litigation expense.

LEGAL FEES

Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred and amounts are estimable.

FOREIGN CURRENCY TRANSLATION AND TRANSACTIONS

Our natural gas distribution utility in Mexico, Ecogas, uses its local currency as its functional currency. The assets and liabilities of its foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the year. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings but are reflected in OCI and AOCI.

Cash flows of this consolidated foreign subsidiary are translated into U.S. dollars using average exchange rates for the period. We report the effect of exchange rate changes on cash balances held in foreign currencies in Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash on Sempra’s Consolidated Statements of Cash Flows.

Foreign currency transaction gains (losses), net, are included in Other Income, Net, on Sempra’s Consolidated Statements of Operations.

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OTHER INCOME, NET

Other Income, Net, on the Consolidated Statements of Operations consists of the following:

OTHER INCOME (EXPENSE), NET
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra:
Allowance for equity funds used during construction	$ 174	$ 150	$ 140
Investment gains, net (1)	52	36	28
(Losses) gains on interest rate and foreign exchange instruments, net	( 2 )	2	4
Foreign currency transaction gains (losses), net	13	( 16 )	2
Non-service components of net periodic benefit cost	( 142 )	( 101 )	( 106 )
Interest on regulatory balancing accounts, net	93	75	79
Sundry, net	( 19 )	( 10 )	( 16 )
Total	$ 169	$ 136	$ 131
SDG&E:
Allowance for equity funds used during construction	$ 79	$ 73	$ 86
Non-service components of net periodic benefit cost	( 27 )	4	( 19 )
Interest on regulatory balancing accounts, net	59	23	42
Sundry, net	( 5 )	( 10 )	( 12 )
Total	$ 106	$ 90	$ 97
SoCalGas:
Allowance for equity funds used during construction	$ 69	$ 72	$ 54
Non-service components of net periodic benefit cost	( 99 )	( 86 )	( 80 )
Interest on regulatory balancing accounts, net	34	52	37
Sundry, net	( 10 )	( 13 )	( 15 )
Total	$ ( 6 )	$ 25	$ ( 4 )

(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 Consolidated Statements of Operations.

INCOME TAXES

Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. ITCs from prior years are generally amortized to income by SDG&E and SoCalGas over the estimated service lives of the properties as required by the CPUC. However, in 2023, the scope of projects eligible for ITCs was expanded to include standalone energy storage projects, which are transferable under the IRA. The IRA also provided an election that permits ITCs related to standalone energy storage projects to be returned to utility customers over a period that is shorter than the life of the applicable asset.

Under the regulatory accounting treatment required for flow-through temporary differences, Sempra, SDG&E and SoCalGas recognize:

▪ regulatory assets to offset deferred income tax liabilities if it is probable that the amounts will be recovered from customers

▪ regulatory liabilities to offset deferred income tax assets if it is probable that the amounts will be returned to customers

When there are uncertainties related to potential income tax benefits, the position we take must have at least a more-likely-than-not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities in order to qualify for recognition. The term “more-likely-than-not” means a likelihood of more than 50%. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the more-likely-than-not criterion at the largest amount of tax benefit that is greater than 50% likely of being realized upon its effective resolution.

Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR.

As a result of management’s decision to hold SI Partners for sale, our foreign subsidiaries are no longer indefinitely reinvested. We accrue income tax for basis differences between financial statement and income tax investment amounts in foreign subsidiaries.

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We recognize interest and penalties related to income taxes in income tax expense.

We provide additional information about income taxes in Note 8.

RESTRICTED NET ASSETS

Sempra

As we discuss below, SDG&E, SoCalGas and certain Other Sempra entities have restrictions on the amount of funds that can be transferred to Sempra by dividend, advance or loan as a result of conditions imposed by various regulators. Additionally, certain Other Sempra entities are subject to various financial and other covenants and other restrictions contained in debt and credit agreements (described in Note 7) and in other agreements that limit the amount of funds that can be transferred to Sempra. At December 31, 2025, Sempra was in compliance with all covenants related to its debt agreements.

At December 31, 2025, the amount of restricted net assets of consolidated entities of Sempra that may not be distributed to Sempra in the form of a loan or dividend is $ 22.3 billion. Additionally, the amount of restricted net assets of our unconsolidated entities is $ 19.1 billion. Although the restrictions cap the amount of funding that the various operating subsidiaries and equity method investees can provide to Sempra, we do not believe these restrictions will have a significant impact on our ability to access cash to pay dividends and fund operating needs.

As we discuss in Note 5, $ 3.4 billion of Sempra’s retained earnings represents undistributed earnings from equity method investments at December 31, 2025.

SDG&E and SoCalGas

The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts available for dividends and loans to Sempra. At December 31, 2025, Sempra could have received combined loans and dividends of approximately $ 868 million from SDG&E and approximately $ 350 million from SoCalGas.

The payment and amount of future dividends by SDG&E and SoCalGas are at the discretion of their respective boards of directors. The following restrictions limit the amount of retained earnings that may be paid as common stock dividends or loaned to Sempra from either utility:

▪ The CPUC requires that SDG&E’s and SoCalGas’ common equity ratios be no lower than one percentage point below the CPUC-authorized percentage of each entity’s authorized capital structure. The authorized percentage at December 31, 2025 is 52 % at both SDG&E and SoCalGas.

▪ SDG&E and SoCalGas each have a revolving credit line that requires it to maintain a ratio of consolidated indebtedness to consolidated capitalization (as defined in the agreements) of no more than 65 %, as we discuss in Note 7.

Based on these restrictions, at December 31, 2025, SDG&E’s restricted net assets were $ 10.2 billion, and SoCalGas’ restricted net assets were $ 8.5 billion, which could not be transferred to Sempra.

Other Sempra

Sempra owns a 100 % interest in Oncor Holdings, which owns an 80.25 % interest in Oncor. As we discuss in Note 5, we account for our investment in Oncor Holdings under the equity method. Significant restrictions at Oncor that limit the amount that may be paid as dividends to Sempra include:

▪ In connection with ring-fencing measures, governance mechanisms and commitments, Oncor may not pay any dividends or make any other distributions (except for contractual tax payments) if a majority of its independent directors or a minority member director determines that it is in the best interests of Oncor to retain such amounts to meet expected future requirements.

▪ Oncor must remain in compliance with its debt-to-equity ratio established by the PUCT for ratemaking purposes and may not pay dividends or other distributions (except for contractual tax payments) if that payment would cause it to exceed its PUCT authorized debt-to-equity ratio. Oncor’s authorized regulatory capital structure is 57.5 % debt to 42.5 % equity at December 31, 2025.

▪ If the credit rating on Oncor’s senior secured debt by any of the Rating Agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. At December 31, 2025, all of Oncor’s senior secured ratings were above BBB.

▪ Oncor’s revolving credit lines and certain of its other debt agreements require it to maintain a consolidated senior debt-to-capitalization ratio of no more than 65 % and observe certain affirmative covenants. At December 31, 2025, Oncor was in compliance with these covenants.

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Based on these restrictions, at December 31, 2025, Oncor’s restricted net assets were $ 18.4 billion, which could not be transferred to its owners.

Sempra owns a 50 % interest in Sharyland Holdings, which owns a 100 % interest in Sharyland Utilities. Significant restrictions related to this equity method investment include:

▪ Sharyland Utilities may not pay dividends or make other distributions (except for contractual payments) without the consent of all JV partners.

▪ Sharyland Utilities must remain in compliance with the capital structure established by the PUCT for ratemaking purposes and may not pay dividends or other distributions (except for contractual tax payments) if that payment would cause its debt to exceed 59 % of its capital structure.

▪ Sharyland Utilities has a revolving credit line and three senior notes that require it to maintain a consolidated debt-to-capitalization ratio of no more than 70 % and observe certain customary reporting requirements and other affirmative covenants. At December 31, 2025, Sharyland Utilities was in compliance with these and all other covenants.

Based on these restrictions, at December 31, 2025, Sharyland Utilities’ restricted net assets were $ 142 million, which could not be transferred to its owners.

Significant restrictions at Sempra Infrastructure include:

▪ Partnerships and JVs at SI Partners may not pay dividends or make other distributions (except for contractual payments) without the consent of the partners or members.

▪ SI Partners has an equity method investment in Cameron LNG JV, which has debt agreements that require the establishment and funding of project accounts to which the proceeds of loans, project revenues and other amounts are deposited and applied in accordance with the debt agreements. The debt agreements require the JV to maintain reserve accounts in order to pay the project debt service, and also contain restrictions related to the payment of dividends and other distributions to the members of the JV.

Pursuant to the transfer restriction agreement under the debt agreements, Sempra must retain at least 10 % of the indirect fully diluted economic and beneficial ownership interest in Cameron LNG JV. In addition, at all times, a Sempra controlled (but not necessarily wholly owned) subsidiary must directly own 50.2 % of the membership interests of Cameron LNG JV. Sempra is pursuing the necessary consents to modify the agreement to waive this restriction.

To support Cameron LNG JV’s obligations under its debt agreements, Cameron LNG JV has granted security over all of its assets, subject to customary exceptions, and all equity interests in Cameron LNG JV were pledged to HSBC Bank USA, National Association, as security trustee for the benefit of all of Cameron LNG JV’s creditors. As a result, an enforcement action by the lenders taken in accordance with the finance documents could result in the exercise of such security interests by the lenders and the loss of ownership interests in Cameron LNG JV by Sempra and the other project owners.

Under these restrictions, net assets of Cameron LNG JV of approximately $ 425 million were restricted at December 31, 2025.

▪ Mexico requires domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $ 221 million at SI Partners’ consolidated Mexican subsidiaries at December 31, 2025.

▪ TAG Norte, a 50 % owned and unconsolidated JV of SI Partners, has a long-term debt agreement that requires it to maintain a reserve account to pay the projects’ debt. Under these restrictions, net assets totaling $ 132 million were restricted at December 31, 2025.

▪ Port Arthur LNG I has a seven-year term loan facility agreement and working capital credit facility agreement that require consent of a trustee for the withdrawal or transfer of cash. Under these restrictions, net assets totaling $ 35 million were restricted at December 31, 2025.

▪ Port Arthur LNG II is required to maintain reserve accounts and has restrictions related to the payment of distributions to the members under the PA2 JVCo LLCA. Under these restrictions, net assets totaling $ 2.2 billion were restricted at December 31, 2025.

▪ SI Partners and Port Arthur LNG I have restrictions under certain equity agreements that may entitle certain partners to future distributions or credit towards future contributions. Under these restrictions, net assets totaling $ 1.2 billion were restricted at December 31, 2025.

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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). We adopted the standard on December 31, 2025 on a retrospective basis. See revised disclosures for all periods presented in Note 8.

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.

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NOTE 3. REVENUES

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 California	Sempra Infrastructure	Consolidating adjustments and Parent and other	Sempra
	Year ended December 31, 2025
By major service line:
Utilities	$ 11,454	$ 78	$ ( 25 )	$ 11,507
Energy-related businesses	—	974	( 63 )	911
Revenues from contracts with customers	$ 11,454	$ 1,052	$ ( 88 )	$ 12,418
By market:
Gas	$ 7,345	$ 642	$ ( 22 )	$ 7,965
Electric	4,109	410	( 66 )	4,453
Revenues from contracts with customers	$ 11,454	$ 1,052	$ ( 88 )	$ 12,418
Revenues from contracts with customers	$ 11,454	$ 1,052	$ ( 88 )	$ 12,418
Utilities regulatory revenues	364	—	—	364
Other revenues	—	913	7	920
Total revenues	$ 11,818	$ 1,965	$ ( 81 )	$ 13,702
	Year ended December 31, 2024
By major service line:
Utilities	$ 11,008	$ 78	$ ( 23 )	$ 11,063
Energy-related businesses	—	818	( 63 )	755
Revenues from contracts with customers	$ 11,008	$ 896	$ ( 86 )	$ 11,818
By market:
Gas	$ 6,858	$ 471	$ ( 21 )	$ 7,308
Electric	4,150	425	( 65 )	4,510
Revenues from contracts with customers	$ 11,008	$ 896	$ ( 86 )	$ 11,818
Revenues from contracts with customers	$ 11,008	$ 896	$ ( 86 )	$ 11,818
Utilities regulatory revenues	374	—	—	374
Other revenues	—	986	7	993
Total revenues	$ 11,382	$ 1,882	$ ( 79 )	$ 13,185
	Year ended December 31, 2023
By major service line:
Utilities	$ 13,686	$ 87	$ ( 19 )	$ 13,754
Energy-related businesses	—	1,164	( 70 )	1,094
Revenues from contracts with customers	$ 13,686	$ 1,251	$ ( 89 )	$ 14,848
By market:
Gas	$ 8,949	$ 755	$ ( 17 )	$ 9,687
Electric	4,737	496	( 72 )	5,161
Revenues from contracts with customers	$ 13,686	$ 1,251	$ ( 89 )	$ 14,848
Revenues from contracts with customers	$ 13,686	$ 1,251	$ ( 89 )	$ 14,848
Utilities regulatory revenues	75	—	—	75
Other revenues	—	1,820	( 23 )	1,797
Total revenues	$ 13,761	$ 3,071	$ ( 112 )	$ 16,720

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DISAGGREGATED REVENUES
(Dollars in millions)
	SDG&E			SoCalGas
	Years ended December 31,
	2025	2024	2023	2025	2024	2023
By major service line:
Revenues from contracts with customers – Utilities	$ 5,165	$ 5,042	$ 5,954	$ 6,459	$ 6,134	$ 7,857
By market:
Gas	$ 1,043	$ 878	$ 1,204	$ 6,459	$ 6,134	$ 7,857
Electric	4,122	4,164	4,750	—	—	—
Revenues from contracts with customers	$ 5,165	$ 5,042	$ 5,954	$ 6,459	$ 6,134	$ 7,857
Revenues from contracts with customers	$ 5,165	$ 5,042	$ 5,954	$ 6,459	$ 6,134	$ 7,857
Utilities regulatory revenues	532	299	( 357 )	( 168 )	75	432
Total revenues	$ 5,697	$ 5,341	$ 5,597	$ 6,291	$ 6,209	$ 8,289

REVENUES FROM CONTRACTS WITH CUSTOMERS

Revenues from contracts with customers are primarily related to the transmission, distribution and storage of natural gas and the generation, transmission and distribution of electricity through our regulated utilities. We also provide other midstream and renewable energy-related services. We assess our revenues on a contract-by-contract basis as well as a portfolio basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized.

We generally recognize revenues when performance of the promised commodity or service is provided to customers and invoices are issued for an amount that reflects the consideration we are entitled to in exchange for those services. We consider the delivery and transmission of natural gas and electricity and providing of natural gas storage services as ongoing and integrated services. Generally, natural gas or electricity services are received and consumed by the customer simultaneously. Performance obligations related to these services are satisfied over time and represent a series of distinct services that are substantially the same and that have the same pattern of transfer to the customers. We recognize revenue based on units delivered, as the satisfaction of respective performance obligations can be directly measured by the amount of natural gas or electricity delivered to the customer. In most cases, the right to consideration from the customer directly corresponds to the value transferred to the customer and we recognize revenue in the amount that we have the right to invoice.

The payment terms in customer contracts vary. Typically, we have an unconditional right to customer payments, which are due after the performance obligation to the customer is satisfied. The term between invoicing and when payment is due is typically between 10 and 90 days.

We exclude sales and usage-based taxes from revenues. In addition, SDG&E and SoCalGas pay franchise fees to operate in various municipalities. SDG&E and SoCalGas bill these franchise fees to their customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SDG&E’s and SoCalGas’ ability to collect from customers, are accounted for on a gross basis and reflected in utilities revenues from contracts with customers and operating expense.

Utilities Revenues

Utilities revenues represent the majority of our consolidated revenues from contracts with customers and include:

▪ The transmission, distribution and storage of natural gas at:

◦ SDG&E

◦ SoCalGas

◦ Sempra’s Ecogas

▪ The generation, transmission and distribution of electricity at SDG&E.

Utilities revenues are derived from and recognized upon the delivery of natural gas or electricity services to customers. Amounts that we bill customers are based on tariffs set by regulators within the respective state or country. For SDG&E and SoCalGas, amounts that we bill to customers also include adjustments for previously recognized regulatory revenues.

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SDG&E, SoCalGas and Ecogas recognize revenues based on regulator-approved revenue requirements, which allow the utilities to recover their reasonable operating costs and provides the opportunity to realize their authorized rates of return on their investments. While SDG&E’s and SoCalGas’ revenues are not affected by actual sales volumes, the pattern of their revenue recognition during the year is affected by seasonality. SDG&E and SoCalGas recognize annual authorized revenue from customers using seasonal factors established in applicable proceedings. This generally results in a significant portion of operating revenues being recognized in the third quarter of each year for SDG&E and in the first and fourth quarters of each year for SoCalGas.

SDG&E has an arrangement to provide the California ISO with the ability to control its high-voltage transmission lines for prices approved by the FERC. Revenue is recognized over time as access is provided to the California ISO.

Factors that can affect the amount, timing and uncertainty of revenues and cash flows include weather, seasonality and timing of customer billings and collections, which may result in unbilled revenues that can vary significantly from month to month and generally approximate one-half month’s deliveries.

SDG&E and SoCalGas recognize revenues from the sale of allocated California GHG allowances at quarterly auctions administered by CARB. GHG allowances are delivered to CARB in advance of the quarterly auctions, and SDG&E and SoCalGas have the right to payment when the GHG allowances are sold at auction. GHG revenue is recognized on a point in time basis within the quarter the auction is held. SDG&E and SoCalGas balance costs and revenues associated with the GHG program through regulatory balancing accounts.

Energy-Related Businesses Revenues

Revenues at Sempra Infrastructure typically represent revenues from long-term, U.S. dollar-based contracts with customers for the sale of natural gas and LNG, as well as storage and transportation of natural gas. Invoiced amounts are based on the volume of natural gas delivered and contracted prices.

We generate pipeline transportation revenues from firm agreements, under which customers pay a fee for reserving transportation capacity. Revenue is recognized when the volumes are delivered to the customers’ agreed upon delivery point. We recognize revenues for our stand-ready obligation to provide capacity and transportation services throughout the contractual delivery period, as the benefits are received and consumed simultaneously as customers utilize pipeline capacity for the transport and receipt of natural gas and LPG. Invoiced amounts are based on a variable usage fee and a fixed capacity charge, which may be adjusted for the Consumer Price Index, the effects of any foreign currency impacts and the actual quantity of commodity transported.

Sempra Infrastructure develops, invests in and operates solar and wind facilities that have long-term PPAs to sell the electricity and the related green energy attributes they generate to customers, generally load serving entities, industrial and other customers. Load serving entities will sell electric service to their end-users and wholesale customers immediately upon receipt of our power delivery, and industrial and other customers immediately consume the electricity to run their facilities, and thus, we recognize the revenue under the PPAs as the electricity is generated and delivered. We invoice customers based on the volume of energy delivered at rates pursuant to the PPAs.

TdM is a natural gas-fired power plant that generates revenues from selling electricity and/or resource adequacy to the California ISO and to governmental, public utility and wholesale power marketing entities as the power is delivered at the interconnection point.

We recognize storage revenue from firm capacity reservation agreements, under which we collect a fee for reserving storage capacity for customers in our storage facilities. Under these firm agreements, customers pay a monthly fixed reservation fee based on the storage capacity reserved rather than the actual volumes stored. For the fixed-fee component, revenue is recognized on a straight-line basis over the term of the contract. We bill customers for any capacity used in excess of the contracted capacity and such revenues are recognized in the month of occurrence. We also recognize revenue for interruptible storage services.

Sempra Infrastructure sells natural gas to the CFE and other customers under supply agreements. Sempra Infrastructure recognizes the revenue from the sale of natural gas upon transfer of the natural gas via pipelines to customers at the agreed upon delivery points, and in the case of the CFE, at its thermoelectric power plants.

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Remaining Performance Obligations

We do not disclose information about remaining performance obligations for (a) contracts with an original expected length of one year or less, (b) variable consideration recognized at the amount at which we have the right to invoice for services performed, or (c) variable consideration allocated to wholly unsatisfied performance obligations.

For contracts greater than one year, we expect to recognize revenue related to the fixed fee component of the consideration. Sempra’s remaining performance obligations primarily relate to capacity agreements for transmission line projects at SDG&E and natural gas storage and transportation at Sempra Infrastructure. SoCalGas did not have any remaining performance obligations for contracts greater than one year at December 31, 2025.

At December 31, 2025, SDG&E’s remaining performance obligations for contracts greater than one year totaled $ 68 million, comprising $ 4 million in each of 2026 through 2030 and $ 48 million thereafter. At December 31, 2025, remaining performance obligations for contracts greater than one year within the disposal group that is classified as held for sale totaled $ 3,138 million, comprising $ 306 million in 2026, $ 287 million in 2027, $ 241 million in 2028, $ 213 million in 2029, $ 213 million in 2030, and $ 1,878 million thereafter.

Contract Liabilities from Revenues from Contracts with Customers

From time to time, we receive payments in advance of satisfying the performance obligations associated with customer contracts. We defer such revenues as contract liabilities and recognize them in earnings as the performance obligations are satisfied.

Activities within Sempra’s and SDG&E’s contract liabilities are presented below. There were no contract liabilities at SoCalGas in 2025, 2024 or 2023.

CONTRACT LIABILITIES
(Dollars in millions)
	2025	2024	2023
Sempra:
Contract liabilities at January 1	$ ( 196 )	$ ( 198 )	( 252 )
Revenue from performance obligations satisfied during reporting period (1)	105	11	14
Payments received in advance (1)	( 1 )	( 7 )	( 21 )
Contract modification	—	( 2 )	61
Reclassification to liabilities held for sale	24	—	—
Contract liabilities at December 31 (2)	$ ( 68 )	$ ( 196 )	$ ( 198 )
SDG&E:
Contract liabilities at January 1	$ ( 72 )	$ ( 75 )	$ ( 79 )
Revenue from performance obligations satisfied during reporting period	4	3	4
Contract liabilities at December 31 (3)	$ ( 68 )	$ ( 72 )	$ ( 75 )

(1) Includes activities in 2025 within the disposal group that is classified as held for sale.

(2) Balances at December 31, 2025 and 2024 include $ 4 and $ 105 , respectively, in Other Current Liabilities and $ 64 and $ 91 , respectively, in Deferred Credits and Other.

(3) Balances at December 31, 2025 and 2024 include $ 4 and $ 4 , respectively, in Other Current Liabilities and $ 64 and $ 68 , respectively, in Deferred Credits and Other.

Sempra Infrastructure previously recorded a contract liability for funds held as collateral in lieu of a customer’s letters of credit primarily associated with its LNG storage and regasification agreement. In December 2024, Sempra Infrastructure and the customer agreed to modify their LNG storage and regasification agreement by reducing the remaining term of the agreement from approximately three years to one year , expiring in December 2025. The net effect to our contract liabilities is reflected in “contract modification” in the table above. As a result of the modification, Sempra Infrastructure recognized revenue of $ 101 million in 2025 and $ 6 million in 2024 from the customer payments received in advance.

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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 Consolidated Balance Sheets.

RECEIVABLES FROM REVENUES FROM CONTRACTS WITH CUSTOMERS
(Dollars in millions)
	December 31,
	2025	2024
Sempra:
Accounts receivable – trade, net (1)	$ 1,767	$ 1,787
Accounts receivable – other, net	22	12
Due from unconsolidated affiliates – current (2)	—	4
Assets held for sale	77	—
Other long-term assets (3)	21	18
Total	$ 1,887	$ 1,821
SDG&E:
Accounts receivable – trade, net (1)	$ 809	$ 774
Accounts receivable – other, net	18	11
Due from unconsolidated affiliates – current (2)	11	6
Other long-term assets (3)	3	4
Total	$ 841	$ 795
SoCalGas:
Accounts receivable – trade, net	$ 958	$ 932
Accounts receivable – other, net	4	1
Other long-term assets (3)	18	14
Total	$ 980	$ 947

(1) At December 31, 2025 and 2024, includes $ 152 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 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.

REVENUES FROM SOURCES OTHER THAN CONTRACTS WITH CUSTOMERS

Certain of our revenues are derived from sources other than contracts with customers and are accounted for under other accounting standards outside the scope of ASC 606.

Utilities Regulatory Revenues

Alternative Revenue Programs

We recognize revenues from alternative revenue programs when the regulator-specified conditions for recognition have been met and adjust these revenues as they are recovered or refunded through future utility service.

Decoupled Revenues. As we discuss above, the regulatory framework requires SDG&E and SoCalGas to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. However, actual demand for natural gas and electricity will typically vary from CPUC-approved forecasted demand due to the impacts from weather volatility, energy efficiency programs, rooftop solar and other factors affecting consumption. The CPUC regulatory framework provides for SDG&E and SoCalGas to use a “decoupling” mechanism, which allows SDG&E and SoCalGas to record revenue shortfalls or excess revenues resulting from any difference between actual and forecasted demand to be recovered or refunded in authorized revenue in a subsequent period based on the nature of the account.

Incentive Mechanisms. SoCalGas is subject to the GCIM and is eligible for financial awards or subject to financial penalties depending on its performance in relation to specific benchmarks.

Incentive awards are included in revenues when we receive required CPUC approval of the award, the timing of which may not be consistent from year to year. We would record penalties for results below the specified benchmarks against revenues when we believe it is probable that the CPUC would assess a penalty.

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Other Cost-Based Regulatory Recovery

The CPUC, and the FERC as applicable to SDG&E, authorize SDG&E and SoCalGas to collect, or in the case of CPUC programmatic activities, to apply for, additional revenue requirements beyond base rates from customers for certain operating and capital-related costs (depreciation, taxes and return on rate base), including for:

▪ costs to purchase natural gas and electricity

▪ costs associated with administering public purpose, demand response, environmental compliance, and customer energy efficiency programs

▪ programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation

▪ costs associated with third-party liability insurance premiums

Authorized costs are recovered as the commodity or service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded in a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met when the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may require regulatory review procedures before authorizing recovery or refund of amounts accumulated for authorized programs, including reviews of costs for reasonableness, and may impose limitations on a program’s total cost or revenue requirement. These procedures and requirements could result in delays or disallowances of recovery from customers.

We discuss balancing accounts and their effects further in Note 4.

Other Revenues

Sempra Infrastructure generates lease revenues from certain of its natural gas and ethane pipelines, compressor stations, LPG storage facilities, a rail facility and refined products terminals. We discuss the recognition of lease income in Note 16.

Sempra Infrastructure has an agreement with Tangguh PSC to supply LNG to the ECA Regas Facility. Under the terms of the agreement, Tangguh PSC must either deliver the contracted number of cargoes or pay a diversion fee for non-delivery of LNG cargoes.

Sempra Infrastructure also recognizes other revenues associated with derivatives related to the sales of natural gas and electricity under short-term and long-term contracts and into the spot market and other competitive markets. Revenues include the net realized gains and losses on physical and derivative settlements and net unrealized gains and losses from the change in fair values of these derivatives.

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NOTE 4. REGULATORY MATTERS

REGULATORY ASSETS AND LIABILITIES

We show the details of regulatory assets and liabilities in the following table and discuss them below. With the exception of regulatory balancing accounts, we generally do not earn a return on our regulatory assets until 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) AT DECEMBER 31
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
	2025	2024	2025	2024	2025	2024
Fixed-price contracts and other derivatives	$ 50	$ 53	$ 7	$ 11	$ 43	$ 42
Deferred income taxes recoverable in rates (1)	2,314	1,689	1,098	802	1,189	817
Pension and PBOP plan obligations	( 610 )	( 458 )	( 1 )	( 2 )	( 609 )	( 456 )
Employee benefit costs	18	19	3	3	15	16
Removal obligations	( 3,540 )	( 3,295 )	( 2,913 )	( 2,676 )	( 627 )	( 619 )
Environmental costs	152	149	113	115	39	34
Sunrise Powerlink fire mitigation	125	124	125	124	—	—
Regulatory balancing accounts (2)(3) :
Commodity – electric	186	( 313 )	186	( 313 )	—	—
Commodity – gas, including transportation	173	( 47 )	17	86	156	( 133 )
Safety and reliability	894	820	286	227	608	593
Public purpose programs	( 347 )	( 439 )	( 175 )	( 219 )	( 172 )	( 220 )
2024 GRC retroactive impacts	299	631	124	277	175	354
Wildfire mitigation plan (4)	530	808	530	808	—	—
Liability insurance premium	( 62 )	( 24 )	( 53 )	( 15 )	( 9 )	( 9 )
Other balancing accounts	90	158	4	( 51 )	86	209
Other regulatory assets, net (3)	104	164	72	87	32	79
Total	$ 376	$ 39	$ ( 577 )	$ ( 736 )	$ 926	$ 707

(1) At December 31, 2025, $ 54 is included in Assets Held for Sale on the Sempra Consolidated Balance Sheet.

(2) At December 31, 2025 and 2024, the noncurrent portion of regulatory balancing accounts – net undercollected for Sempra was $ 1,060 and $ 1,731 , respectively, for SDG&E was $ 502 and $ 873 , respectively, and for SoCalGas was $ 558 and $ 858 , respectively.

(3) Includes regulatory assets earning a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate.

(4) Includes a $ 508 decrease in 2025 from regulatory disallowances associated with SDG&E’s 2024 GRC Track 2 FD.

Regulatory Assets Not Earning a Return

▪ Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. Regulatory assets increase/decrease based on changes in the fair market value of the contracts. They are also reduced as payments are made for commodities and services under these contracts. The related amounts are recovered in rates once these contracts are settled, generally within four years .

▪ Deferred income taxes recoverable/refundable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Infrastructure expect to recover/refund net regulatory assets/liabilities related to deferred income taxes over the lives of the assets, ranging from 5 to 69 years, that give rise to the related accumulated deferred income tax balances. Regulatory assets and liabilities include excess deferred income taxes resulting from statutory income tax rate changes and certain income tax benefits and expenses associated with flow-through items, which we discuss in Note 8.

▪ Regulatory assets/liabilities related to pension and PBOP plan obligations are offset by corresponding liabilities/assets. The assets are recovered in rates as the plans are funded.

▪ The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.

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▪ Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs in excess of cumulative amounts incurred (or paid).

▪ Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made.

▪ The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 44-year period.

Regulatory Assets Earning a Return

▪ Over and undercollected regulatory balancing accounts and other regulatory assets, net, reflect the difference between customer billings and recorded or CPUC-authorized amounts. Depreciation, taxes and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. The adopted revenue requirements in the 2024 GRC FD were placed into rates on February 1, 2025 and 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. SDG&E and SoCalGas periodically make requests to the CPUC to true up their revenue requirement for amounts accumulated in the regulatory balancing accounts and in other regulatory assets, net. The CPUC may require regulatory review procedures before authorizing recovery or refund of amounts accumulated for authorized programs, including reviews of costs for reasonableness, and may impose limitations on a program’s total cost or revenue requirement. These procedures and requirements could result in delays or disallowances of recovery from customers.

Amortization expense on certain regulatory assets for the years ended December 31, 2025, 2024 and 2023 was $ 16 million, $ 14 million and $ 12 million, respectively, at Sempra, $ 7 million, $ 7 million and $ 6 million, respectively, at SDG&E, and $ 9 million, $ 7 million and $ 6 million, respectively, at SoCalGas. In September 2025, we classified SI Partners as held for sale and ceased recording amortization.

Catastrophic Event Memorandum Account

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 year ended December 31, 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’ Consolidated Statements of Operations. The CPUC denied SoCalGas’ request for a rehearing of the FD.

CPUC GRC

A CPUC GRC proceeding is designed to set authorized base revenue requirements that are sufficient 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.

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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 and 2026 revenue requirements were, and 2027 revenue requirements will be, updated to implement the applicable authorized changes in the cost of capital, which we describe below.

In December 2025, SDG&E and SoCalGas filed a petition for modification of the 2024 GRC, seeking to modify the post-test year mechanism for capital related costs. The petition for modification seeks increases of $ 55 million, $ 87 million and $ 79 million to the approved revenue requirements for SDG&E for 2025, 2026 and 2027, respectively, and increases of $ 86 million, $ 122 million and $ 109 million to the approved revenue requirements for SoCalGas for 2025, 2026 and 2027, respectively. There is no established timeline for the CPUC to act on this filing.

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 recoverable from customers that are not included in the amounts described above. We record regulatory revenues associated with the O&M and capital costs of these projects and programs as such costs are incurred.

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 $ 1,472 million of WMP costs incurred from 2019 through 2022 that were incremental to amounts authorized in the 2019 GRC and not otherwise addressed in the 2024 GRC FD. In January 2026, the CPUC issued an FD in SDG&E’s Track 2 request that approves recovery of $ 1,023 million of these requested costs, including $ 78 million of O&M costs and $ 945 million of capital costs. The Track 2 FD allows SDG&E to seek recovery in Track 3 of this proceeding of the drone inspection and repair program costs that were disallowed in the Track 2 FD.

The Track 2 request also addresses SDG&E’s requested revenue requirement for the period from 2019 through 2027 for ongoing capital-related costs for capital assets placed into service from 2019 through 2022. The FD authorizes a total Track 2 revenue requirement of $ 707 million for 2019 through 2027, which is $ 441 million lower than SDG&E’s requested revenue requirement of $ 1,148 million. In February 2024, the CPUC authorized an interim cost recovery mechanism that permitted SDG&E to collect in rates $ 194 million and $ 96 million of this revenue requirement in 2024 and 2025, respectively. The FD authorizes SDG&E to collect the remaining $ 417 million from 2026 through 2028.

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 WMP costs incurred in 2023 that were in addition to the amounts authorized in the 2019 GRC and not addressed in the 2024 GRC. SDG&E expects to provide supplemental testimony in its Track 3 request for drone inspection and repair program costs that were disallowed in its Track 2 request. SDG&E expects to receive a PD for its Track 3 request related to its WMP costs in the second half of 2026. Additionally, SDG&E and SoCalGas submitted a combined request seeking review and recovery of $ 240 million of PSEP costs incurred from 2014 through 2019 and $ 499 million of PSEP costs incurred from 2015 through 2020. SDG&E and SoCalGas expect to receive a PD for their Track 3 requests related to their PSEP costs in the first half of 2026.

Revenue requirements associated with the Track 3 requests have been recorded in regulatory accounts and disallowances resulting from Track 3 would be recorded as an expense on the Sempra, SDG&E and SoCalGas Consolidated Statements of Operations. 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.

Accounting Impact of Regulatory Disallowances

In connection with the Track 2 FD, in the fourth quarter of 2025, SDG&E recorded a charge of $ 651 million ($ 464 million after tax) in Regulatory Disallowances on the SDG&E and Sempra Consolidated Statements of Operations, of which $ 605 million ($ 432 million after tax) relates to 2019 through 2024, $ 41 million ($ 28 million after tax) relates to the first nine months of 2025, and $ 5 million ($ 4 million after tax) relates to the fourth quarter of 2025.

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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 return on rate base. The CPUC applies the CCM in the interim years to consider changes in the cost of capital using changes in interest rates as reflected by the applicable utility bond index published by Moody’s (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. Alternatively, each of SDG&E and SoCalGas is 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.

The CPUC-approved cost of capital, subject to the CCM, for SDG&E and SoCalGas that became effective on January 1, 2023 was to remain in effect through December 31, 2025. The CCM was triggered for SDG&E and SoCalGas for the measurement period ending September 30, 2023, and in December 2023, the CPUC approved updated authorized rates of return effective January 1, 2024.

In October 2023, the CPUC issued a ruling to initiate a second phase of the 2023-2025 cost of capital proceeding to evaluate potential modifications to the CCM. In October 2024, the CPUC issued an FD to modify the CCM. The FD updates the upward or downward adjustment to authorized ROE, if the CCM is triggered, from 50 % to 20 % of the change in the benchmark rate during the measurement period. The FD adopted this change effective January 1, 2025, reducing both SDG&E’s and SoCalGas’ ROE by 42 bps to 10.23 % and 10.08 %, respectively, and allowing SDG&E and SoCalGas to update their respective costs of preferred equity and debt for 2025.

The following table summarizes the CPUC-approved cost of capital for SDG&E and SoCalGas for 2023 through 2025. The authorized weighting remained unchanged for each of the years presented.

AUTHORIZED COST OF CAPITAL	Authorized weighting	2023	2024	2025	2023 (1)	2024	2025
		Return on rate base			Weighted return on rate base
SDG&E:
Long-Term Debt	45.25 %	4.05 %	4.34 %	4.34 %	1.83 %	1.96 %	1.96 %
Preferred Equity	2.75	6.22	6.22	6.22	0.17	0.17	0.17
Common Equity	52.00	9.95	10.65	10.23	5.17	5.54	5.32
	100.00 %				7.18 %	7.67 %	7.45 %
SoCalGas:
Long-Term Debt	45.60 %	4.07 %	4.54 %	4.63 %	1.86 %	2.07 %	2.11 %
Preferred Equity	2.40	6.00	6.00	6.00	0.14	0.14	0.14
Common Equity	52.00	9.80	10.50	10.08	5.10	5.46	5.24
	100.00 %				7.10 %	7.67 %	7.49 %

(1) Total weighted return on rate base for SDG&E does not sum due to rounding differences.

In December 2025, the CPUC approved the following cost of capital for SDG&E and SoCalGas that became effective on January 1, 2026 and will remain in effect through December 31, 2028, subject to the CCM.

AUTHORIZED COST OF CAPITAL FOR 2026 – 2028
SDG&E				SoCalGas
Authorized weighting	Return on rate base	Weighted return on rate base		Authorized weighting	Return on rate base	Weighted return on rate base
45.25 %	4.59 %	2.08 %	Long-Term Debt	45.60 %	5.02 %	2.29 %
2.75	6.22	0.17	Preferred Equity	2.40	6.00	0.14
52.00	9.93	5.16	Common Equity	52.00	9.78	5.09
100.00 %		7.41 %		100.00 %		7.52 %

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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. As a result of the FERC order, SDG&E recorded a charge of $ 120 million ($ 89 million after tax) with $ 94 million in Electric Revenues and $ 26 million in Other Income, Net, on the SDG&E and Sempra Consolidated Statements of Operations in the year ended December 31, 2024.

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 proposed, 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. In February 2026, the settlement judge in the TO6 proceeding reported to the FERC that the participants had reached an agreement in principle on all issues in the proceeding. The parties will draft an offer of settlement to be filed with the FERC for approval.

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 Consolidated Statements of Operations. Distributions received from equity method investees are classified in the 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.

Our equity method investments include various domestic and foreign entities. Our domestic equity method investees are typically partnerships that are pass-through entities for income tax purposes and therefore they do not record income tax. Sempra’s income tax on earnings from these equity method investees, other than Oncor Holdings as we discuss below, is included in Income Tax Expense on the Consolidated Statements of Operations. Our foreign equity method investees are generally corporations whose operations are taxable on a standalone basis in the countries in which they operate, and we recognize our equity in such income or loss net of investee income tax. See Note 8 for information on how equity earnings and losses before income taxes are factored into the calculations of our pretax income or loss and ETR.

We provide the carrying values of our investments on the Sempra Consolidated Balance Sheets and earnings on these investments by segment on the Sempra Consolidated Statements of Operations in the following tables.

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EQUITY METHOD AND OTHER INVESTMENTS (1)
(Dollars in millions)
	Percent ownership		Investment balance
	December 31,
	2025	2024	2025	2024
Sempra Texas Utilities:
Oncor Holdings (2)	100 %	100 %	$ 17,472	$ 15,400
Sempra Texas Utilities:
Sharyland Holdings (3)	50 %	50 %	$ 129	$ 122
Sempra Infrastructure:
Cameron LNG JV (4),(5)	50.2	50.2	17	1,149
IMG (6)	40	40	—	723
TAG Norte (7)	50	50	—	539
Segment totals			146	2,533
Parent and other – Other			1	1
Total			$ 147	$ 2,534

(1) All amounts are before NCI, where applicable.

(2) The carrying value of our equity method investment is $ 2,769 and $ 2,884 higher than the underlying equity in the net assets of the investee at December 31, 2025 and 2024, respectively, due to $ 2,868 of equity method goodwill and $ 69 in basis differences in AOCI, offset by $ 44 and $ 53 at December 31, 2025 and 2024, respectively, due to a tax sharing liability to TTI under a tax sharing agreement and $ 124 of deferred income taxes at December 31, 2025.

(3) The carrying value of our equity method investment is $ 41 higher than the underlying equity in the net assets of the investee due to equity method goodwill.

(4) At December 31, 2025, $ 1,242 is included in Assets Held for Sale, the carrying value of which is $ 251 and $ 257 higher than the underlying equity in the net assets of the investee at December 31, 2025 and 2024, respectively, primarily due to guarantees, interest capitalized on the investment prior to the JV commencing its operations, and amortization of guarantee fees and capitalized interest thereafter.

(5) Includes $ 17 and $ 18 at December 31, 2025 and 2024, respectively, which represents Sempra’s investment balance related to the guarantee under the SDSRA, which we discuss in Note 16, that will remain with Sempra following completion of the planned sale of a portion of our equity interest in SI Partners.

(6) At December 31, 2025, $ 766 is included in Assets Held for Sale, the carrying value of which is $ 5 higher than the underlying equity in the net assets of the investee due to guarantees.

(7) At December 31, 2025, $ 558 is included in Assets Held for Sale, the carrying value of which is $ 130 higher than the underlying equity in the net assets of the investee due to equity method goodwill.

EARNINGS FROM EQUITY METHOD INVESTMENTS (1)
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
EARNINGS RECORDED BEFORE INCOME TAX (2) :
Sempra Texas Utilities:
Sharyland Holdings	$ 7	$ 8	$ 7
Sempra Infrastructure:
Cameron LNG JV (3)	613	576	586
Segment totals	620	584	593
Parent and other – RBS Sempra Commodities LLP	—	19	40
	620	603	633
EARNINGS RECORDED NET OF INCOME TAX:
Sempra Texas Utilities:
Oncor Holdings	862	780	694
Sempra Infrastructure:
IMG	43	136	40
TAG Norte	79	90	114
Segment totals	984	1,006	848
Total	$ 1,604	$ 1,609	$ 1,481

(1) All amounts are before NCI, where applicable.

(2) We provide our ETR calculation in Note 8.

(3) Includes $ 9 of basis differences in equity earnings related to AOCI in 2023.

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We provide the expenditures for and distributions from our investments by segment in the following tables.

EXPENDITURES FOR INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra Texas Utilities:
Oncor Holdings	$ 2,009	$ 972	$ 363
Sharyland Holdings	4	4	4
	2,013	976	367
Sempra Infrastructure:
Cameron LNG JV	2	12	15
Total	$ 2,015	$ 988	$ 382

DISTRIBUTIONS FROM INVESTMENTS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra Texas Utilities:
Oncor Holdings (1)	$ 634	$ 616	$ 441
Sharyland Holdings	4	4	4
	638	620	445
Sempra Infrastructure:
Cameron LNG JV	482	453	456
IMG	—	33	11
TAG Norte	45	62	36
	527	548	503
Segment totals	1,165	1,168	948
Parent and other – RBS Sempra Commodities LLP	—	9	—
Total	$ 1,165	$ 1,177	$ 948

(1) Includes a $ 13 noncash return on investment in 2024. When including payments received under a tax sharing agreement, cash and noncash distributions would total $ 666 , $ 681 and $ 558 in 2025, 2024 and 2023, respectively.

On February 12, 2026, Sempra contributed $ 876 million to Oncor Holdings, and on February 11, 2026, Oncor Holdings distributed $ 229 million to Sempra.

At December 31, 2025 and 2024, our share of the undistributed earnings from equity method investments was $ 3.4 billion and $ 2.9 billion, respectively, including $ 710 million at December 31, 2025 in undistributed earnings from investments for which we have less than a 50% equity interest.

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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. Sempra does not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and commitments in effect limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends or other distributions, strategic planning and other important corporate matters and actions. We also have limited representation on the Oncor Holdings and Oncor boards of directors.

Oncor is a domestic partnership for U.S. federal income tax purposes and is not included in the consolidated income tax return of Sempra. Rather, only our pretax equity earnings from our investment in Oncor Holdings (a disregarded entity for tax purposes) are included in our consolidated income tax return. A tax sharing agreement with TTI, Oncor Holdings and Oncor provides for the calculation of an income tax liability substantially as if Oncor Holdings and Oncor were taxed as corporations and requires tax payments determined on that basis. While partnerships are not subject to income taxes, in consideration of the tax sharing agreement and Oncor being subject to the provisions of U.S. GAAP governing rate-regulated operations, Oncor recognizes amounts determined under cost-based regulatory rate-setting processes (with such costs including income taxes), as if it were taxed as a corporation. As a result, since Oncor Holdings consolidates Oncor, we recognize equity earnings from our investment in Oncor Holdings net of its recorded income tax.

We provide summarized income statement and balance sheet information for Oncor Holdings in the following table.

SUMMARIZED FINANCIAL INFORMATION – ONCOR HOLDINGS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Operating revenues	$ 6,778	$ 6,082	$ 5,586
Operating expenses	( 4,791 )	( 4,318 )	( 4,026 )
Income from operations	1,987	1,764	1,560
Interest expense	( 788 )	( 653 )	( 536 )
Income tax expense	( 236 )	( 217 )	( 192 )
Net income	1,062	957	849
NCI held by TTI	( 211 )	( 192 )	( 170 )
Earnings attributable to Sempra (1)	851	765	679
		December 31,
		2025	2024
Current assets		$ 2,016	$ 1,638
Noncurrent assets		45,659	38,697
Current liabilities		2,284	2,183
Noncurrent liabilities		26,397	21,958
NCI held by TTI		4,300	3,689

(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.

Sharyland Holdings

We account for our 50 % ownership interest in Sharyland Holdings, a JV with SU Investment Partners, L.P. that owns a 100 % interest in Sharyland Utilities, as an equity method investment.

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 $ 2.6 billion at December 31, 2025 is included in Assets Held for Sale on Sempra’s Consolidated Balance Sheet.

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Cameron LNG JV

Cameron LNG JV is a JV among Sempra and three project partners, TotalEnergies SE, Mitsui & Co., Ltd., and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha. SI Partners accounts for its 50.2 % investment in Cameron LNG JV under the equity method.

IMG

SI Partners has a 40 % interest in IMG, a JV with a subsidiary of TC Energy Corporation, and accounts for its interest as an equity method investment. IMG owns and operates the Sur de Texas-Tuxpan natural gas marine pipeline, which is fully contracted under a 35 -year natural gas transportation service contract with the CFE.

TAG Norte

SI Partners has a 50 % beneficial ownership interest in TAG Norte, a JV with TETL JV Mexico Norte, S. de R.L. de C.V. and Bravo N Mergeco, S. de R.L. de C.V. that owns a 50 % interest in the Los Ramones Norte pipeline. SI Partners accounts for its 50 % interest in TAG Norte as an equity method investment.

RBS SEMPRA COMMODITIES LLP

RBS Sempra Commodities LLP is a United Kingdom limited liability partnership formed by Sempra and The Royal Bank of Scotland plc (RBS) in 2008 to own and operate the commodities-marketing businesses previously operated through wholly owned subsidiaries of Sempra. We and RBS sold substantially all of the partnership’s businesses and assets in four separate transactions completed in 2010 and 2011. Since 2011, our investment balance has reflected our share of the remaining partnership assets, including amounts retained by the partnership to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership and the distribution of the partnership’s remaining assets, if any. We accounted for our investment in RBS Sempra Commodities LLP under the equity method.

In 2018, we fully impaired our remaining equity method investment in RBS Sempra Commodities LLP. In 2023, we reduced our previously recorded estimate of losses by $ 40 million based on a settlement that fully resolved legal matters. In 2024, we substantially completed the dissolution of the partnership, at which time we recorded $ 19 million ($ 16 million after tax) in Equity Earnings on Sempra’s Consolidated Statement of Operations.

SUMMARIZED FINANCIAL INFORMATION

The summarized financial information below represents the aggregate results of operations and aggregate financial position of 100 % of each of Sempra’s equity method investments for the periods in which we were invested in the entities.

SUMMARIZED FINANCIAL INFORMATION – EQUITY METHOD INVESTMENTS (1)
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Gross revenues	$ 3,059	$ 2,962	$ 3,083
Operating expenses	( 869 )	( 820 )	( 776 )
Income from operations	2,190	2,142	2,307
Interest expense	( 487 )	( 547 )	( 570 )
Net income/Earnings (2)(3)	1,504	1,688	1,499
		December 31,
		2025	2024
Current assets		1,104	$ 1,134
Noncurrent assets		14,793	14,687
Current liabilities		1,171	1,130
Noncurrent liabilities		9,705	10,051

(1) Excludes Oncor Holdings and RBS Sempra Commodities LLP.

(2) Except for our investments in Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships.

(3) Amounts for Cameron LNG JV exclude adjustments to equity earnings related to amortization of capitalized interest and guarantee fees within the carrying value of our equity method investment and changes in basis differences in equity earnings related to AOCI in 2023.

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NOTE 6. SEMPRA – 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 12 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)
	December 31, 2025
Cash and cash equivalents	$ 112
Restricted cash, current	3,406
Accounts receivable	479
Due from unconsolidated affiliates	3
Inventories	109
Other current assets	218
Restricted cash, noncurrent	3
Right-of-use assets – operating leases	206
Equity method investments	2,566
Goodwill	1,602
Other intangible assets	273
Other long-term assets	691
Property, plant and equipment, net	21,356
Total assets held for sale	$ 31,024
Short-term debt	$ 362
Accounts payable	1,208
Current portion of long-term debt	49
Other current liabilities	290
Long-term debt	7,744
Due to unconsolidated affiliates	477
Deferred income taxes	982
Asset retirement obligations	94
Deferred credits and other	498
Total liabilities held for sale	$ 11,704

At December 31, 2025, $ 26 million of accumulated losses is included in AOCI and is part of the disposal group that is classified as 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.

The agreement provides that, subject to adjustments and the closing date, 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 this sale to close in the second or third quarter of 2026, subject to certain conditions, including receipt of antitrust approvals in Mexico; 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. 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 be entitled to 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, we classified SI Partners as held for sale and ceased recording depreciation and amortization in September 2025. We recognized $ 502 million in Income Tax Expense on Sempra’s Consolidated Statements of Operations for the year ended December 31, 2025 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 of SI Partners 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 generally 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 a 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 a positive 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 Guaymas-El Oro segment of the Sonora pipeline and any proceeds from a sale of the Guaymas-El Oro segment of the Sonora 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 December 2025, we entered into an agreement to sell Ecogas, a natural gas regulated distribution utility that operates in three separate distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico, to Gas Natural del Noroeste S.A. de C.V. for 9.0 billion Mexican pesos (approximately $ 500 million in U.S. dollar-equivalent at December 31, 2025), subject to adjustments. In the first quarter of 2026, we entered into contingent hedges designed to lock in the Mexican peso foreign exchange rate for the anticipated after-tax proceeds. We expect to complete the sale in the second or third quarter of 2026, subject to closing conditions. As a result of satisfying all applicable criteria in June 2025, 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 $ 14 million in Income Tax Expense on Sempra’s Consolidated Statement of Operations in the year ended December 31, 2025 for a Mexican deferred income tax liability related to the excess of carrying value over the tax basis (outside basis difference). Since this $ 14 million ($ 10 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 December 31, 2025, this amount could change in future periods until the date of sale.

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NOTE 7. DEBT AND CREDIT FACILITIES

SHORT-TERM DEBT

Committed Lines of Credit

At December 31, 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)
		December 31, 2025
Borrower	Expiration date of facility	Total facility	Commercial paper outstanding	Amounts outstanding	Letters of credit outstanding	Available unused credit
Sempra	October 2030	$ 4,000	$ ( 983 )	$ —	$ —	$ 3,017
SDG&E	October 2030	1,500	( 532 )	—	—	968
SoCalGas	October 2030	1,200	( 504 )	—	—	696
SI Partners and IEnova	September 2026	500	—	( 91 )	—	409
SI Partners and IEnova	August 2028	1,500	—	( 266 )	—	1,234
SI Partners and IEnova	December 2028 (1)	1,000	—	—	—	1,000
Port Arthur LNG I	March 2030	200	—	—	( 87 )	113
Port Arthur LNG II	September 2030	300	—	—	( 111 )	189
Total		$ 10,200	$ ( 2,019 )	$ ( 357 )	$ ( 198 )	$ 7,626

(1) In December 2025, SI Partners and IEnova amended their shared credit facility to extend the expiration date from August 2026 to December 2028.

The principal terms of Sempra’s, SDG&E’s and SoCalGas’ lines of credit reflected in the table above include the following:

▪ Each revolving credit facility has a syndicate of 23 lenders. No single lender has greater than a 6 % share in any facility.

▪ Sempra’s, SDG&E’s and SoCalGas’ facilities provide for the issuance of $ 200 million, $ 100 million and $ 150 million, respectively, of letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, Sempra, SDG&E and SoCalGas each have the right to increase its letter of credit commitment to up to $ 500 million, $ 250 million and $ 250 million, respectively.

▪ Borrowings bear interest at a benchmark rate plus a margin that varies with the borrower’s credit rating.

▪ Each borrower must maintain a ratio of indebtedness to total capitalization (as defined in each of the applicable credit facilities) of no more than 65 % at the end of each quarter. At December 31, 2025, each Registrant was in compliance with this ratio under its respective credit facility.

SI Partners and IEnova have three combined lines of credit, reflected in the table above, that require borrowings to be issued in U.S. dollars only and include the following principal terms:

▪ Borrowings on the $ 500 million revolving credit facility bear interest at a per annum rate equal to term SOFR plus 80 bps (including a credit adjustment spread).

▪ The $ 1.5 billion revolving credit facility provides for borrowings by SI Partners of up to $ 1.5 billion through a syndicate of 12 lenders and by IEnova of up to $ 1,365 million through a syndicate of 11 lenders, subject to a combined borrowing limit of $ 1.5 billion, bearing interest at a per annum rate equal to term SOFR plus 90 bps (including a credit adjustment spread).

▪ The $ 1.0 billion revolving credit facility provides for borrowings through a syndicate of 12 lenders. This facility:

◦ Charges interest on borrowings at a benchmark rate plus a margin that varies with SI Partners’ credit rating (plus a term SOFR credit adjustment spread of 10 bps in all tenors).

◦ Provides for issuance of up to $ 200 million of letters of credit, subject to a combined letter of credit commitment of $ 200 million, which can be issued in U.S. dollars or Mexican pesos, and which reduces available unused credit.

◦ Includes a $ 100 million swingline loan sub-limit, whereby any outstanding amounts would reduce available unused credit. No swingline loan borrowings were outstanding at December 31, 2025.

◦ Gives either SI Partners or IEnova the right to increase the total facility to $ 1.5 billion, subject to lender approval.

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Additionally, 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 December 31, 2025, SI Partners was in compliance with this ratio.

Port Arthur LNG I and Port Arthur LNG II have working capital facility agreements, reflected in the table above, that permit borrowings of up to $ 200 million and $ 300 million, respectively. Borrowings under these facilities bear interest by reference to term SOFR, plus the applicable margin and a credit adjustment spread. The credit facilities also provide for the issuance of up to $ 200 million and $ 300 million, respectively, 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.

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 disposal group that is classified as held for sale that we discuss in Note 6 but remain legally accessible and a source of available credit to Sempra Infrastructure until the planned sale of a portion of our equity interest in SI Partners closes.

Uncommitted Line of Credit

ECA LNG Phase 1, which is included in the disposal group that is classified as held for sale, 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 December 31, 2025, ECA LNG Phase 1 had outstanding borrowings of $ 5 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 December 31, 2025, we had $ 202 million in standby letters of credit outstanding under these agreements.

UNCOMMITTED LETTERS OF CREDIT OUTSTANDING
(Dollars in millions)
	Expiration date range	December 31, 2025
SDG&E	January 2026 - November 2026	$ 21
SoCalGas	March 2026 - December 2026	15
Other Sempra (1)	March 2026 - June 2026	166
Total Sempra		$ 202

(1) Excludes $ 1,784 in unsecured standby letters of credit with expiration dates ranging from January 2026 - November 2054 that are included in the disposal group that is classified as held for sale.

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.

In December 2025, SoCalGas entered into a $ 400 million, term loan facility with a maturity date of 364 days from the initial borrowing date. On December 10, 2025, SoCalGas borrowed the full $ 400 million available under the term loan. The borrowings bear interest at a per annum rate equal to term SOFR plus 75 bps. SoCalGas used the proceeds for working capital, capital expenditures and other general corporate purposes.

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Other Sempra

In May 2025, Sempra entered into a $ 1.25 billion, 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 were as follows:

WEIGHTED-AVERAGE INTEREST RATES
	December 31,
	2025	2024
Sempra	4.32 %	5.03 %
SDG&E	3.96	4.76
SoCalGas	4.17	5.02

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LONG-TERM DEBT

The following tables show the detail and maturities of long-term debt outstanding.

LONG-TERM DEBT AND FINANCE LEASES
(Dollars in millions)
	December 31,
	2025	2024
SDG&E:
First mortgage bonds (collateralized by plant assets):
2.50 % May 15, 2026	$ 500	$ 500
6.00 % June 1, 2026	250	250
4.95 % August 15, 2028	600	600
1.70 % October 1, 2030	800	800
3.00 % March 15, 2032	500	500
5.40 % April 15, 2035	850	—
5.35 % May 15, 2035	250	250
6.125 % September 15, 2037	250	250
6.00 % June 1, 2039	300	300
5.35 % May 15, 2040	250	250
4.50 % August 15, 2040	500	500
3.95 % November 15, 2041	250	250
4.30 % April 1, 2042	250	250
3.75 % June 1, 2047	400	400
4.15 % May 15, 2048	400	400
4.10 % June 15, 2049	400	400
3.32 % April 15, 2050	400	400
2.95 % August 15, 2051	750	750
3.70 % March 15, 2052	500	500
5.35 % April 1, 2053	800	800
5.55 % April 15, 2054	600	600
	9,800	8,950
Finance lease obligations:
Power purchase agreements	1,109	1,138
Other	67	67
	1,176	1,205
	10,976	10,155
Current portion of long-term debt and finance leases	( 798 )	( 42 )
Unamortized discount on long-term debt	( 33 )	( 33 )
Unamortized debt issuance costs	( 64 )	( 62 )
Total SDG&E	$ 10,081	$ 10,018

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LONG-TERM DEBT AND FINANCE LEASES (CONTINUED)
(Dollars in millions)
	December 31,
	2025	2024
SoCalGas:
First mortgage bonds (collateralized by plant assets):
3.20 % June 15, 2025	$ —	$ 350
2.60 % June 15, 2026	500	500
2.55 % February 1, 2030	650	650
5.20 % June 1, 2033	500	500
5.05 % September 1, 2034	600	600
5.45 % June 15, 2035	600	—
5.75 % November 15, 2035	250	250
5.125 % November 15, 2040	300	300
3.75 % September 15, 2042	350	350
4.45 % March 15, 2044	250	250
4.125 % June 1, 2048	400	400
4.30 % January 15, 2049	550	550
3.95 % February 15, 2050	350	350
6.35 % November 15, 2052	600	600
5.75 % June 1, 2053	500	500
5.60 % April 1, 2054	500	500
6.00 % June 15, 2055	500	—
	7,400	6,650
Other long-term debt (uncollateralized):
1.875 % Notes May 14, 2026 (1)	4	4
2.95 % Notes April 15, 2027	700	700
5.67 % Notes January 18, 2028 (2)	5	5
Finance lease obligations	117	110
	826	819
	8,226	7,469
Current portion of long-term debt and finance leases	( 529 )	( 373 )
Unamortized discount on long-term debt	( 25 )	( 18 )
Unamortized debt issuance costs	( 53 )	( 47 )
Total SoCalGas	$ 7,619	$ 7,031

(1) Callable long-term debt not subject to make-whole provisions.

(2) Debt is not callable.

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LONG-TERM DEBT AND FINANCE LEASES (CONTINUED)
(Dollars in millions)
	December 31,
	2025	2024
Other Sempra:
Sempra - Other long-term debt (uncollateralized):
3.30 % Notes April 1, 2025	$ —	$ 750
5.40 % Notes August 1, 2026	550	550
3.25 % Notes June 15, 2027	750	750
3.40 % Notes February 1, 2028	1,000	1,000
3.70 % Notes April 1, 2029	500	500
5.50 % Notes August 1, 2033	700	700
3.80 % Notes February 1, 2038	1,000	1,000
6.00 % Notes October 15, 2039	750	750
4.00 % Notes February 1, 2048	800	800
4.125 % (next rate reset on April 1, 2027) Junior Subordinated Notes April 1, 2052 (1)	1,000	1,000
6.40 % (next rate reset on October 1, 2034) Junior Subordinated Notes October 1, 2054 (1)	1,250	1,250
6.875 % (next rate reset on October 1, 2029) Junior Subordinated Notes October 1, 2054 (1)	600	600
6.875 % (next rate reset on October 1, 2029) Junior Subordinated Notes October 1, 2054 (1)	500	500
6.55 % (next rate reset on April 1, 2035) Junior Subordinated Notes April 1, 2055 (1)	600	600
6.625 % (next rate reset on April 1, 2030) Junior Subordinated Notes April 1, 2055 (1)	400	400
6.375 % (next rate reset on April 1, 2031) Junior Subordinate Notes April 1, 2056 (1)	800	—
5.75 % Junior Subordinated Notes July 1, 2079 (1)	758	758
	11,958	11,908
Sempra Infrastructure - Other long-term debt (uncollateralized unless otherwise noted) (2) :
Loan at variable rates (weighted-average rate of 7.29 % at December 31, 2024) December 9, 2025	—	1,063
3.75 % Notes January 14, 2028	—	300
Loan at variable rates ( 5.329 % after floating-to-fixed rate swaps effective 2023) March 20, 2030, collateralized by plant assets (1)	—	1,090
3.25 % Notes January 15, 2032	—	400
Loan at variable rates ( 4.03 % after floating-to-fixed rate swap effective 2019) payable June 15, 2022 through November 19, 2034 (1)	—	90
Loan at variable rates ( 4.03 % after floating-to-fixed rate swap effective 2019) payable June 15, 2022 through November 19, 2034 (1)	—	90
Loan at variable rates ( 2.38 % after floating-to-fixed rate swap effective 2020) payable June 15, 2022 through November 19, 2034 (1)	—	90
2.90 % Loan payable June 15, 2022 through November 19, 2034 (1)	—	219
4.875 % Notes January 14, 2048	—	540
4.75 % Notes January 15, 2051	—	800
	—	4,682
	11,958	16,590
Current portion of long-term debt	( 549 )	( 1,859 )
Unamortized discount on long-term debt	( 26 )	( 78 )
Unamortized debt issuance costs	( 104 )	( 144 )
Total Other Sempra	11,279	14,509
Total Sempra	$ 28,979	$ 31,558

(1) Callable long-term debt not subject to make-whole provisions.

(2) At December 31, 2025, $ 7,744 of long-term debt, net of $ 49 of current portion of long-term debt, $ 89 of unamortized discount on long-term debt, and $ 43 of unamortized debt issuance costs is included in Liabilities Held for Sale on the Sempra Consolidated Balance Sheet.

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At December 31, 2025, scheduled maturities of long-term debt are as follows:

MATURITIES OF LONG-TERM DEBT (1)
(Dollars in millions)
	SDG&E	SoCalGas	Other Sempra (2)	Total Sempra (2)
2026	$ 750	$ 504	$ 550	$ 1,804
2027	—	700	750	1,450
2028	600	5	1,000	1,605
2029	—	—	500	500
2030	800	650	—	1,450
Thereafter	7,650	6,250	9,158	23,058
Total	$ 9,800	$ 8,109	$ 11,958	$ 29,867

(1) Excludes finance lease obligations, discounts, and debt issuance costs.

(2) Excludes $ 49 in 2026, $ 1,325 in 2027, $ 376 in 2028, $ 177 in 2029, $ 3,149 in 2030, and $ 2,849 thereafter within the disposal group that is classified as held for sale.

Various long-term obligations totaling $ 12.7 billion at Sempra at December 31, 2025 are unsecured. This includes unsecured long-term obligations totaling $ 709 million at SoCalGas and excludes $ 3.8 billion unsecured long-term obligations within the disposal group that is classified as held for sale.

Callable Long-Term Debt

At the option of Sempra, SDG&E and SoCalGas, certain debt at December 31, 2025 is callable subject to premiums:

CALLABLE LONG-TERM DEBT
(Dollars in millions)
	SDG&E	SoCalGas	Other Sempra (1)	Total Sempra (1)
Not subject to make-whole provisions	$ —	$ 4	$ 5,908	$ 5,912
Subject to make-whole provisions	9,800	8,100	6,050	23,950

(1) Excludes $ 3,610 not subject to make-whole provisions and $ 4,315 subject to make-whole provisions within the disposal group that is classified as held for sale.

First Mortgage Bonds

SDG&E and SoCalGas issue first mortgage bonds secured by liens on their respective utility plant assets. SDG&E and SoCalGas may issue additional first mortgage bonds if in compliance with the provisions of their bond agreements (indentures). These indentures require, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of additional first mortgage bonds of $ 9.2 billion at SDG&E and $ 1.3 billion at SoCalGas at December 31, 2025.

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.

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Other Long-Term Debt

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.

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 December 31, 2025 and 2024, $ 1.3 billion and $ 1.1 billion, respectively, of borrowings from external lenders were outstanding under the loan agreement, with a weighted-average interest rate of 6.06 % 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 December 31, 2025 and 2024, $ 3.2 billion and $ 1.1 billion, respectively, of borrowings were outstanding under the loan agreement, with an all-in weighted-average interest rate of 5.47 % and 5.33 %, respectively. At December 31, 2025, previous borrowings of $ 983 million have been repaid, as we discuss below, and cannot be reborrowed. Proceeds from the loan are being used to finance the cost of construction of the PA LNG Phase 1 project.

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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 on December 15, 2042. The net proceeds were used to repay borrowings and accrued interest under the existing Port Arthur LNG I term loan facility.

NOTE 8. INCOME TAXES

We provide our calculations of ETRs in the following table.

INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra:
Income tax expense	$ 701	$ 219	$ 490
Income before income taxes and equity earnings	$ 1,169	$ 2,110	$ 2,627
Equity earnings, before income tax (1)	620	603	633
Pretax income	$ 1,789	$ 2,713	$ 3,260
Effective income tax rate	39 %	8 %	15 %
SDG&E:
Income tax (benefit) expense	$ ( 128 )	$ 153	$ ( 26 )
Income before income taxes	$ 435	$ 1,044	$ 910
Effective income tax rate	( 29 ) %	15 %	( 3 ) %
SoCalGas:
Income tax (benefit) expense	$ ( 38 )	$ 31	$ ( 5 )
Income before income taxes	$ 828	$ 987	$ 807
Effective income tax rate	( 5 ) %	3 %	( 1 ) %

(1) We discuss how we recognize equity earnings in Note 5.

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 year ended December 31, 2025.

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We present in the table below reconciliations of the U.S. federal statutory income tax rate to our ETRs.

RECONCILIATION OF FEDERAL INCOME TAX RATE TO EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Years ended December 31,
	2025		2024		2023
Sempra:
U.S. federal statutory income tax rate	$ 376	21 %	$ 570	21 %	$ 684	21 %
State income taxes, net of federal income tax benefit (1)	204	11	23	1	6	—
Foreign tax effects:
Mexico:
Rate differential	40	2	32	1	50	2
Foreign exchange and inflation	246	14	( 368 )	( 14 )	290	9
Outside basis difference	142	8	12	1	—	—
Other	( 20 )	( 1 )	—	—	( 33 )	( 1 )
Tax credits:
Investment tax credits	( 100 )	( 6 )	( 17 )	( 1 )	( 144 )	( 4 )
Other	( 2 )	—	—	—	( 3 )	—
Change in valuation allowances	( 266 )	( 15 )	347	13	—	—
Nontaxable or nondeductible items	( 23 )	( 1 )	( 25 )	( 1 )	( 14 )	( 1 )
Changes in unrecognized tax benefits	3	—	2	—	( 35 )	( 1 )
Regulatory tax effects (2)	( 304 )	( 17 )	( 246 )	( 9 )	( 203 )	( 6 )
Noncontrolling interests	( 43 )	( 2 )	( 79 )	( 3 )	( 91 )	( 3 )
Other adjustments	( 15 )	( 1 )	( 32 )	( 1 )	( 17 )	( 1 )
SI Partners held for sale outside basis differences	463	26	—	—	—	—
Effective income tax rate	$ 701	39 %	$ 219	8 %	$ 490	15 %
SDG&E:
U.S. federal statutory income tax rate	$ 91	21 %	$ 219	21 %	$ 191	21 %
State income taxes, net of federal income tax benefit (3)	( 12 )	( 3 )	36	3	19	2
Tax credits:
Investment tax credits	( 100 )	( 23 )	( 17 )	( 1 )	( 144 )	( 16 )
Other	—	—	( 1 )	—	—	—
Nontaxable or nondeductible items	( 2 )	—	( 1 )	—	( 1 )	—
Changes in unrecognized tax benefits	( 1 )	—	—	—	—	—
Regulatory tax effects (2)	( 105 )	( 24 )	( 84 )	( 8 )	( 89 )	( 10 )
Other adjustments	1	—	1	—	( 2 )	—
Effective income tax rate	$ ( 128 )	( 29 ) %	$ 153	15 %	$ ( 26 )	( 3 ) %
SoCalGas:
U.S. federal statutory income tax rate	$ 174	21 %	$ 208	21 %	$ 169	21 %
State income taxes, net of federal income tax benefit (3)	( 11 )	( 2 )	( 14 )	( 1 )	( 23 )	( 3 )
Tax credits	( 3 )	—	( 3 )	—	( 2 )	—
Nontaxable or nondeductible items	2	—	2	—	2	—
Changes in unrecognized tax benefits	( 1 )	—	—	—	( 44 )	( 6 )
Regulatory tax effects (2)	( 199 )	( 24 )	( 162 )	( 17 )	( 114 )	( 14 )
Other adjustments	—	—	—	—	7	1
Effective income tax rate	$ ( 38 )	( 5 ) %	$ 31	3 %	$ ( 5 )	( 1 ) %

(1) State taxes in California and Louisiana made up the majority (greater than 50%) of the tax effect in this category.

(2) Includes federal impacts of flow-through rate-making treatment.

(3) State taxes in California made up substantially all the tax effect in this category.

In 2025, we recognized income tax expense of $ 693 million to adjust deferred income tax liabilities primarily related to outside basis differences in our investment in SI Partners for foreign subsidiaries that are no longer considered to be indefinitely reinvested and income tax expense of $ 14 million ($ 10 million after NCI) for a Mexican deferred income tax liability on our outside basis difference in Ecogas as a result of management’s decision to classify these assets as held for sale, which we discuss in Note 6.

Tab le of Cont ents

The table below presents the geographic location of pretax income.

PRETAX INCOME BY GEOGRAPHIC LOCATION
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra:
U.S.	$ 1,353	$ 2,354	$ 2,678
Foreign	436	359	582
Total (1)	$ 1,789	$ 2,713	$ 3,260

(1) See the Income Tax Expense (Benefit) and Effective Income Tax Rates table above for the calculation of pretax income.

The components of income tax expense are as follows.

INCOME TAX EXPENSE (BENEFIT)
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra:
Current:
U.S. federal	$ ( 18 )	$ 73	$ 102
U.S. state	38	( 4 )	3
Foreign	126	179	208
Total	146	248	313
Deferred:
U.S. federal	( 45 )	366	( 56 )
U.S. state	230	28	18
Foreign	383	( 422 )	225
Total (1)	568	( 28 )	187
Deferred investment tax credits (1)	( 13 )	( 1 )	( 10 )
Total income tax expense	$ 701	$ 219	$ 490
SDG&E:
Current:
U.S. federal	$ 4	$ ( 16 )	$ ( 156 )
U.S. state	13	—	( 5 )
Total	17	( 16 )	( 161 )
Deferred:
U.S. federal	( 114 )	129	111
U.S. state	( 19 )	41	35
Total	( 133 )	170	146
Deferred investment tax credits	( 12 )	( 1 )	( 11 )
Total income tax (benefit) expense	$ ( 128 )	$ 153	$ ( 26 )
SoCalGas:
Current:
U.S. federal	$ 18	$ 3	$ ( 6 )
U.S. state	51	—	( 11 )
Total	69	3	( 17 )
Deferred:
U.S. federal	( 40 )	45	22
U.S. state	( 66 )	( 16 )	( 11 )
Total	( 106 )	29	11
Deferred investment tax credits	( 1 )	( 1 )	1
Total income tax (benefit) expense	$ ( 38 )	$ 31	$ ( 5 )

(1) In 2025, 2024 and 2023, Deferred Income Taxes and Investment Tax Credits on the Sempra Consolidated Statements of Cash Flows also includes $ 22 , $ 9 and $ 72 , respectively, of income taxes included in equity earnings, which are recorded net of income tax under a tax sharing agreement with Oncor.

Tab le of Cont ents

The tables below present the components of deferred income taxes:

DEFERRED INCOME TAXES
(Dollars in millions)
	December 31,
	2025	2024
Sempra (1) :
Deferred income tax liabilities:
Differences in financial and tax bases of fixed assets, investments and other assets (2)	$ 7,691	$ 7,164
U.S. and foreign tax on repatriation of foreign earnings	—	79
Regulatory balancing accounts	637	850
Right-of-use assets – operating leases	357	325
Property taxes	—	74
Postretirement benefits	—	150
Other deferred income tax liabilities	446	94
Total deferred income tax liabilities	9,131	8,736
Deferred income tax assets:
Tax credits	1,564	1,485
Net operating losses	935	1,105
Compensation-related items	212	225
Operating lease liabilities	363	301
Other deferred income tax assets	173	219
Bad debt allowance	—	151
Accrued expenses not yet deductible	—	80
Deferred income tax assets before valuation allowances	3,247	3,566
Less: valuation allowances	233	503
Total deferred income tax assets	3,014	3,063
Net deferred income tax liability (3)	$ 6,117	$ 5,673

(1) At December 31, 2025, excludes $ 894 of net deferred income tax liability, comprised of $ 982 of deferred income tax liabilities and $ 88 of deferred income tax assets, that is included in Liabilities Held for Sale on the Sempra Consolidated Balance Sheet.

(2) In addition to the financial over tax basis differences in fixed assets, the amount also includes financial over tax basis differences in various interests in partnerships and certain subsidiaries.

(3) At December 31, 2025 and 2024, includes $ 10 and $ 172 , respectively, recorded as a noncurrent asset and $ 6,127 and $ 5,845 , respectively, recorded as a noncurrent liability on the Consolidated Balance Sheets.

Tab le of Cont ents

DEFERRED INCOME TAXES
(Dollars in millions)
	SDG&E		SoCalGas
	December 31,
	2025	2024	2025	2024
Deferred income tax liabilities:
Differences in financial and tax bases of utility plant and other assets	$ 2,971	$ 2,805	$ 2,902	$ 2,594
Regulatory balancing accounts	478	545	158	306
Right-of-use assets – operating leases	293	222	19	5
Property taxes	53	47	31	27
Postretirement benefits	—	—	173	124
Other deferred income tax liabilities	4	—	—	2
Total deferred income tax liabilities	3,799	3,619	3,283	3,058
Deferred income tax assets:
Tax credits	98	8	2	2
Compensation-related items	—	8	—	26
Operating lease liabilities	293	222	19	5
Bad debt allowance	—	29	54	72
Accrued expenses not yet deductible	—	10	53	54
Net operating losses	77	122	799	874
Other deferred income tax assets	45	9	85	20
Total deferred income tax assets	513	408	1,012	1,053
Net deferred income tax liability	$ 3,286	$ 3,211	$ 2,271	$ 2,005

The following table provides the valuation allowances that we recorded against a portion of our total deferred income tax assets shown above in the “Deferred Income Taxes – Sempra” table.

VALUATION ALLOWANCES BY JURISDICTION
(Dollars in millions)
	December 31,
	2025	2024
Sempra:
U.S. federal	$ 137	$ 406
U.S. state	96	47
Foreign (1)	—	50
	$ 233	$ 503

(1) At December 31, 2025, excludes $ 50 of valuation allowances that are included in Assets Held for Sale on the Sempra Consolidated Balance Sheet.

A valuation allowance is recorded when, based on more-likely-than-not criteria, negative evidence outweighs positive evidence with regard to our ability to realize a deferred income tax asset in the future. In the year ended December 31, 2025, we recognized an income tax benefit of $ 344 million from changes to a valuation allowance against certain tax credit carryforwards as a result of management’s decision to classify SI Partners as held for sale. In the years ended December 31, 2025 and 2024, we recognized income tax expense of $ 78 million and $ 330 million, respectively, from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the TCJA. For various U.S. state and foreign jurisdictions, the negative evidence outweighs the positive evidence primarily due to cumulative pretax losses resulting in deferred income tax assets that we currently do not believe will be realized on a more-likely-than-not basis.

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The following table presents the amount of income taxes paid (net of refunds received) disaggregated by jurisdiction for the years ended December 31:

INCOME TAXES PAID (NET OF REFUNDS RECEIVED)
(Dollars in millions)
	2025	2024	2023
Sempra:
U.S. federal	$ 62	$ 100	$ 3
U.S. state:
California	55	—	—
Texas	28	26	24
Other	2	2	2
Foreign:
Mexico	226	161	168
Other	3	—	—
Income tax payments, net	$ 376	$ 289	$ 197
SDG&E (1) :
U.S. federal	$ 9	$ ( 199 )	$ 40
U.S. state – California	14	( 26 )	36
Income tax payments (refunds), net	$ 23	$ ( 225 )	$ 76
SoCalGas (1) :
U.S. federal	$ 20	$ ( 11 )	$ 6
U.S. state – California	49	2	—
Income tax payments (refunds), net	$ 69	$ ( 9 )	$ 6

(1) SDG&E and SoCalGas are included in the consolidated income tax return of Sempra, and their respective income tax payments are computed as an amount equal to that which would result from each company having filed a separate return.

The following table summarizes our unused NOLs and tax credit carryforwards.

NET OPERATING LOSSES AND TAX CREDIT CARRYFORWARDS
(Dollars in millions)
	Unused amount at December 31, 2025	Year expiration begins
Sempra:
U.S. federal:
NOLs (1)	$ 3,169	2037
General business tax credits (1)	260	2043
Corporate alternative minimum tax credits (1)	630	Indefinite
Foreign tax credits (2)	704	2026
U.S. state:
NOLs (2)	5,762	2027
General business tax credits (1)	20	2027
Foreign (2)(3) :
NOLs	693	2026
Foreign tax credits	5	Indefinite
SDG&E:
U.S. federal (1) :
NOLs	$ 94	Indefinite
General business tax credits	92	2045
U.S. state NOLs (1)	818	2046
SoCalGas:
U.S. federal NOLs (1)	$ 2,489	Indefinite
U.S. state NOLs (1)	3,952	2045

(1) We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not-basis.

(2) We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as we discuss below.

(3) Deferred tax assets related to foreign NOLs and foreign tax credits are included within the disposal group that is classified as held for sale.

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On February 18, 2026, the IRS issued Notice 2026‑7, which provides additional guidance on the application of the Corporate Alternative Minimum Tax (CAMT), including the treatment of certain capitalized repairs and maintenance expenditures. We are currently evaluating the impact of this guidance. Based on our initial assessment, we expect it will result in a prospective reduction in our CAMT liability in periods when we are subject to CAMT. In addition, we expect to amend prior year tax returns to claim refunds for CAMT previously paid.

Following is a reconciliation of the changes in unrecognized income tax benefits and the potential effect on our ETR for the years ended December 31:

RECONCILIATION OF UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	2025	2024	2023
Sempra:
Balance at January 1	$ 548	$ 492	$ 278
Increase in prior period tax positions	19	40	308
Decrease in prior period tax positions	( 28 )	( 8 )	( 63 )
Decrease in current period tax positions	—	—	( 21 )
Settlements with tax authorities	( 19 )	( 15 )	( 16 )
Increase in current period tax positions	81	39	6
Balance at December 31 (1)	$ 601	$ 548	$ 492
Of December 31 balance, amounts related to tax positions that if recognized in future years would
decrease the effective tax rate	$ ( 500 )	$ ( 229 )	$ ( 224 )
increase the effective tax rate	—	1	1
SDG&E:
Balance at January 1	$ 14	$ 14	$ 14
Increase in prior period tax positions	—	—	2
Settlements with tax authorities	( 6 )	—	( 2 )
Balance at December 31	$ 8	$ 14	$ 14
Of December 31 balance, amounts related to tax positions that if recognized in future years would
decrease the effective tax rate	$ ( 8 )	$ ( 11 )	$ ( 11 )
increase the effective tax rate	—	1	1
SoCalGas:
Balance at January 1	$ 29	$ 29	$ 77
Increase in prior period tax positions	—	—	1
Decrease in prior period tax positions	—	—	( 47 )
Settlements with tax authorities	( 2 )	—	( 2 )
Balance at December 31	$ 27	$ 29	$ 29
Of December 31 balance, amounts related to tax positions that if recognized in future years would
decrease the effective tax rate	$ ( 27 )	$ ( 29 )	$ ( 29 )

(1) At December 31, 2025, includes $ 33 that is within the disposal group that is classified as held for sale.

The California Franchise Tax Board is examining Sempra’s California unitary group for tax years 2018 and 2019. The reconciliation above includes unrecognized tax benefits through 2025 related to this matter.

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 ETR.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. SDG&E and SoCalGas elected this change in tax accounting method in Sempra’s consolidated 2023 income tax return filing and recorded additional income tax benefits of $ 34 million and $ 97 million, respectively, in 2023. Additionally, SoCalGas updated its assessment of prior years’ unrecognized income tax benefits and recorded an income tax benefit of $ 43 million in 2023 for previously unrecognized income tax benefits pertaining to gas repairs expenditures. Sempra elected this change in tax accounting method in its consolidated 2023 income tax return filing.

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Amounts accrued for interest and penalties associated with unrecognized income tax benefits are included in Income Tax Expense on the Consolidated Statements of Operations. Sempra accrued $ 17 million and $ 15 million at December 31, 2025 and 2024, respectively, on the Consolidated Balance Sheets, and recorded $ 2 million in 2025, negligible amounts in 2024, and $ 2 million in 2023 on the Consolidated Statements of Operations for interest and penalties. SDG&E and SoCalGas each accrued negligible amounts for interest expense and penalties at December 31, 2025 and 2024 on their Balance Sheets, and recorded negligible amounts for interest expense and penalties on their Statements of Operations for all periods presented.

INCOME TAX AUDITS

Sempra is subject to U.S. federal income tax as well as income tax of multiple state and foreign jurisdictions. We remain subject to examination for U.S. federal tax years after 2021. We are subject to examination by major state tax jurisdictions for tax years after 2012. Certain major foreign income tax returns for tax years 2014 through the present are open to examination.

SDG&E and SoCalGas are subject to U.S. federal income tax and state income tax. They remain subject to examination for U.S. federal tax years after 2021 and state tax years after 2012.

In addition, Sempra has filed protests to contest proposed state audit adjustments for tax years 2009 through 2012. The pre-2013 tax years for our major state tax jurisdictions are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these tax years.

SI Partners has filed an administrative appeal to contest a tax assessment issued by the Servicio de Administración Tributaria for tax year 2016. In 2025, we increased unrecognized income tax benefits and will have the opportunity to contest any unresolved issues through the Mexican courts.

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NOTE 9. EMPLOYEE BENEFIT PLANS

For our employee benefit plans, we:

▪ recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the balance sheet;

▪ measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year; and

▪ recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity.

The detailed information presented below covers the employee benefit plans of primarily Sempra and its consolidated entities.

Sempra has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E and SoCalGas, which collectively cover all eligible employees. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology.

IEnova has an unfunded noncontributory defined benefit plan covering all employees that provides defined benefits to retirees based on date of hire, years of service and final average earnings.

Sempra also has PBOP plans, including separate plans for SDG&E and SoCalGas, which collectively cover all domestic and certain foreign employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. PBOP plans include medical benefits.

Pension and PBOP costs and obligations are dependent on assumptions used in calculating such amounts. We review these assumptions on an annual basis and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions.

DEDICATED ASSETS IN SUPPORT OF CERTAIN BENEFITS PLANS

In support of its Supplemental Executive Retirement Plan, Cash Balance Restoration Plan and Employee and Director Savings Plan, Sempra maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $ 605 million and $ 585 million at December 31, 2025 and 2024, respectively.

PENSION AND PBOP PLANS

Oncor

In both 2025 and 2024, we had $ 34 million in AOCI representing an actuarial loss related to Oncor’s pension plans.

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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Special Termination Benefits

In the second quarter of 2025, certain eligible employees retired under a Voluntary Retirement Enhancement Program and received an additional postretirement health benefit in the form of a $ 100,000 Health Reimbursement Account. Employees eligible to participate in the Voluntary Retirement Enhancement Program 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 year ended December 31, 2025.

Benefit Obligations and Assets

The following three tables provide a reconciliation of the changes in the plans’ benefit obligations and the fair value of assets during 2025 and 2024, and a statement of the funded status at December 31, 2025 and 2024.

BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
	Pension (1)		PBOP
	2025	2024	2025	2024
Sempra (2) :
CHANGE IN BENEFIT OBLIGATION
Obligation at January 1	$ 3,139	$ 3,107	$ 687	$ 693
Service cost	127	132	13	15
Interest cost	176	166	39	36
Contributions from plan participants	—	—	28	23
Actuarial loss (gain)	80	( 100 )	35	( 11 )
Plan amendments	—	2	—	—
Benefit payments	( 85 )	( 81 )	( 80 )	( 69 )
Special termination benefits	—	—	40	—
Settlements	( 290 )	( 87 )	—	—
Reclassification to liabilities held for sale	( 24 )	—	—	—
Obligation at December 31	3,123	3,139	762	687
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	2,935	2,664	1,185	1,169
Actual return on plan assets	272	196	125	57
Employer contributions	278	243	15	5
Contributions from plan participants	—	—	28	23
Benefit payments	( 85 )	( 81 )	( 80 )	( 69 )
Settlements	( 290 )	( 87 )	—	—
Fair value of plan assets at December 31	3,110	2,935	1,273	1,185
Funded status at December 31	$ ( 13 )	$ ( 204 )	$ 511	$ 498
Net recorded (liability) asset at December 31	$ ( 13 )	$ ( 204 )	$ 511	$ 498

(1) The accumulated benefit obligation was $ 2,868 and $ 2,900 at December 31, 2025 and 2024, respectively.

(2) Includes activities in 2025 within the disposal group that is classified as held for sale.

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BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
	Pension (1)		PBOP
	2025	2024	2025	2024
SDG&E:
CHANGE IN BENEFIT OBLIGATION
Obligation at January 1	$ 822	$ 807	$ 134	$ 140
Service cost	38	39	2	3
Interest cost	46	43	8	7
Contributions from plan participants	—	—	10	8
Actuarial loss (gain)	39	( 28 )	5	( 6 )
Benefit payments	( 18 )	( 16 )	( 23 )	( 18 )
Special termination benefits	—	—	17	—
Settlements	( 86 )	( 23 )	—	—
Transfer of liability from other plans	( 13 )	—	—	—
Obligation at December 31	828	822	153	134
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	787	726	145	150
Actual return on plan assets	73	63	13	5
Employer contributions	51	37	13	—
Contributions from plan participants	—	—	10	8
Benefit payments	( 18 )	( 16 )	( 23 )	( 18 )
Settlements	( 86 )	( 23 )	—	—
Fair value of plan assets at December 31	807	787	158	145
Funded status at December 31	$ ( 21 )	$ ( 35 )	$ 5	$ 11
Net recorded (liability) asset at December 31	$ ( 21 )	$ ( 35 )	$ 5	$ 11

(1) The accumulated benefit obligation was $ 770 and $ 781 at December 31, 2025 and 2024, respectively.

BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
	Pension (1)		PBOP
(Dollars in millions)	2025	2024	2025	2024
SoCalGas:
CHANGE IN BENEFIT OBLIGATION
Obligation at January 1	$ 1,999	$ 1,977	$ 522	$ 521
Service cost	75	79	10	11
Interest cost	112	105	30	27
Contributions from plan participants	—	—	17	14
Actuarial loss (gain)	29	( 70 )	28	( 4 )
Plan amendments	—	2	—	—
Benefit payments	( 59 )	( 56 )	( 53 )	( 47 )
Special termination benefits	—	—	23	—
Settlements	( 178 )	( 38 )	—	—
Obligation at December 31	1,978	1,999	577	522
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1	1,937	1,744	1,008	990
Actual return on plan assets	179	115	107	50
Employer contributions	195	172	1	1
Contributions from plan participants	—	—	17	14
Benefit payments	( 59 )	( 56 )	( 53 )	( 47 )
Settlements	( 178 )	( 38 )	—	—
Fair value of plan assets at December 31	2,074	1,937	1,080	1,008
Funded status at December 31	$ 96	$ ( 62 )	$ 503	$ 486
Net recorded asset (liability) at December 31	$ 96	$ ( 62 )	$ 503	$ 486

(1) The accumulated benefit obligation was $ 1,801 and $ 1,824 at December 31, 2025 and 2024, respectively.

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Actuarial losses (gains) fluctuate based on changes in assumptions that we describe below in “Assumptions for Pension and PBOP Plans” and updates to census data.

Pension Plans

▪ In 2025, actuarial losses were driven by increases in salary rates at SDG&E and SoCalGas and changes in retirement rates at SoCalGas. These losses were partially offset by changes in lump-sum conversion rates at SoCalGas.

▪ In 2024, actuarial gains were driven by an increase in discount rates at SoCalGas and SDG&E, offset by updated census data at SoCalGas and SDG&E.

PBOP Plans

▪ In 2025, actuarial losses were driven by the assumed future trend of increasing healthcare costs at SoCalGas, partially offset by updated census data at SoCalGas.

▪ In 2024, actuarial gains were driven by an increase in discount rates at SoCalGas, partially offset by an increase in the 2025 expected healthcare costs at SoCalGas.

Net Assets and Liabilities

The assets and liabilities of the pension and PBOP plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and PBOP costs over a period of years. Our funded pension and PBOP plans use the asset smoothing method, except for those at SDG&E. This method develops an asset value that recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used in conjunction with an expected long-term rate of return to determine the expected return-on-plan-assets component of net periodic benefit cost. SDG&E does not use the asset smoothing method but rather recognizes realized and unrealized investment gains and losses during the current year.

The 10% corridor accounting method is used at Sempra, SDG&E and SoCalGas. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants (or, for plans where participants are substantially inactive employees, the average remaining lifetime of all participants or the period for which benefits will be paid, whichever is shorter). The asset smoothing and 10% corridor accounting methods help mitigate volatility of net periodic benefit costs from year to year.

Defined benefit pension and PBOP plans with an aggregated overfunded status are recognized as an asset and with an aggregated underfunded status are recognized as a liability; unrecognized changes in these assets and/or liabilities are normally recorded in AOCI on the balance sheet. SDG&E and SoCalGas record regulatory assets and liabilities that offset the funded pension and PBOP plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on decisions by regulatory agencies.

SDG&E and SoCalGas record annual pension and PBOP net periodic benefit costs equal to the contributions to their qualified plans as authorized by the CPUC. The annual contributions to the pension plans are the greater of:

▪ a minimum required funding amount as required by the IRS;

▪ the amount required to maintain an 85% Adjusted Funding Target Attainment Percentage as defined by the Pension Protection Act of 2006, as amended; or

▪ beginning January 1, 2024 and for the duration of the 2024 GRC cycle, a fixed amount equal to the estimated annual service cost as defined by U.S. GAAP plus one year of a seven-year amortization of the unfunded projected benefit obligation of the pension plan as of January 1, 2024, and limited to an annual amount that keeps the fair value of the pension plan assets from exceeding 110% of the pension benefit obligation of the plan.

The annual contributions to PBOP plans are equal to the lesser of the maximum tax-deductible amount or the net periodic benefit cost calculated in accordance with U.S. GAAP for pension and PBOP plans but not less than benefits paid directly by the employer (such as benefits paid to key employees). Any differences between booked net periodic benefit cost and amounts contributed to the pension and PBOP plans for SDG&E and SoCalGas are disclosed as regulatory adjustments in accordance with U.S. GAAP for rate-regulated entities.

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The net (liability) asset is included in the following categories on the Consolidated Balance Sheets.

PENSION AND PBOP OBLIGATIONS, NET OF PLAN ASSETS
(Dollars in millions)
	Pension		PBOP
	December 31,
	2025	2024	2025	2024
Sempra:
Noncurrent assets	$ 124	$ 6	$ 520	$ 507
Current liabilities	( 21 )	( 50 )	( 1 )	( 1 )
Noncurrent liabilities	( 116 )	( 160 )	( 8 )	( 8 )
Net recorded (liability) asset (1)	$ ( 13 )	$ ( 204 )	$ 511	$ 498
SDG&E:
Noncurrent assets	$ —	$ —	$ 5	$ 11
Current liabilities	( 2 )	( 7 )	—	—
Noncurrent liabilities	( 19 )	( 28 )	—	—
Net recorded (liability) asset	$ ( 21 )	$ ( 35 )	$ 5	$ 11
SoCalGas:
Noncurrent assets	$ 116	$ —	$ 503	$ 486
Current liabilities	( 2 )	( 17 )	—	—
Noncurrent liabilities	( 18 )	( 45 )	—	—
Net recorded asset (liability)	$ 96	$ ( 62 )	$ 503	$ 486

(1) At December 31, 2025, excludes pension obligation, net of plan assets, of $ 24 that is included in Liabilities Held for Sale on the Sempra Consolidated Balance Sheet.

Amounts recorded in AOCI, net of income tax effects and amounts recorded as regulatory assets, are as follows.

AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Pension		PBOP
	December 31,
	2025	2024	2025	2024
Sempra:
Net actuarial (loss) gain	$ ( 106 )	$ ( 120 )	$ 13	$ 14
Prior service cost	( 5 )	( 9 )	—	—
Total	$ ( 111 )	$ ( 129 )	$ 13	$ 14
SDG&E:
Net actuarial loss	$ ( 6 )	$ ( 12 )
Total	$ ( 6 )	$ ( 12 )
SoCalGas:
Net actuarial loss	$ ( 6 )	$ ( 14 )
Prior service cost	( 2 )	( 3 )
Total	$ ( 8 )	$ ( 17 )

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Sempra, SDG&E and SoCalGas each have a funded pension plan. The following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets.

OBLIGATIONS OF FUNDED PENSION PLANS
(Dollars in millions)
	December 31,
	2025	2024
Sempra:
Projected benefit obligation	$ 811	$ 2,752
Accumulated benefit obligation	755	2,542
Fair value of plan assets	807	2,724
SDG&E:
Projected benefit obligation	$ 811	$ 793
Accumulated benefit obligation	755	755
Fair value of plan assets	807	787
SoCalGas:
Projected benefit obligation	$ —	$ 1,959
Accumulated benefit obligation	—	1,787
Fair value of plan assets	—	1,937

We also have unfunded pension plans at Sempra, SDG&E, SoCalGas and IEnova. The following table shows the obligations of unfunded pension plans.

OBLIGATIONS OF UNFUNDED PENSION PLANS
(Dollars in millions)
	December 31,
	2025	2024
Sempra:
Projected benefit obligation (1)	$ 134	$ 183
Accumulated benefit obligation	114	159
SDG&E:
Projected benefit obligation	$ 17	$ 29
Accumulated benefit obligation	15	26
SoCalGas:
Projected benefit obligation	$ 20	$ 40
Accumulated benefit obligation	17	37

(1) At December 31, 2025, excludes $ 24 of projected benefit obligation that is included in Liabilities Held for Sale on the Sempra Consolidated Balance Sheet.

Sempra, SDG&E and SoCalGas each have a funded PBOP plan. At December 31, 2025, Sempra’s, SDG&E’s and SoCalGas’ plan assets were each in excess of their respective obligations for funded PBOP plans with accumulated postretirement benefit obligations.

We also have unfunded PBOP plans at Sempra. The following table shows the obligations of unfunded PBOP plans.

OBLIGATIONS OF UNFUNDED PBOP PLANS
(Dollars in millions)
	December 31,
	2025	2024
Sempra:
Accumulated postretirement benefit obligation	$ 9	$ 9

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Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (which, other than the service cost component, are included in Other Income, Net) and pretax amounts recognized in OCI.

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
(Dollars in millions)
	Pension			PBOP
	Years ended December 31,
	2025	2024	2023	2025	2024	2023
Sempra:
NET PERIODIC BENEFIT COST
Service cost	$ 127	$ 132	$ 109	$ 13	$ 15	$ 13
Interest cost	176	166	157	39	36	37
Expected return on plan assets	( 175 )	( 178 )	( 169 )	( 66 )	( 70 )	( 69 )
Amortization of:
Prior service cost (credit)	4	5	5	( 3 )	( 2 )	( 2 )
Actuarial loss (gain)	12	14	10	( 12 )	( 17 )	( 23 )
Settlement charges	26	9	—	—	—	—
Special termination benefits	—	—	—	40	—	—
Net periodic benefit cost (credit)	170	148	112	11	( 38 )	( 44 )
Regulatory adjustment	97	100	117	4	38	43
Total expense (income) recognized	267	248	229	15	—	( 1 )
CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI
Net loss (gain)	6	( 2 )	42	( 1 )	( 1 )	( 2 )
Prior service cost	—	3	4	—	—	—
Amortization of actuarial (loss) gain	( 7 )	( 7 )	( 5 )	1	1	2
Amortization of prior service cost	( 2 )	( 3 )	( 2 )	—	—	—
Settlements	( 16 )	( 9 )	—	—	—	—
Total recognized in OCI	( 19 )	( 18 )	39	—	—	—
Total recognized in net periodic benefit cost and OCI	$ 248	$ 230	$ 268	$ 15	$ —	$ ( 1 )

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NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
(Dollars in millions)
	Pension			PBOP
	Years ended December 31,
	2025	2024	2023	2025	2024	2023
SDG&E:
NET PERIODIC BENEFIT COST
Service cost	$ 38	$ 39	$ 32	$ 2	$ 3	$ 3
Interest cost	46	43	40	8	7	8
Expected return on plan assets	( 46 )	( 45 )	( 39 )	( 7 )	( 9 )	( 8 )
Amortization of:
Prior service cost	—	1	1	—	—	—
Actuarial loss (gain)	4	8	4	( 2 )	( 1 )	( 2 )
Settlement charges	11	—	—	—	—	—
Special termination benefits	—	—	—	17	—	—
Net periodic benefit cost	53	46	38	18	—	1
Regulatory adjustment	( 2 )	( 8 )	15	( 2 )	—	—
Total expense recognized	51	38	53	$ 16	$ —	$ 1
CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI
Net loss	2	4	3
Transfer of actuarial gain	( 7 )	—	—
Amortization of actuarial loss	( 1 )	( 1 )	—
Amortization of prior service cost	—	—	( 1 )
Total recognized in OCI	( 6 )	3	2
Total recognized in net periodic benefit cost and OCI	$ 45	$ 41	$ 55

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
(Dollars in millions)
	Pension			PBOP
	Years ended December 31,
	2025	2024	2023	2025	2024	2023
SoCalGas:
NET PERIODIC BENEFIT COST
Service cost	$ 75	$ 79	$ 65	$ 10	$ 11	$ 9
Interest cost	112	105	101	30	27	28
Expected return on plan assets	( 118 )	( 121 )	( 119 )	( 57 )	( 59 )	( 59 )
Amortization of:
Prior service cost (credit)	4	4	4	( 3 )	( 3 )	( 2 )
Actuarial loss (gain)	2	1	1	( 9 )	( 14 )	( 19 )
Settlement charges	10	—	—	—	—	—
Special termination benefits	—	—	—	23	—	—
Net periodic benefit cost (credit)	85	68	52	( 6 )	( 38 )	( 43 )
Regulatory adjustment	99	108	102	6	38	43
Total expense recognized	184	176	154	$ —	$ —	$ —
CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI
Net loss	2	4	2
Prior service cost	—	2	—
Amortization of actuarial loss	( 1 )	( 1 )	( 1 )
Amortization of prior service cost	( 1 )	( 1 )	( 1 )
Settlements	( 10 )	—	—
Total recognized in OCI	( 10 )	4	—
Total recognized in net periodic benefit cost and OCI	$ 174	$ 180	$ 154

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Assumptions for Pension and PBOP Plans

Benefit Obligation and Net Periodic Benefit Cost

Except for the IEnova plans, which are included in the disposal group that is classified as held for sale, we develop the discount rate assumptions using a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high-quality corporate bonds that generate sufficient cash flows to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of corporate bonds with a Bloomberg Composite of AA or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plans’ projected benefit payments discounted at this rate with the market value of the bonds selected.

We develop the discount rate assumptions for the plans at IEnova by constructing a synthetic government zero coupon bond yield curve from the available market data, based on duration matching, and we add a risk spread to allow for the yields of high-quality corporate bonds. Such method is required when there is no deep market for high quality corporate bonds.

Expected return on plan assets is based on the weighted average of the plans’ target investment allocation as of the measurement date and the expected returns for those asset types.

Interest crediting rate is based on an average 30-year Treasury bond from the month of November of the preceding year.

We amortize prior service cost using straight line amortization over average future service (or average expected lifetime for plans where participants are substantially inactive employees), which is an alternative method allowed under U.S. GAAP.

The significant assumptions affecting projected benefit obligation and net periodic benefit cost are as follows:

WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE PROJECTED BENEFIT OBLIGATION	Pension		PBOP
	December 31,
	2025	2024	2025	2024
Sempra:
Discount rate	5.72 %	5.74 %	5.73 %	5.75 %
Interest crediting rate (1)(2)	4.70	4.54	4.70	4.54
Rate of compensation increase	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00
SDG&E:
Discount rate	5.74 %	5.75 %	5.70 %	5.75 %
Interest crediting rate (1)(2)	4.70	4.54	4.70	4.54
Rate of compensation increase	4.50 - 10.00	3.50 - 10.00	4.50 - 10.00	3.50 - 10.00
SoCalGas:
Discount rate	5.70 %	5.70 %	5.75 %	5.75 %
Interest crediting rate (1)(2)	4.70	4.54	4.70	4.54
Rate of compensation increase	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00

(1) Interest crediting rate for pension benefits applies only to funded cash balance plans.

(2) Interest crediting rate for PBOP applies only to interest bearing health retirement accounts at SDG&E and SoCalGas.

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WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST
	Pension			PBOP
	Years ended December 31,
	2025	2024	2023	2025	2024	2023
Sempra:
Discount rate	5.74 %	5.31 %	5.63 %	5.75 %	5.34 %	5.65 %
Expected return on plan assets	6.40	6.56	6.48	5.90	5.90	5.51
Interest crediting rate (1)(2)	4.54	4.66	3.99	4.54	4.66	3.99
Rate of compensation increase	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00
SDG&E:
Discount rate	5.75 %	5.30 %	5.60 %	5.75 %	5.30 %	5.65 %
Expected return on plan assets	6.25	6.25	6.00	5.86	5.88	5.52
Interest crediting rate (1)(2)	4.54	4.66	3.99	4.54	4.66	3.99
Rate of compensation increase	3.50 - 10.00	3.50 - 10.00	3.50 - 10.00	3.50 - 10.00	3.50 - 10.00	3.50 - 10.00
SoCalGas:
Discount rate	5.70 %	5.25 %	5.60 %	5.75 %	5.35 %	5.65 %
Expected return on plan assets	6.50	6.75	6.75	5.87	5.86	5.47
Interest crediting rate (1)(2)	4.54	4.66	3.99	4.54	4.66	3.99
Rate of compensation increase	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00	2.70 - 10.00

(1) Interest crediting rate for pension benefits applies only to funded cash balance plans.

(2) Interest crediting rate for PBOP applies only to interest bearing health retirement accounts at SDG&E and SoCalGas.

Health Care Cost Trend Rates

Assumed health care cost trend rates have a significant effect on the amounts that Sempra, SDG&E and SoCalGas report for the health care plan costs. Following are the health care cost trend rates applicable to our PBOP plans:

ASSUMED HEALTH CARE COST TREND RATES
	PBOP
	Pre-65 retirees			Retirees aged 65 years and older
	Years ended December 31,
	2025	2024	2023	2025	2024	2023
Health care cost trend rate assumed for next year	6.75 %	6.50 %	6.00 %	8.50 %	4.50 %	4.50 %
Rate to which the cost trend rate is assumed to decline (the ultimate trend)	4.75 %	4.75 %	4.75 %	4.50 %	4.50 %	4.50 %
Year the rate reaches the ultimate trend	2032	2030	2028	2032	2022	2022

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Plan Assets

Investment Strategy for Sempra’s Pension Master Trust

Sempra’s pension master trust holds the investments for our pension plans and a portion of the investments for our PBOP plans. We maintain additional trusts, as we discuss below, for certain of SDG&E’s and SoCalGas’ PBOP plans. Other than through indexing and certain collective investment strategies, the trusts do not invest in securities of Sempra.

The current asset allocation objective for the pension master trust is to protect the funded status of the plans while generating sufficient returns to cover future benefit payments and accruals. A portion of the pension master trust is invested in accordance with plan specific de-risking glidepaths designed to reduce the assets’ exposure to risk as the plans become better funded. We assess the portfolio performance by comparing actual returns with relevant benchmarks. The target asset allocations for Sempra’s pension plans are between return-seeking assets (i.e., generally, equity securities, diversified real assets, high-yield fixed income securities and other instruments with a similar risk profile) and risk-mitigating assets (i.e., generally, government and corporate fixed income securities) as follows:

TARGET ASSET ALLOCATIONS FOR PENSION PLANS
(Dollars in millions)
	Sempra	SDG&E	SoCalGas
Return-seeking assets	35 %	40 %	35 %
Risk-mitigating assets	65 %	60 %	65 %

We maintain asset allocations at strategic levels within reasonable bands of variance. The asset allocations are reviewed by our Plan Funding Committee and our Pension and Benefits Investment Committee (the Committees) on a regular basis to help ensure that plan assets are positioned to meet plan obligations. When evaluating strategic asset allocations, the Committees consider many variables, including:

▪ long-term cost

▪ variability and level of contributions

▪ funded status

▪ a range of expected outcomes over varying confidence levels

In accordance with the Sempra pension investment guidelines, derivative financial instruments may be used by the pension master trust’s equity and fixed income portfolio investment managers to equitize cash, hedge certain exposures, and as substitutes for certain types of fixed income securities.

Rate of Return Assumption

The expected return on plan assets in our pension and PBOP plans is based on the weighted average of the plans’ target investment allocations to specific asset classes as of the measurement date. We expect a return of between 4 % and 12 % on return-seeking assets and between 3 % and 6 % for risk-mitigating assets. Certain trusts that hold assets for SDG&E’s and SoCalGas’ PBOP plans are subject to taxation, which impacts the expected after-tax return on plan assets.

Concentration of Risk

Plan assets are diversified across global equity and bond markets, and concentration of risk in any one economic, industry, maturity or geographic sector is limited.

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Investment Strategy for Sempra’s, SDG&E’s and SoCalGas’ PBOP Plans

Sempra’s, SDG&E’s and SoCalGas’ PBOP plans are funded by cash contributions from Sempra, SDG&E and SoCalGas, respectively, and their current retirees. The assets of these plans are placed into the pension master trust and other Voluntary Employee Beneficiary Association trusts. Specific target asset allocations are periodically reviewed to help ensure that plan assets are positioned to meet plan obligations. The target asset allocations for the PBOP plans are between return-seeking assets and risk-mitigating assets as follows:

TARGET ASSET ALLOCATIONS FOR PBOP PLANS
(Dollars in millions)
	Sempra	SDG&E and SoCalGas
	Assets held in pension master trust	Assets held in pension master trust	Assets held in Voluntary Employee Beneficiary Association trusts
Return-seeking assets	45 %	45 %	30 %
Risk-mitigating assets	55 %	55 %	70 %

Fair Value of Pension and PBOP Plan Assets

We classify the investments in Sempra’s pension master trust and the trusts for SDG&E’s and SoCalGas’ PBOP plans based on the fair value hierarchy, except for certain investments measured using NAV as a practical expedient for fair value.

The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and PBOP plan trusts.

Equity Securities – Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.

Registered Investment Companies – Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy. Other investments are valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks.

Fixed Income Securities – Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information.

Common/Collective Trusts – Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets.

Derivative Financial Instruments – Futures contracts that are publicly traded in active markets are valued at closing prices as of the last business day of the year. Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index futures contracts are valued at the last sales price quoted on the exchange on which they primarily trade.

While management believes the valuation methods described above are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

We provide more discussion of fair value measurements in Notes 1 and 11. The following tables set forth by level within the fair value hierarchy a summary of the investments in our pension and PBOP plan trusts measured at fair value on a recurring basis.

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The fair values by asset category are as follows:

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
(Dollars in millions)
	Fair value at December 31, 2025
	Level 1	Level 2	Total
SDG&E:
Cash and cash equivalents	$ 2	$ —	$ 2
Equity securities:
Domestic	10	—	10
International	6	—	6
Registered investment companies – Domestic	38	52	90
Fixed income securities:
Domestic government and government agencies	88	12	100
International government bonds	—	11	11
Domestic corporate bonds	—	256	256
International corporate bonds	—	26	26
Derivative financial instruments	4	—	4
Total investment assets in the fair value hierarchy	148	357	505
Accounts receivable/payable, net			( 3 )
Investments measured at NAV – Common/collective trusts			305
Total SDG&E investment assets			807
SoCalGas:
Cash and cash equivalents	6	—	6
Equity securities:
Domestic	23	—	23
International	13	—	13
Registered investment companies – Domestic	85	118	203
Fixed income securities:
Domestic government and government agencies	486	26	512
International government bonds	—	25	25
Domestic corporate bonds	—	579	579
International corporate bonds	—	59	59
Derivative financial instruments	( 3 )	1	( 2 )
Total investment assets in the fair value hierarchy	610	808	1,418
Accounts receivable/payable, net			6
Investments measured at NAV – Common/collective trusts			650
Total SoCalGas investment assets			2,074
Other Sempra:
Equity securities:
Domestic	3	—	3
International	1	—	1
Registered investment companies:
Domestic	10	13	23
International	1	—	1
Fixed income securities:
Domestic government and government agencies	45	3	48
International government bonds	—	3	3
Domestic corporate bonds	—	65	65
International corporate bonds	—	6	6
Derivative financial instruments	1	—	1
Total investment assets in the fair value hierarchy	61	90	151
Investments measured at NAV – Common/collective trusts			78
Total Other Sempra investment assets			229
Total Sempra investment assets in the fair value hierarchy	$ 819	$ 1,255
Total Sempra investment assets			$ 3,110

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FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
(Dollars in millions)
	Fair value at December 31, 2024
	Level 1	Level 2	Total
SDG&E:
Cash and cash equivalents	$ 2	$ —	$ 2
Equity securities:
Domestic	9	—	9
International	5	—	5
Registered investment companies – Domestic	48	—	48
Fixed income securities:
Domestic government and government agencies	227	5	232
International government bonds	—	3	3
Domestic corporate bonds	—	65	65
International corporate bonds	—	8	8
Derivative financial instruments	6	—	6
Total investment assets in the fair value hierarchy	297	81	378
Accounts receivable/payable, net			3
Investments measured at NAV – Common/collective trusts			406
Total SDG&E investment assets			787
SoCalGas:
Cash and cash equivalents	8	—	8
Equity securities:
Domestic	27	—	27
International	14	—	14
Registered investment companies – Domestic	149	—	149
Fixed income securities:
Domestic government and government agencies	270	17	287
International government bonds	—	9	9
Domestic corporate bonds	—	201	201
International corporate bonds	—	26	26
Derivative financial instruments	( 4 )	1	( 3 )
Total investment assets in the fair value hierarchy	464	254	718
Accounts receivable/payable, net			22
Investments measured at NAV – Common/collective trusts			1,197
Total SoCalGas investment assets			1,937
Other Sempra:
Equity securities:
Domestic	2	—	2
International	1	—	1
Registered investment companies – Domestic	10	—	10
Fixed income securities:
Domestic government and government agencies	77	3	80
International government bonds	—	1	1
Domestic corporate bonds	—	14	14
International corporate bonds	—	2	2
Derivative financial instruments	1	—	1
Total investment assets in the fair value hierarchy	91	20	111
Accounts receivable/payable, net			1
Investments measured at NAV – Common/collective trusts			99
Total Other Sempra investment assets			211
Total Sempra investment assets in the fair value hierarchy	$ 852	$ 355
Total Sempra investment assets			$ 2,935

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The fair values by asset category of the PBOP plan assets held in the pension master trust and in the additional trusts for SDG&E and SoCalGas are as follows:

FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PBOP PLANS
(Dollars in millions)
	Fair value at December 31, 2025
	Level 1	Level 2	Total
SDG&E:
Equity securities:
Domestic	$ 1	$ —	$ 1
International	1	—	1
Registered investment companies:
Domestic	77	6	83
International	9	—	9
Fixed income securities:
Domestic government and government agencies	2	1	3
International government bonds	—	1	1
Domestic corporate bonds	—	27	27
International corporate bonds	—	3	3
Total investment assets in the fair value hierarchy	90	38	128
Investments measured at NAV – Common/collective trusts			30
Total SDG&E investment assets			158
SoCalGas:
Cash and cash equivalents	2	—	2
Equity securities:
Domestic	7	—	7
International	4	—	4
Registered investment companies – Domestic	90	170	260
Fixed income securities:
Domestic government and government agencies	66	17	83
International government bonds	—	15	15
Domestic corporate bonds	—	322	322
International corporate bonds	—	31	31
Total investment assets in the fair value hierarchy	169	555	724
Accounts receivable/payable, net			3
Investments measured at NAV – Common/collective trusts			353
Total SoCalGas investment assets			1,080
Other Sempra:
Equity securities – Domestic	1	—	1
Registered investment companies – Domestic	2	2	4
Fixed income securities:
Domestic government and government agencies	1	1	2
Domestic corporate bonds	—	12	12
International corporate bonds	—	1	1
Total investment assets in the fair value hierarchy	4	16	20
Accounts receivable/payable, net			1
Investments measured at NAV – Common/collective trusts			14
Total Other Sempra investment assets			35
Total Sempra investment assets in the fair value hierarchy	$ 263	$ 609
Total Sempra investment assets			$ 1,273

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FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PBOP PLANS
(Dollars in millions)
	Fair value at December 31, 2024
	Level 1	Level 2	Total
SDG&E:
Cash and cash equivalents	$ 1	$ —	$ 1
Equity Securities – Domestic	1	—	1
Registered investment companies:
Domestic	74	—	74
International	8	—	8
Fixed income securities:
Domestic government and government agencies	8	—	8
Domestic corporate bonds	—	5	5
International corporate bonds	—	1	1
Derivative financial instruments	( 1 )	—	( 1 )
Total investment assets in the fair value hierarchy	91	6	97
Accounts receivable/payable, net			1
Investments measured at NAV:
Common/collective trusts			21
Other			26
Total SDG&E investment assets			145
SoCalGas:
Cash and cash equivalents	2	—	2
Equity securities:
Domestic	5	—	5
International	2	—	2
Registered investment companies – Domestic	87	103	190
Fixed income securities:
Domestic government and government agencies	74	14	88
International government bonds	—	10	10
Domestic corporate bonds	—	295	295
International corporate bonds	—	45	45
Derivative financial instruments	1	—	1
Total investment assets in the fair value hierarchy	171	467	638
Accounts receivable/payable, net			9
Investments measured at NAV – Common/collective trusts			361
Total SoCalGas investment assets			1,008
Other Sempra:
Equity securities – International	1	—	1
Registered investment companies – Domestic	4	—	4
Fixed income securities:
Domestic government and government agencies	—	1	1
Domestic corporate bonds	—	4	4
Total investment assets in the fair value hierarchy	5	5	10
Investments measured at NAV – Common/collective trusts			22
Total Other Sempra investment assets			32
Total Sempra investment assets in the fair value hierarchy	$ 267	$ 478
Total Sempra investment assets			$ 1,185

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Future Payments

We expect to contribute the following amounts to our pension and PBOP plans in 2026:

EXPECTED CONTRIBUTIONS
(Dollars in millions)
	Sempra (1)	SDG&E	SoCalGas
Pension plans	$ 231	$ 49	$ 151
PBOP plans	9	7	1

(1) Excludes $ 2 in expected contributions to the pension plan that is related to the disposal group that is classified as held for sale.

The following table shows the total benefits we expect to pay for the next 10 years to current employees and retirees from the plans or from company assets.

EXPECTED BENEFIT PAYMENTS
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
	Pension (1)	PBOP	Pension	PBOP	Pension	PBOP
2026	$ 253	$ 55	$ 66	$ 13	$ 149	$ 39
2027	273	56	65	12	148	38
2028	246	52	65	12	147	38
2029	238	52	65	12	146	38
2030	238	52	65	11	147	39
2031-2035	1,280	263	347	56	799	196

(1) Excludes $ 2 in each of 2026 through 2029, $ 3 in 2030 and $ 20 between 2031 and 2035 that is related to the disposal group that is classified as held for sale.

SAVINGS PLANS

Sempra, SDG&E and SoCalGas offer trusteed savings plans qualified under section 401(k) of the Internal Revenue Code of 1986 to all employees. Employee participation, employee contributions and employer matching contributions are subject to the provisions of the respective plans, and for employee contributions, limits imposed by the respective governmental authorities.

Employer contributions to the savings plans were as follows:

EMPLOYER CONTRIBUTIONS TO SAVINGS PLANS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra	$ 65	$ 65	$ 59
SDG&E	22	22	20
SoCalGas	33	33	32

The market value of Sempra common stock held by the savings plans was $ 1.0 billion and $ 1.2 billion at December 31, 2025 and 2024, respectively.

NOTE 10. 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.

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In all other cases, we record derivatives at fair value on the Consolidated Balance Sheets. We may have derivatives that are (1) cash flow hedges, (2) fair value hedges, or (3) undesignated. Depending on the applicability of hedge accounting and the requirement to pass impacts through to customers for SDG&E and SoCalGas and other operations subject to regulatory accounting, 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 Consolidated Statements of Cash Flows.

HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk 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 both 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 and regulatory requirements. SDG&E’s risk management and transacting activity plans for electricity derivatives are also required to be filed with, and have been approved by, the CPUC. SoCalGas is also subject to certain regulatory requirements and thresholds related to natural gas procurement under the GCIM. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Consolidated Statements of Operations are reflected in Cost of Natural Gas or in Cost of Electric Fuel and Purchased Power.

▪ SDG&E is allocated and may purchase CRRs, which are designed to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations.

▪ Sempra Infrastructure may use natural gas and electricity derivatives, as appropriate, in an effort to mitigate commodity price risk and 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 Revenues: Energy-Related Businesses on the Consolidated Statements of Operations.

▪ Sempra Infrastructure may use natural gas derivatives when supplying feed gas to its natural gas liquefaction facilities to support the production of LNG. Gains and losses from these undesignated derivatives are recognized in Revenues: Energy-Related Businesses or Energy-Related Businesses Cost of Sales on the 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.

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The following table summarizes net energy derivative volumes.

NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
		December 31,
Commodity	Unit of measure	2025	2024
Sempra:
Natural gas (1)	MMBtu	336	637
Congestion revenue rights	MWh	18	27
SDG&E:
Natural gas	MMBtu	14	16
Congestion revenue rights	MWh	18	27
SoCalGas:
Natural gas	MMBtu	322	347

(1) At December 31, 2025, excludes 1,016 related to the disposal group that is classified as held for sale.

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)
	December 31, 2024
	Notional amount	Maturities
Sempra:
Cash flow hedges (1)	$ 271	2025-2034
Undesignated derivatives (2)(3)	3,189	2025-2048

(1) At December 31, 2025, excludes a notional amount of $ 244 with maturities of 2026-2034 related to the disposal group that is classified as held for sale.

(2) At December 31, 2025, excludes a notional amount of $ 3,189 with maturities of 2026-2048 related to the disposal group that is classified as held for sale. These undesignated derivatives accrued interest based on a notional amount of $ 2,286 .

(3) At December 31, 2024, undesignated derivatives accrued interest based on a notional amount of $ 1,598 .

FOREIGN CURRENCY DERIVATIVES

From time to time, SI Partners 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.

In the first quarter of 2026, SI Partners entered into undesignated contingent foreign currency hedges that are designed to lock in the exchange rate associated with the anticipated after‑tax net proceeds from the planned sale of Ecogas. Settlement of the hedges is contingent on the completion of the planned sale of Ecogas in the second or third quarter of 2026.

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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 help 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)
	December 31, 2024
	Notional amount	Maturities
Sempra:
Foreign currency derivatives (1)	$ 162	2025-2026

(1) At December 31, 2025, excludes a notional amount of $ 172 with maturities of 2026-2027 related to the disposal group that is classified as held for sale.

FINANCIAL STATEMENT PRESENTATION

The Consolidated Balance Sheets reflect the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Consolidated Balance Sheets, including the amount of cash collateral receivables that were not offset because the cash collateral was in excess of liability positions. We discuss the fair value of derivative assets and liabilities in Note 11.

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DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31, 2025
	Current assets			Current liabilities
	Other current assets	Assets held for sale	Other long-term assets	Other current liabilities	Liabilities held for sale	Deferred credits and other
Sempra:
Derivatives designated as hedging instruments:
Interest rate instruments		$ 25			$ —
Foreign exchange instruments		—			( 8 )
Derivatives not designated as hedging instruments:
Interest rate instruments		242			—
Commodity contracts not subject to rate recovery		9			( 66 )
Associated offsetting commodity contracts		( 5 )			5
Commodity contracts subject to rate recovery	$ 25		$ 11	$ ( 134 )		$ ( 10 )
Associated offsetting commodity contracts	( 4 )		( 2 )	4		2
Associated offsetting cash collateral	—		—	68		4
Net amounts presented on the balance sheet	21	271	9	( 62 )	( 69 )	( 4 )
Additional cash collateral for commodity contracts not subject to rate recovery		38			—
Additional cash collateral for commodity contracts subject to rate recovery	23		—	—		—
Total	$ 44	$ 309	$ 9	$ ( 62 )	$ ( 69 )	$ ( 4 )
SDG&E:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$ 4		$ 8	$ ( 12 )		$ ( 5 )
Associated offsetting commodity contracts	—		( 1 )	—		1
Associated offsetting cash collateral	—		—	12		4
Net amounts presented on the balance sheet	4		7	—		—
Additional cash collateral for commodity contracts subject to rate recovery	13		—	—		—
Total	$ 17		$ 7	$ —		$ —
SoCalGas:
Derivatives not designated as hedging instruments:
Commodity contracts subject to rate recovery	$ 21		$ 3	$ ( 122 )		$ ( 5 )
Associated offsetting commodity contracts	( 4 )		( 1 )	4		1
Associated offsetting cash collateral	—		—	56		—
Net amounts presented on the balance sheet	17		2	( 62 )		( 4 )
Additional cash collateral for commodity contracts subject to rate recovery	10		—	—		—
Total	$ 27		$ 2	$ ( 62 )		$ ( 4 )

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DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
	December 31, 2024
	Other current assets	Other long-term assets	Other current liabilities	Deferred credits and other
Sempra:
Derivatives designated as hedging instruments:
Interest rate instruments	$ 7	$ 28	$ —	$ —
Foreign exchange instruments	4	1	—	—
Derivatives not designated as hedging instruments:
Interest rate instruments	12	246	—	—
Commodity contracts not subject to rate recovery	16	23	( 21 )	( 43 )
Associated offsetting commodity contracts	( 15 )	( 23 )	15	23
Commodity contracts subject to rate recovery	7	4	( 55 )	( 10 )
Associated offsetting commodity contracts	( 5 )	( 2 )	5	2
Associated offsetting cash collateral	—	—	10	4
Net amounts presented on the balance sheet	26	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 (1)	$ 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 sheet	2	2	( 1 )	—
Additional cash collateral for commodity contracts subject to rate recovery	21	—	—	—
Total (1)	$ 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) 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 Consolidated Statements of Operations and in OCI and AOCI.

HEDGE IMPACTS
(Dollars in millions)
	Pretax (loss) gain recognized in OCI				Pretax gain (loss) reclassified from AOCI into earnings
	Years ended December 31,				Years ended December 31,
	2025	2024	2023	Location	2025	2024	2023
Sempra:
Cash flow hedges:
Interest rate instruments	$ ( 2 )	$ 36	$ 45	Interest expense	$ 7	$ 11	$ ( 1 )
Interest rate instruments	( 29 )	21	20	Equity earnings (1)	10	23	48
Foreign exchange instruments	( 13 )	14	( 2 )	Revenues: Energy- related businesses	( 3 )	5	( 1 )
				Other income, net	( 2 )	2	( 2 )
Foreign exchange instruments	( 13 )	12	( 3 )	Equity earnings (1)	( 5 )	6	( 2 )
Interest rate and foreign exchange instruments	—	—	7	Interest expense	—	—	1
				Other income, net	—	—	6
Fair value hedges:
Foreign exchange instruments	( 27 )	2	—	Equity earnings (1)	—	—	—
Total	$ ( 84 )	$ 85	$ 67		$ 7	$ 47	$ 49
SoCalGas:
Cash flow hedges:
Interest rate instruments	$ —	$ —	$ —	Interest expense	$ ( 1 )	$ ( 1 )	$ ( 1 )

(1) Equity earnings at Oncor Holdings and our foreign equity method investees are recognized after tax.

For Sempra, we expect that net losses before NCI of $ 2 million, which are net of income tax benefit and include amounts related to the disposal group that is classified as held for sale, that are currently recorded in AOCI (with net gains of $ 1 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 December 31, 2025, t he 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 Consolidated Statements of Operations.

UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
		Pretax (loss) gain on derivatives recognized in earnings
		Years ended December 31,
	Location	2025	2024	2023
Sempra:
Commodity contracts not subject to rate recovery	Revenues: Energy-related businesses	$ ( 6 )	$ 223	$ 919
Commodity contracts not subject to rate recovery	Energy-related business cost of sales	( 1 )	—	—
Commodity contracts subject to rate recovery	Cost of natural gas	( 149 )	( 56 )	( 288 )
Commodity contracts subject to rate recovery	Cost of electric fuel and purchased power	( 14 )	( 41 )	15
Interest rate instruments	Interest expense	—	243	( 47 )
Total		$ ( 170 )	$ 369	$ 599
SDG&E:
Commodity contracts subject to rate recovery	Cost of electric fuel and purchased power	$ ( 14 )	$ ( 41 )	$ 15
SoCalGas:
Commodity contracts subject to rate recovery	Cost of natural gas	$ ( 149 )	$ ( 56 )	$ ( 288 )

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 December 31, 2025 and 2024 is $ 190 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 December 31, 2025 and 2024. For SoCalGas, the total fair value of this group of derivative instruments in a liability position at December 31, 2025 and 2024 is $ 47 million and $ 42 million, respectively. At December 31, 2025, if the credit ratings of Sempra or SoCalGas were reduced below investment grade, $ 189 million and $ 47 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 11. FAIR VALUE MEASUREMENTS

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 December 31, 2025 and 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.

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” and natural gas derivatives at Sempra Infrastructure, as we discuss below in “Level 3 Information – Other Sempra.” We further discuss derivative assets and liabilities in Note 10.

▪ 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 16, in July 2020, Sempra entered into the 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 1	Level 2	Level 3	Netting (1)	Total
	Fair value at December 31, 2025
Sempra:
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents	$ 9	$ 3	$ —		$ 12
Equity securities	285	3	—		288
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	28	19	—		47
Municipal bonds	—	300	—		300
Other securities	—	255	—		255
Total debt securities	28	574	—		602
Total nuclear decommissioning trusts (2)	322	580	—		902
Short-term investments held in Rabbi Trust	49	—	—		49
Support Agreement, net of related guarantee fees	—	—	41		41
Commodity contracts subject to rate recovery	2	24	10	$ 17	53
	373	604	51	17	1,045
Assets held for sale:
Interest rate instruments	—	267	—	—	267
Commodity contracts not subject to rate recovery	—	8	1	33	42
Total assets held for sale	—	275	1	33	309
Total assets	$ 373	$ 879	$ 52	$ 50	$ 1,354
Liabilities:
Commodity contracts subject to rate recovery	$ 37	$ 107	$ —	$ ( 78 )	$ 66
Liabilities held for sale:
Foreign exchange instruments	—	8	—	—	8
Commodity contracts not subject to rate recovery	—	10	56	( 5 )	61
Total liabilities held for sale	—	18	56	( 5 )	69
Total liabilities	$ 37	$ 125	$ 56	$ ( 83 )	$ 135
	Fair value at December 31, 2024
Sempra:
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents	$ 8	$ 2	$ —		$ 10
Equity securities	295	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 securities	41	541	—		582
Total nuclear decommissioning trusts (2)	344	546	—		890
Short-term investments held in Rabbi Trust	64	—	—		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 recovery	6	1	4	18	29
Total assets	$ 414	$ 884	$ 29	$ 20	$ 1,347
Liabilities:
Commodity contracts not subject to rate recovery	$ 1	$ 63	$ —	$ ( 38 )	$ 26
Commodity contracts subject to rate recovery	20	45	—	( 21 )	44
Total liabilities	$ 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 1	Level 2	Level 3	Netting (1)	Total
	Fair value at December 31, 2025
SDG&E:
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents	$ 9	$ 3	$ —		$ 12
Equity securities	285	3	—		288
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	28	19	—		47
Municipal bonds	—	300	—		300
Other securities	—	255	—		255
Total debt securities	28	574	—		602
Total nuclear decommissioning trusts (2)	322	580	—		902
Commodity contracts subject to rate recovery	2	—	10	$ 12	24
Total	$ 324	$ 580	$ 10	$ 12	$ 926
Liabilities:
Commodity contracts subject to rate recovery	$ 17	$ —	$ —	$ ( 17 )	$ —
	Fair value at December 31, 2024
SDG&E:
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents	$ 8	$ 2	$ —		$ 10
Equity securities	295	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 securities	41	541	—		582
Total nuclear decommissioning trusts (2)	344	546	—		890
Commodity contracts subject to rate recovery	4	—	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 1	Level 2	Level 3	Netting (1)	Total
	Fair value at December 31, 2025
SoCalGas:
Assets:
Commodity contracts subject to rate recovery	$ —	$ 24	$ —	$ 5	$ 29
Liabilities:
Commodity contracts subject to rate recovery	$ 20	$ 107	$ —	$ ( 61 )	$ 66
	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)
	2025	2024	2023
Balance at January 1	$ 4	$ 10	$ 35
Realized and unrealized gains (losses), net	2	( 10 )	( 17 )
Allocated transmission instruments	8	3	( 1 )
Settlements	( 4 )	1	( 7 )
Balance at December 31	$ 10	$ 4	$ 10
Change in unrealized gains (losses) relating to instruments still held at December 31	$ —	$ ( 4 )	$ ( 13 )

(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 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.

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 year	Price per MWh			Median price per MWh
2026	$ ( 0.31 )	to	$ 13.76	$ 4.05
2025	( 7.38 )	to	15.54	0.01
2024	( 3.69 )	to	9.55	( 0.44 )

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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 10.

Other Sempra

Support Agreement. 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)
	2025	2024	2023
Balance at January 1	$ 25	$ 23	$ 17
Realized and unrealized gains (losses), net (1)	24	11	15
Settlements	( 8 )	( 9 )	( 9 )
Balance at December 31 (2)	$ 41	$ 25	$ 23
Change in unrealized gains (losses) relating to instruments still held at December 31	$ 24	$ 8	$ 13

(1) Net gains are included in Interest Income and net losses are included in Interest Expense on Sempra’s Consolidated Statements of Operations.

(2) Balance at December 31, 2025 and 2024 includes $ 8 and $ 7 , respectively, in Other Current Assets, and $ 33 and $ 18 , respectively, in Other Long-Term Assets on Sempra’s 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 December 31, 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.

Commodity contracts not subject to rate recovery. The table below sets forth a reconciliation of the change in the fair value of natural gas derivatives classified as Level 3 in the fair value hierarchy.

LEVEL 3 RECONCILIATION
(Dollars in millions)
	2025
Balance at January 1	$ —
Transfer from Level 2 to Level 3	( 55 )
Balance at December 31	$ ( 55 )
Change in unrealized gains (losses) relating to instruments still held at December 31	$ —

At the end of the reporting period, we refined how we determine the fair value of certain natural gas derivatives to include significant unobservable inputs. Because these inputs are not based on observable market data, the instruments no longer meet the criteria for Level 2 classification. As a result, we transferred their fair value measurement from Level 2 to Level 3 in the fair value hierarchy. Realized and unrealized gains and losses associated with commodity contracts not subject to rate recovery are recorded in Revenues: Energy-Related Businesses or Energy-Related Businesses Cost of Sales on the Sempra Consolidated Statement of Operations.

We estimate the fair value of our natural gas derivatives using an income approach. These instruments are classified as Level 3 within the fair value hierarchy because their valuation relies on significant unobservable inputs. Key unobservable inputs include implied forward price curves at illiquid delivery locations and location-specific forward price adjustments. When observable market data is limited or unavailable at these illiquid delivery points, we apply industry-standard valuation methodologies to develop unobservable inputs that maximize the use of observable information, including extrapolation and the use of historical market data and other relevant information.

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The following table presents information about the significant unobservable inputs used in the valuation of our Level 3 natural gas derivatives at December 31, 2025:

QUANTITATIVE INFORMATION ABOUT LEVEL 3 FAIR VALUE MEASUREMENT	Fair value (in millions)	Valuation technique	Unobservable input	Range			Weighted average
Commodity contracts not subject to rate recovery	$ ( 55 )	Income approach	Forward natural gas price per MMBtu	$ 0.29	–	$ 2.41	$ 1.61

The valuation of our natural gas derivatives is sensitive to changes in forward pricing and location-specific price adjustments. Generally, significant increases or decreases in forward pricing, in isolation, would decrease or increase, respectively, the fair value of the natural gas derivatives. We evaluate valuation inputs and assumptions at least quarterly and update inputs as necessary to reflect changes.

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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 Plan, Cash Balance Restoration Plan and Employee and Director Savings Plan are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Consolidated Balance Sheets.

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
	Carrying	Fair value
	amount	Level 1	Level 2	Level 3	Total
	December 31, 2025
Sempra:
Long-term note receivable (1)	$ 369	$ —	$ —	$ 366	$ 366
Long-term amounts due to unconsolidated affiliates held for sale	477	—	463	—	463
Long-term debt held for sale (2)	7,925	—	7,611	—	7,611
Long-term debt (3)	29,867	—	28,282	—	28,282
SDG&E:
Long-term debt (4)	$ 9,800	$ —	$ 8,810	$ —	$ 8,810
SoCalGas:
Long-term debt (5)	$ 8,109	$ —	$ 7,818	$ —	$ 7,818
	December 31, 2024
Sempra:
Long-term note receivable (1)	$ 351	$ —	$ —	$ 334	$ 334
Long-term amounts due to unconsolidated affiliates	352	—	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 December 31, 2025 and 2024, respectively. Excludes unamortized transaction costs of $ 3 at both December 31, 2025 and 2024, respectively.

(2) After the effects of interest rate swaps. Before reductions of unamortized discount and debt issuance costs of $ 132 at December 31, 2025.

(3) After the effects of interest rate swaps at December 31, 2024. Before reductions of unamortized discount and debt issuance costs of $ 305 and $ 382 at December 31, 2025 and 2024, respectively, and excluding finance lease obligations of $ 1,293 and $ 1,315 at December 31, 2025 and 2024, respectively.

(4) Before reductions of unamortized discount and debt issuance costs of $ 97 and $ 95 at December 31, 2025 and 2024, respectively, and excluding finance lease obligations of $ 1,176 and $ 1,205 at December 31, 2025 and 2024, respectively.

(5) Before reductions of unamortized discount and debt issuance costs of $ 78 and $ 65 at December 31, 2025 and 2024, respectively, and excluding finance lease obligations of $ 117 and $ 110 at December 31, 2025 and 2024, respectively.

We provide the fair values for the securities held in the NDT related to SONGS in Note 15.

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NOTE 12. SEMPRA – 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.

Tab le of Cont ents

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 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 December 31, 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.

Contributions

In addition to the $ 3,166 million contribution made in September 2025 that we discuss above, Blackstone contributed $ 2,082 million in December 2025, both of which were recorded as increases to CRNCI.

Allocation of Interests

Upon reaching a positive 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 net assets must be further allocated among the respective owners.

To effect the allocation of interests in the year ended December 31, 2025, we recorded a decrease in CRNCI of $ 2,115 million, an increase in NCI of $ 673 million and an increase in Sempra’s shareholders’ equity of $ 1,073 million, net of $ 369 million in income tax expense.

NOTE 13. EQUITY AND EARNINGS PER COMMON SHARE

PREFERRED STOCK

Sempra and SDG&E are authorized to issue up to 50,000,000 and 45,000,000 shares of preferred stock, respectively. At December 31, 2025, Sempra had no preferred stock outstanding. At December 31, 2025 and 2024, SDG&E had no preferred stock outstanding. The rights, preferences, privileges and restrictions for any new series of preferred stock would be established by each company’s board of directors at the time of issuance. We discuss SoCalGas preferred stock below.

Sempra Series C Preferred Stock

At December 31, 2024, Sempra had 900,000 shares of series C preferred stock outstanding. In 2025, Sempra provided notice of the redemption of all 900,000 issued and outstanding shares of our series C preferred stock for a redemption price of $ 1,000 per share, and paid $ 900 million with proceeds received from our August 2025 issuance of junior subordinated notes and short-term debt, which we discuss in Note 7. Upon notice of the redemption, we recognized $ 11 million of capitalized underwriting discounts and equity issuance costs in Preferred Deemed Dividends on the Sempra Consolidated Statement of Operations.

On February 23, 2026, Sempra filed restated articles of incorporation that implemented the revocation of the series C preferred stock, such that the number of authorized shares of such series is decreased to zero and it is no longer an authorized series of Sempra’s capital stock.

Tab le of Cont ents

SoCalGas Preferred Stock

SoCalGas is authorized to issue up to an aggregate of 11,000,000 shares of preferred stock, series preferred stock and preference stock. The table below presents preferred stock outstanding at SoCalGas:

PREFERRED STOCK OUTSTANDING
(Dollars in millions, except per share amounts)
	December 31,
	2025	2024
$ 25 par value, authorized 1,000,000 shares:
6 % Series, 79,011 shares outstanding	$ 3	$ 3
6 % Series A, 783,032 shares outstanding	19	19
SoCalGas - Total preferred stock	22	22
Less: 50,970 shares of the 6 % Series outstanding owned by Pacific Enterprises	( 2 )	( 2 )
Sempra - Total preferred stock of subsidiary	$ 20	$ 20

None of SoCalGas’ outstanding preferred stock is callable, and no shares are subject to mandatory redemption.

All outstanding shares have one vote per share, cumulative preferences as to dividends and liquidation preferences of $ 25 per share plus any unpaid dividends.

In addition to the outstanding preferred stock above, SoCalGas’ articles of incorporation authorize 5,000,000 shares of series preferred stock and 5,000,000 shares of preference stock, both without par value and with cumulative preferences as to dividends and liquidation value. The preference stock would rank junior to all series of preferred stock and series preferred stock. Other rights and privileges of any new series of such stock would be established by the SoCalGas board of directors at the time of issuance.

The preferred stock at SoCalGas is presented at Sempra as NCI. Sempra records charges against income related to NCI for preferred dividends declared by SoCalGas.

COMMON STOCK

We are authorized to issue 1,125,000,000 shares of Sempra’s no par value common stock. The following table provides common stock activity for the last three years.

COMMON STOCK ACTIVITY	2025	2024	2023
Sempra:
Common shares outstanding, January 1	650,629,876	631,431,732	628,669,356
Shares issued under forward sale agreements	—	17,142,858	—
Shares issued to underwriters to cover overallotments	—	—	2,099,152
RSUs vesting (1)	1,571,512	1,320,561	941,910
Stock options exercised	—	143,944	—
Common stock investment plan (2)	1,067,446	1,151,877	1,730
Issuance of RSUs held in our deferred compensation plans	147,582	128,207	132,178
Shares repurchased (3)	( 684,748 )	( 689,303 )	( 412,594 )
Common shares outstanding, December 31	652,731,668	650,629,876	631,431,732

(1) Includes dividend equivalents.

(2) Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares.

(3) Includes shares repurchased under repurchase programs and shares withheld from LTIP participants and individuals exercising stock options in 2024 to satisfy minimum statutory tax withholding requirements.

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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.

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 December 31, 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 per share. 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 December 31, 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 December 31, 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.

Tab le of Cont ents

November 2023 Common Stock Offering and Forward Sale Agreements

In November 2023, we completed the offering of 19,242,010 shares of our common stock, no par value, in a registered public offering at $ 70.00 per share ($ 68.845 per share after deducting underwriting discounts), 17,142,858 shares of which were pursuant to forward sale agreements with an affiliate of Morgan Stanley & Co. LLC and an affiliate of Citigroup Global Markets Inc. (the November 2023 forward purchasers). The shares offered pursuant to the forward sale agreements were borrowed by the underwriters and therefore are not newly issued shares. The underwriters of the offering partially exercised the option we granted them and purchased 2,099,152 shares of common stock directly from us solely to cover overallotments. We received net proceeds of $ 144 million (net of underwriting discounts and equity issuance costs of $ 3 million) from the sale of shares to cover overallotments. We did not initially receive any proceeds from the sale of shares pursuant to the forward sale agreements. We used the net proceeds from the sale of the overallotment shares to fund working capital and for other general corporate purposes, including to partly finance our long-term capital plan and to repay commercial paper and other indebtedness.

In December 2024, upon full physical settlement of the forward sale agreements from our November 2023 offering, we received net proceeds of $ 1.2 billion (net of underwriting discounts and equity issuance costs of $ 20 million) from the issuance of 17,142,858 shares of Sempra common stock at a forward price of $ 69.2195 per share. We used the net proceeds from our common stock issued pursuant to the forward sale agreements to fund working capital and for other general corporate purposes, including to partly finance our long-term capital plan and to repay commercial paper and other indebtedness.

COMMON STOCK REPURCHASES

On July 6, 2020, our board of directors authorized the repurchase of shares of our common stock at any time and from time to time in an aggregate amount not to exceed the lesser of $ 2.0 billion or amounts spent to purchase no more than 25,000,000 shares. As of February 26, 2026, a maximum of $ 1.25 billion and no more than 19,632,529 shares may yet be purchased under this repurchase authorization.

In 2025, 2024 and 2023, we withheld 684,748 shares for $ 58 million, 689,303 shares for $ 43 million and 412,594 shares for $ 32 million, respectively, of our common stock that would otherwise be issued to LTIP participants and individuals exercising stock options in 2024 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. The repurchases do not fall under the July 6, 2020 repurchase authorization.

Tab le of Cont ents

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)
	Years ended December 31,
	2025	2024	2023
Sempra:
Numerator:
Earnings attributable to common shares	$ 1,796	$ 2,817	$ 3,030
Denominator:
Weighted-average common shares outstanding for basic EPS (1)	652,697	633,795	630,296
Dilutive effect of common shares sold forward	209	2,036	96
Dilutive effect of stock options and RSUs (2)	920	2,112	2,341
Weighted-average common shares outstanding for diluted EPS	653,826	637,943	632,733
EPS:
Basic	$ 2.75	$ 4.44	$ 4.81
Diluted	$ 2.75	$ 4.42	$ 4.79

(1) Includes fully vested RSUs held in our deferred compensation plan of 500 in 2025, 617 in 2024 and 717 in 2023. 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 14, dilutive RSUs may vary widely from period-to-period.

The potentially dilutive impact from stock options and RSUs is calculated under the treasury stock method. Under this method, proceeds based on the exercise price and unearned compensation are assumed to be used to repurchase shares on the open market at the average market price for the period, reducing the number of potential new shares to be issued and sometimes causing an antidilutive effect. The computation of diluted EPS for 2025, 2024 and 2023 excludes potentially dilutive shares related to stock options and RSUs of 567,653 , 747,724 and 502,942 , 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.

NONCONTROLLING INTERESTS

Ownership interests in a consolidated entity that are held by unconsolidated owners are accounted for and reported as NCI.

In 2025, 2024 and 2023, Sempra Infrastructure distributed $ 609 million, $ 297 million and $ 730 million, respectively, to its NCI owners, and NCI owners contributed $ 327 million, $ 1,235 million and $ 1,770 million, respectively, to Sempra Infrastructure.

Tab le of Cont ents

The following table summarizes net income attributable to Sempra and transfers (to) from CRNCI and NCI, which shows the effects of changes in Sempra’s ownership interest in its subsidiaries on Sempra’s shareholders’ equity. There were no transfers (to) from CRNCI and NCI in 2024.

NET INCOME ATTRIBUTABLE TO SEMPRA AND TRANSFERS (TO) FROM CRNCI AND NCI
(Dollars in millions)
	Years ended December 31,
	2025	2023
Sempra:
Net income attributable to Sempra	$ 1,837	$ 3,075
Transfers (to) from CRNCI and NCI:
Increase in shareholders’ equity from investor equity subscription	16	—
Increase in shareholders’ equity from allocation of interests (1)	1,073	—
Decrease in shareholders’ equity for sales of NCI	—	( 49 )
Net transfers (to) from CRNCI and NCI	1,089	( 49 )
Change from net income attributable to Sempra and transfers (to) from CRNCI and NCI	$ 2,926	$ 3,026

(1) We describe the allocation of interests in Note 12.

SI Partners

Sale of NCI to KKR Pinnacle

In connection with the October 2021 sale of NCI to KKR Pinnacle, KKR Pinnacle was entitled to a $ 200 million credit from Sempra to be applied to capital calls once an LNG project reached a positive FID and met certain projected internal rates of return. In 2023, KKR Pinnacle used $ 200 million of this credit to fund its share of contributions to SI Partners. As a result, we recorded a $ 200 million increase in equity held by NCI and a decrease in Sempra’s shareholders’ equity of $ 145 million, net of a tax benefit.

SI Partners Subsidiaries

Sale of NCI to KKR Denali

In September 2023, a subsidiary of SI Partners completed the sale of a 60 % interest in an SI Partners subsidiary (resulting in a 42 % NCI in the PA LNG Phase 1 project) to KKR Denali for aggregate cash consideration of $ 976 million, including post-closing adjustments. As a result of this sale, we recorded a $ 1.0 billion increase in equity held by NCI and a decrease in Sempra’s shareholders’ equity of $ 61 million, including $ 11 million in transaction costs and net of a $ 23 million tax benefit.

SI Partners’ and KKR Denali’s subsidiaries have made capital contribution commitments to fund their respective equity share of the equity funding amount of anticipated development costs of the PA LNG Phase 1 project, except in certain budget overrun scenarios.

Sale of NCI to ConocoPhillips Affiliate

In March 2023, a subsidiary of SI Partners completed the sale of a 30 % interest in an SI Partners subsidiary (resulting in a 30 % NCI in the PA LNG Phase 1 project) to an affiliate of ConocoPhillips for aggregate cash consideration of $ 254 million, including post-closing adjustments. As a result of this sale, we recorded a $ 234 million increase in equity held by NCI and an increase in Sempra’s shareholders’ equity of $ 12 million, net of $ 3 million in transaction costs and $ 5 million in tax expense.

SI Partners’ subsidiary and the ConocoPhillips affiliate have made certain customary capital contribution commitments to fund their respective pro rata equity share of the total anticipated capital calls for the equity portion of the anticipated development costs of the PA LNG Phase 1 project. In addition, 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 December 31, 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.

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NOTE 14. SHARE-BASED COMPENSATION

SEMPRA EQUITY COMPENSATION PLANS

Sempra has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra. The plans permit a wide variety of share-based awards, including:

▪ nonqualified stock options

▪ incentive stock options

▪ restricted stock awards

▪ restricted stock units

▪ stock appreciation rights

▪ performance awards

▪ stock payments

▪ dividend equivalents

Eligible employees, including those from SDG&E and SoCalGas, participate in Sempra’s share-based compensation plans as a component of their compensation package.

In the three years ended December 31, 2025, Sempra had the following types of equity awards outstanding:

▪ Nonqualified Stock Options : Options to purchase common stock have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a three-year period and expire 10 years from the date of grant. Unvested option awards are subject to forfeiture following a termination of employment, except where the retirement criteria under such awards have been met and subject to certain other exceptions described below.

▪ Performance-Based Restricted Stock Units : These RSU awards generally vest in Sempra common stock at the end of three -year performance periods based on Sempra’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra’s EPS. The comparative market indices for the awards that vest based on total return to shareholders are the S&P 500 Utilities Index (excluding water companies) and the S&P 500 Index. For the awards that vest based on EPS growth, (i) awards issued in 2025 and 2024 are based on the percentile ranking of the compound annual growth rate of Sempra’s adjusted EPS relative to the EPS compound annual growth rate of companies in the S&P 500 Utilities Index (excluding water companies), and (ii) awards issued in 2023 are based on long-term analyst consensus EPS growth estimates for companies in the S&P 500 Utilities Index (excluding water companies). If Sempra’s total return to shareholders or EPS growth is below the target levels but above threshold performance levels, shares are subject to partial vesting on a pro rata basis. If Sempra’s total return to shareholders or EPS growth exceeds target levels, up to an additional 100 % of the granted RSUs may be issued. These RSU awards are subject to forfeiture prior to vesting following a termination of employment, except where the retirement criteria under such awards have been met and subject to certain other exceptions described below.

▪ Service-Based Restricted Stock Units: RSUs may also be service-based; these vest ratably over one -, two -, three - and four-year service periods. These awards are subject to earlier forfeiture upon termination of employment, subject to certain exceptions described below.

For awards that would otherwise be forfeited upon termination of employment, the Compensation and Talent Development Committee of Sempra’s board of directors may waive the forfeiture requirement and, with respect to options and service-based RSUs, may accelerate vesting. Awards are also subject to accelerated vesting under certain circumstances upon a change in control under the applicable LTIP, in accordance with severance pay agreements or to the extent otherwise required by the terms of the applicable award. Dividend equivalents on shares subject to RSUs are reinvested to purchase additional common shares that become subject to the same vesting conditions as the RSUs to which the dividends relate.

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SHARE-BASED AWARDS AND COMPENSATION EXPENSE

At December 31, 2025, 15,400,000 common shares were authorized, and 6,544,164 common shares were available for future grants of share-based awards, in each case under Sempra’s 2019 LTIP. Our practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases.

We measure and recognize compensation expense for all share-based payment awards made to our employees and directors based on estimated fair values on the date of grant. We recognize compensation costs net of an estimated forfeiture rate (based on historical experience) and recognize the compensation costs for nonqualified stock options and RSUs on a straight-line basis over the requisite service period of the award, which is generally three years . However, for awards granted to retirement-eligible participants, the expense is recognized over the initial year in which the award was granted as the award requires service through the end of the year in which it was granted. For awards granted to participants who become eligible for retirement during the requisite service period, the expense is recognized over the period between the date of grant and the later of the end of the year in which the award was granted or the date the participant first becomes eligible for retirement. Substantially all awards outstanding are classified as equity instruments; therefore, we recognize additional paid in capital as we recognize the compensation expense associated with the awards. We recognize in earnings the tax benefits (or deficiencies) resulting from tax deductions that are in excess of (or less than) tax benefits related to compensation cost recognized for share-based payments.

Sempra subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans and/or the subsidiaries are allocated a portion of the Sempra plans’ corporate staff costs. Total share-based compensation expense for all of Sempra’s share-based awards was comprised as follows:

SHARE-BASED COMPENSATION EXPENSE
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra:
Share-based compensation expense, before income taxes (1)	$ 56	$ 77	$ 71
Income tax benefit (1)	( 6 )	( 9 )	( 9 )
	$ 50	$ 68	$ 62
Capitalized share-based compensation cost	$ 8	$ 13	$ 12
Excess income tax (benefit) deficiency	( 15 )	( 9 )	( 6 )
SDG&E:
Share-based compensation expense, before income taxes	$ 8	$ 12	$ 13
Income tax benefit	( 1 )	( 2 )	( 2 )
	$ 7	$ 10	$ 11
Capitalized share-based compensation cost	$ 5	$ 7	$ 7
Excess income tax (benefit) deficiency	( 3 )	( 1 )	( 1 )
SoCalGas:
Share-based compensation expense, before income taxes	$ 10	$ 20	$ 18
Income tax benefit	( 2 )	( 4 )	( 3 )
	$ 8	$ 16	$ 15
Capitalized share-based compensation cost	$ 3	$ 6	$ 5
Excess income tax (benefit) deficiency	( 3 )	( 2 )	( 1 )

(1) Includes activity of awards issued from the IEnova 2013 LTIP in the years ended December 31, 2024 and 2023, which settled in cash upon vesting based on the price of IEnova’s common stock.

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SEMPRA NONQUALIFIED STOCK OPTIONS

We use a Black-Scholes option-pricing model to estimate the fair value of each nonqualified stock option grant. The use of a valuation model requires us to make certain assumptions about selected model inputs. Expected volatility is calculated based on a blend of the historical and implied volatility of Sempra’s common stock price. The average expected term for options is based on the vesting schedule, contractual term of the option, expected employee exercise and post-termination behavior. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected term estimated at the date of the grant. In 2025, 2024 and 2023, Sempra’s board of directors granted 303,614 , 414,812 and 326,574 nonqualified stock options, respectively, that become exercisable over a three -year period. The weighted-average per-share fair value for options granted was $ 20.58 , $ 16.43 and $ 17.50 in 2025, 2024 and 2023, respectively. To calculate this fair value, we used the Black-Scholes model with the following weighted-average assumptions:

KEY ASSUMPTIONS FOR STOCK OPTIONS GRANTED
	Years ended December 31,
	2025	2024	2023
Sempra:
Stock price volatility	26.85 %	26.49 %	27.35 %
Expected term	5.36 years	5.36 years	5.36 years
Risk-free rate of return	4.35 %	3.90 %	3.89 %
Annual dividend yield	2.85 %	3.14 %	2.98 %

The following table shows a summary of nonqualified stock options at December 31, 2025 and activity for the year then ended:

NONQUALIFIED STOCK OPTIONS	Common shares under options	Weighted- average exercise price	Weighted- average remaining contractual term (in years)	Aggregate intrinsic value (in millions)
Sempra:
Outstanding at January 1, 2025	2,030,666	$ 68.22
Granted	303,614	$ 87.13
Outstanding at December 31, 2025	2,334,280	$ 70.68	6.20	$ 41
Vested or expected to vest at December 31, 2025	2,334,280	$ 70.68	6.20	$ 41
Exercisable at December 31, 2025	1,645,270	$ 66.37	5.33	$ 36

The aggregate intrinsic value at December 31, 2025 is the total of the difference between Sempra’s closing common stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for nonqualified stock options exercised was:

▪ zero in 2025

▪ $ 4.4 million in 2024

▪ zero in 2023

We expect a negligible amount of total compensation cost related to nonvested stock options not yet recognized as of December 31, 2025 to be recognized over a weighted-average period of 0.4 years. The weighted-average exercise price for nonqualified stock options granted in 2024 and 2023 was $ 75.82 and $ 76.86 , respectively.

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SEMPRA RESTRICTED STOCK UNITS

We use Sempra’s common stock price at the grant date to estimate the fair value of our service-based RSUs and our RSUs that vest based on the compound annual growth rate of Sempra’s EPS.

We use a Monte-Carlo simulation model to estimate the fair value of our RSUs that vest based on Sempra’s total return to shareholders. Our determination of fair value is affected by the historical volatility of the common stock price for Sempra and its peer group companies. The valuation also is affected by the risk-free rates of return and a number of other variables. Below are key assumptions for RSUs granted in the last three years:

KEY ASSUMPTIONS FOR RSUs GRANTED
	Years ended December 31,
	2025	2024	2023
Sempra:
Stock price volatility	21.84 %	21.27 %	35.31 %
Risk-free rate of return	4.23 %	4.06 %	4.13 %

The following table shows a summary of RSUs at December 31, 2025 and activity for the year then ended:

RESTRICTED STOCK UNITS	Performance-based restricted stock units		Service-based restricted stock units
	Units	Weighted- average grant-date fair value	Units	Weighted- average grant-date fair value
Sempra:
Nonvested at January 1, 2025	1,905,724	$ 77.22	543,088	$ 74.55
Granted	628,413	$ 86.46	261,084	$ 85.88
Vested	( 603,506 )	$ 73.43	( 299,620 )	$ 73.44
Forfeited	( 71,070 )	$ 83.46	( 27,515 )	$ 84.16
Nonvested at December 31, 2025 (1)	1,859,561	$ 81.33	477,037	$ 80.89
Expected to vest at December 31, 2025	1,823,031	$ 81.32	461,750	$ 80.83

(1) Each RSU represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based RSUs, up to an additional 100 % of the shares represented by the RSUs may be issued if Sempra exceeds target performance conditions.

In 2025, 2024 and 2023, the total fair value of RSU shares vested during the year was $ 66 million, $ 57 million and $ 52 million, respectively.

We expect $ 36 million of total compensation cost related to nonvested RSUs not yet recognized as of December 31, 2025 to be recognized over a weighted-average period of 1.90 years. The weighted-average per-share fair values for performance-based RSUs granted were $ 75.70 and $ 82.64 in 2024 and 2023, respectively. The weighted-average per-share fair values for service-based RSUs granted were $ 75.86 and $ 76.76 in 2024 and 2023, respectively.

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NOTE 15. SAN ONOFRE NUCLEAR GENERATING STATION

SDG&E has a 20 % ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which permanently ceased operations in June 2013 after an extended outage as a result of issues with the steam generators used in the facility. Edison, the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.

SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of costs. SDG&E’s share of operating expenses is included in Sempra’s and SDG&E’s Consolidated Statements of Operations.

NUCLEAR DECOMMISSIONING AND FUNDING

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Major decommissioning work began in 2020. We expect the majority of the decommissioning work to 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 ISFSI and puts in place a program for the fuel’s disposal, as we discuss below. SDG&E is responsible for approximately 20 % of the total decommissioning cost.

In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. Amounts that were collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. SDG&E classifies debt and equity securities held in the NDT as available-for-sale. The NDT assets are presented on the Sempra and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.

Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. In January 2026, the CPUC granted SDG&E authorization to access NDT funds of up to $ 45 million for forecasted 2026 costs.

In September 2020, the IRS and the U.S. Department of the Treasury published final regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The final regulations adopted most of the provisions of the proposed regulations issued in December 2016. The final regulations apply to taxable years ending on or after September 4, 2020 and confirm that the definition of “nuclear decommissioning costs” includes amounts related to the storage of spent nuclear fuel at both on-site and off-site ISFSIs.

The final regulations also clarify that costs incurred for ISFSIs that may be or are expected to be reimbursed by the DOE may be paid or reimbursed from a qualified trust fund. Accordingly, the final regulations allow SDG&E the option to access qualified trust funds to recover spent fuel storage costs before Edison reaches final settlement with the DOE regarding the DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below.

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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 Consolidated Balance Sheets. We provide additional fair value disclosures for the NDT in Note 11.

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
	Cost	Gross unrealized gains	Gross unrealized losses	Estimated fair value
	December 31, 2025
Short-term investments, primarily cash equivalents	$ 12	$ —	$ —	$ 12
Equity securities	69	221	( 2 )	288
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies (1)	46	1	—	47
Municipal bonds (2)	301	4	( 5 )	300
Other securities (3)	253	5	( 3 )	255
Total debt securities	600	10	( 8 )	602
Receivables (payables), net	( 3 )	—	—	( 3 )
Total	$ 678	$ 231	$ ( 10 )	$ 899
	December 31, 2024
Short-term investments, primarily cash equivalents	$ 10	$ —	$ —	$ 10
Equity securities	78	223	( 3 )	298
Debt securities:
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	67	1	( 1 )	67
Municipal bonds	295	1	( 9 )	287
Other securities	234	2	( 8 )	228
Total debt securities	596	4	( 18 )	582
Receivables (payables), net	( 15 )	—	—	( 15 )
Total	$ 669	$ 227	$ ( 21 )	$ 875

(1) Maturity dates are 2026-2056.

(2) Maturity dates are 2026-2055.

(3) Maturity dates are 2026-2070.

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)
	Years ended December 31,
	2025	2024	2023
Proceeds from sales	$ 974	$ 874	$ 592
Gross realized gains	57	57	27
Gross realized losses	8	10	14

Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on Sempra’s and SDG&E’s Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

ASSET RETIREMENT OBLIGATION

The present value of SDG&E’s ARO related to decommissioning costs for all three SONGS units was $ 446 million at December 31, 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. The ARO for Units 2 and 3 reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. We expect SDG&E’s undiscounted SONGS decommissioning payments to be $ 100 million in 2026, $ 37 million in 2027, $ 25 million in 2028, $ 11 million in 2029, $ 9 million in 2030, and $ 860 million thereafter.

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U.S. DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL

Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC. The ISFSI will operate until 2054, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.

The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. In November 2019, Edison filed a claim for spent fuel management costs in the U.S. Court of Federal Claims for the time period from January 2017 through July 2018, which is pending approval. Additionally, in July 2024, Edison filed a claim for spent fuel management costs in the U.S. Court of Federal Claims for the time period from August 2018 through December 2021, which was subsequently amended to include costs through September 2024 and is pending approval. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel.

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $ 500 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides an additional $ 60 million of coverage. If a nuclear liability loss occurs at SONGS and exceeds the $ 500 million insurance limit, this additional coverage would be available to provide a total of $ 560 million in coverage limits per incident.

The SONGS owners have nuclear property damage insurance of $ 130 million, which exceeds the minimum federal requirement of $ 50 million. This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed a negligible amount for retrospective premiums based on overall member claims.

The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act) of $ 3.24 billion. This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.

NOTE 16. COMMITMENTS, 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 December 31, 2025, loss contingency accruals for legal matters that are probable and estimable were $ 38 million for Sempra, including $ 22 million for SoCalGas. We discuss our policy regarding accrual of legal fees in Note 1.

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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 in March 2025, definitively resolving this matter.

SoCalGas

LA Fires

Palisades Fire Litigation - Pending. There is a consolidated legal action pending in Los Angeles County Superior Court related to the January 2025 Palisades fire. Various plaintiffs named nineteen defendants in a December 2025 master complaint, including but not limited to SoCalGas, Sempra, Edison, Edison International, the J. Paul Getty Trust, the City of Los Angeles, Los Angeles County, and the State of California (collectively, the Palisades Defendants). At this early stage of the legal process, it is unclear how many plaintiffs are asserting claims against the Palisades Defendants. The plaintiffs seek an award of economic and noneconomic damages, punitive damages, attorneys’ fees, litigation costs and pre-judgment interest.

Eaton Fire Litigation - Pending. There is a separate consolidated legal action pending in Los Angeles County Superior Court related to the January 2025 Eaton fire. The first of these lawsuits was filed against Edison in January 2025. In January 2026, Edison and Edison International filed cross-complaints in Los Angeles County Superior Court against more than a dozen defendants, including but not limited to SoCalGas, the City of Pasadena, Pasadena Water and Power, Los Angeles County, and Genasys Inc. (collectively, the Eaton Cross-Defendants) in connection with underlying litigation related to the January 2025 Eaton fire. The Edison cross-complaints against the Eaton Cross-Defendants seek indemnity, compensatory damages, attorneys’ fees, litigation costs and pre-judgment interest.

Other Sempra

Energía Costa Azul

We describe below certain land disputes and permit challenges that may affect our ECA Regas Facility or ECA LNG liquefaction facilities under construction or in development. 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.

Land Disputes.

▪ Pending - Sempra Infrastructure has been engaged in a long-running land dispute relating to property adjacent to and owned by its ECA Regas Facility (the facility, however, is not situated on the land that is the subject of this dispute). A claimant to the adjacent property filed suit to reinitiate an administrative procedure at SEDATU to obtain the property title for the disputed property, which title 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 - 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.

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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 addition, 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:

▪ Resolved - 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 cancelation of 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. A federal appellate court affirmed the rulings in favor of the ECA Regas Facility, definitively resolving this matter.

▪ Resolved - 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. A federal appellate court affirmed the rulings in favor of the ECA Regas Facility, definitively resolving this matter.

▪ 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.

Port Arthur LNG I

TCEQ Permit - Resolved. 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. Because the petitioners did not file a petition for writ of certiorari with the U.S. Supreme Court by November 2025, the ruling is final and is not subject to further challenge. The 2016 Permit was not the subject of, and is unaffected by, the litigation of the 2022 Permit.

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 SI Partners but has released the site. OSHA’s inspection of SI Partners concluded without the issuance of citations to SI Partners. Bechtel is continuing construction of the PA LNG Phase 1 project.

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As of February 19, 2026, 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. In November 2025, the cases were transferred to a multidistrict litigation pretrial court and remain stayed pending assignment to a judge by the Texas Multidistrict Litigation Panel.

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 - Resolved. 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, in March 2025, the Mexican government adopted the 2025 Energy Laws, which repealed the LIE.

Prior to the enactment of the 2025 Energy Laws, 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 that impacted Sempra Infrastructure’s power marketing business was definitively dismissed by the Plenary of the Mexican Supreme Court in November 2025.

Ordinary Course Litigation

We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, employment litigation, product liability, property damage and other claims. Juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.

LEASES

A lease exists when a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. We determine if an arrangement is or contains a lease at inception of the contract.

Some of our lease agreements contain nonlease components, which represent activities that transfer a separate good or service to the lessee. As the lessee for both operating and finance leases, we have elected to combine lease and nonlease components as a single lease component for real estate, fleet vehicles, aircraft, power generating facilities and pipelines, whereby fixed or in-substance fixed payments allocable to the nonlease component are accounted for as part of the related lease liability and ROU asset. As the lessor, we have elected to combine lease and nonlease components as a single lease component for refined products terminals if the timing and pattern of transfer of the lease and nonlease components are the same and the lease component would be classified as an operating lease if accounted for separately.

Lessee Accounting

We have operating and finance leases for real and personal property (including office space, land, fleet vehicles, aircraft, tugboats, machinery and equipment, warehouses and other operational facilities) and PPAs with renewable energy, energy storage and peaker plant facilities.

Some of our leases include options to extend the lease terms for up to 25 years, or to terminate the lease within one year . Our lease liabilities and ROU assets are based on lease terms that may include such options when it is reasonably certain that we will exercise the option.

Certain of our contracts are short-term leases, which have a lease term of 12 months or less at lease commencement. We do not recognize a lease liability or ROU asset arising from short-term leases for all existing classes of underlying assets. In such cases, we recognize short-term lease costs on a straight-line basis over the lease term. Our short-term lease costs for the period reasonably reflect our short-term lease commitments.

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Certain of our leases contain escalation clauses requiring annual increases in rent ranging from 2 % to 5 % or based on the Consumer Price Index. The rentals payable under these leases may increase by a fixed amount each year or by a percentage of a base year. Variable lease payments that are based on an index or rate are included in the initial measurement of our lease liability and ROU asset based on the index or rate at lease commencement and are not remeasured because of changes to the index or rate. Rather, changes to the index or rate are treated as variable lease payments and recognized in the period in which the obligation for those payments is incurred.

Similarly, PPAs for the purchase of renewable energy at SDG&E require lease payments based on a stated rate per MWh produced by the facilities, and we are required to purchase substantially all the output from the facilities. SDG&E is required to pay additional amounts for capacity charges and actual purchases of energy that exceed the minimum energy commitments. Under these contracts, we do not recognize a lease liability or ROU asset for leases for which there are no fixed lease payments. Rather, these variable lease payments are recognized separately as variable lease costs. SDG&E estimates these variable lease payments to be $ 290 million in 2026, $ 289 million in 2027, $ 290 million in 2028, $ 289 million in each of 2029 and 2030 and $ 1.6 billion thereafter.

As of the lease commencement date, we recognize a lease liability for our obligation to make future lease payments, which we initially measure at present value using our incremental borrowing rate at the date of lease commencement, unless the rate implicit in the lease is readily determinable. We determine our incremental borrowing rate based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We also record a corresponding ROU asset, initially equal to the lease liability and adjusted for lease payments made at or before lease commencement, lease incentives, and any initial direct costs. We test ROU assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the ROU assets.

For our operating leases, our non-regulated entities recognize a single lease cost on a straight-line basis over the lease term in operating expenses. SDG&E and SoCalGas recognize this single lease cost on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.

For our finance leases, the interest expense on the lease liability and amortization of the ROU asset are accounted for separately. Our non-regulated entities use the effective interest rate method to account for the imputed interest on the lease liability and amortize the ROU asset on a straight-line basis over the lease term. SDG&E and SoCalGas recognize amortization of the ROU asset on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.

Our leases do not contain any material residual value guarantees , restrictions or covenants.

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Classification of ROU assets and lease liabilities and the weighted-average remaining lease term and discount rate associated with operating and finance leases are summarized in the table below.

LESSEE INFORMATION ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
	December 31,
	2025	2024	2025	2024	2025	2024
ROU assets (1) :
Operating leases:
ROU assets	$ 1,262	$ 1,177	$ 1,047	$ 795	$ 68	$ 18
Finance leases:
PP&E	1,673	1,626	1,440	1,426	233	200
Accumulated depreciation	( 380 )	( 311 )	( 264 )	( 221 )	( 116 )	( 90 )
PP&E, net	1,293	1,315	1,176	1,205	117	110
Total ROU assets	$ 2,555	$ 2,492	$ 2,223	$ 2,000	$ 185	$ 128
Lease liabilities (1) :
Operating leases:
Other current liabilities (2)	$ 90	$ 91	$ 85	$ 68	$ —	$ 8
Deferred credits and other (3)	1,176	1,019	969	734	67	9
	1,266	1,110	1,054	802	67	17
Finance leases:
Current portion of long-term debt and finance leases	73	65	48	42	25	23
Long-term debt and finance leases	1,220	1,250	1,128	1,163	92	87
	1,293	1,315	1,176	1,205	117	110
Total lease liabilities	$ 2,559	$ 2,425	$ 2,230	$ 2,007	$ 184	$ 127
Weighted-average remaining lease term (in years):
Operating leases (4)	12	13	12	12	15	2
Finance leases	13	14	14	15	6	6
Weighted-average discount rate:
Operating leases (4)(5)	5.18 %	6.10 %	5.25 %	5.06 %	5.19 %	4.70 %
Finance leases	13.65 %	13.71 %	14.08 %	14.11 %	5.67 %	5.35 %

(1) At December 31, 2025, excludes $ 206 of ROU assets under operating leases included in Assets Held for Sale and $ 143 of lease liabilities under operating leases included in Liabilities Held for Sale on the Sempra Consolidated Balance Sheet.

(2) Includes $ 58 and $ 43 related to PPAs at December 31, 2025 and 2024, respectively, at both Sempra and SDG&E.

(3) Includes $ 854 and $ 627 related to PPAs at December 31, 2025 and 2024, respectively, at both Sempra and SDG&E.

(4) At December 31, 2025, excludes operating leases within the disposal group that is classified as held for sale.

(5) Weighted-average discount rate related to PPAs at December 31, 2025 and 2024 is 5.23 % and 5.04 %, respectively, at both Sempra and SDG&E. Weighted-average discount rate related to all other operating leases at December 31, 2025 and 2024 is 5.05 % and 7.41 %, respectively, at Sempra and 5.37 % and 5.23 %, respectively, at SDG&E.

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The components of lease costs were as follows:

LESSEE INFORMATION ON THE CONSOLIDATED STATEMENTS OF OPERATIONS (1)
(Dollars in millions)
	Sempra			SDG&E			SoCalGas
	Years ended December 31,
	2025	2024	2023	2025	2024	2023	2025	2024	2023
Operating lease costs (2)	$ 164	$ 118	$ 99	$ 113	$ 71	$ 53	$ 8	$ 12	$ 13
Finance lease costs:
Amortization of ROU assets (3)	69	65	60	43	42	40	26	23	20
Interest on lease liabilities	176	178	182	169	173	177	7	6	5
Total finance lease costs	245	243	242	212	215	217	33	29	25
Short-term lease costs (4)	8	9	9	8	8	8	—	—	—
Variable lease costs (4)	450	472	458	430	460	447	9	10	10
Total lease costs	$ 867	$ 842	$ 808	$ 763	$ 754	$ 725	$ 50	$ 51	$ 48

(1) Includes costs capitalized in PP&E.

(2) Includes $ 88 , $ 37 , and $ 21 related to PPAs in 2025, 2024 and 2023, respectively, at both Sempra and SDG&E.

(3) Included in O&M, except for $ 30 in each of 2025 and 2024 and $ 29 in 2023 at Sempra, and $ 29 in each of 2025 and 2024 and $ 28 in 2023 at SDG&E, and $ 1 at SoCalGas in each of 2025, 2024 and 2023, which is included in Depreciation and Amortization Expense.

(4) Short-term leases with variable lease costs are recorded and presented as variable lease costs.

Cash paid for amounts included in the measurement of lease liabilities and supplemental noncash information were as follows:

LESSEE INFORMATION ON THE CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Sempra			SDG&E			SoCalGas
	Years ended December 31,
	2025	2024	2023	2025	2024	2023	2025	2024	2023
Operating activities:
Cash paid for operating leases	$ 159	$ 112	$ 85	$ 114	$ 70	$ 46	$ 8	$ 12	$ 13
Cash paid for finance leases	161	163	167	154	158	162	7	6	5
Financing activities:
Cash paid for finance leases	69	66	60	43	42	40	26	24	20
Increase in operating lease obligations for ROU assets	386	520	143	319	474	134	60	—	—
Increase in finance lease obligations capitalized to PP&E	47	41	57	14	14	17	33	27	40

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The table below presents the maturity analysis of our lease liabilities and reconciliation to the present value of lease liabilities at December 31, 2025:

LESSEE MATURITY ANALYSIS OF LIABILITIES
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
	Operating leases (1)(2)	Finance leases	Operating leases (1)	Finance leases (3)	Operating leases	Finance leases
2026	$ 147	$ 229	$ 128	$ 198	$ 6	$ 31
2027	143	227	130	197	—	30
2028	143	220	125	195	5	25
2029	147	212	122	192	12	20
2030	147	202	121	187	12	15
Thereafter	1,078	1,561	780	1,546	161	15
Total undiscounted lease payments	1,805	2,651	1,406	2,515	196	136
Less: imputed interest	( 539 )	( 1,358 )	( 352 )	( 1,339 )	( 129 )	( 19 )
Total lease liabilities	1,266	1,293	1,054	1,176	67	117
Less: current lease liabilities	( 90 )	( 73 )	( 85 )	( 48 )	—	( 25 )
Long-term lease liabilities	$ 1,176	$ 1,220	$ 969	$ 1,128	$ 67	$ 92

(1) Includes $ 104 in each of 2026 through 2029, $ 105 in 2030, and $ 724 thereafter related to PPAs.

(2) Excludes $ 26 in each of 2026 and 2027, $ 25 in 2028, $ 24 in 2029, $ 20 in 2030, and $ 261 thereafter within the disposal group that is classified as held for sale.

(3) Substantially all amounts are related to PPAs.

Leases That Have Not Yet Commenced

SDG&E has 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 each of 2029 and 2030, and $ 66 million thereafter (through expiration in 2043).

SI Partners has a lease agreement for tugboat services for the PA LNG Phase 1 project that it expects will commence in 2027. SI Partners expects the future minimum lease payments to be $ 10 million in 2027, $ 12 million in each of 2028 through 2030, and $ 186 million thereafter (through expiration in 2047, exclusive of certain renewal options) and total future minimum fixed payments for operation and maintenance services to be $ 184 million.

Lessor Accounting

SI Partners is a lessor for certain of its natural gas and ethane pipelines, compressor stations, LPG storage facilities, a rail facility and refined products terminals, which we account for as operating or sales-type leases. These leases expire at various dates from 2026 through 2042.

Over the lease term, we monitor the underlying assets in operating leases for impairment, and we evaluate the net investment in sales-type leases for expected credit losses. SI Partners expects to continue to derive value from the underlying assets associated with its pipelines following the end of their respective lease terms based on the expected remaining useful life, expected market conditions and plans to re-market and re-contract the underlying assets.

Generally, we recognize operating lease income on a straight-line basis over the lease term, and sales-type lease income based on the effective interest method over the lease term. Certain of our leases contain rate adjustments or are based on foreign currency exchange rates that may result in lease payments received that vary in amount from one period to the next. In addition to minimum fixed payments, our refined products terminals receive variable lease payments for barrels delivered that exceed minimum delivery requirements.

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We provide information below for leases for which we are the lessor.

LESSOR INFORMATION (1)
(Dollars in millions)
	December 31,
	2024
Sempra – Assets subject to operating leases:
Property, plant and equipment:
Pipelines and storage	$ 1,313
Refined products terminals	623
Other	77
Total	2,013
Accumulated depreciation	( 605 )
Property, plant and equipment, net	$ 1,408

(1) At December 31, 2025, excludes total net property, plant and equipment subject to operating leases of $ 1,336 , which is included in Assets Held for Sale on the Sempra Consolidated Balance Sheet and is comprised of $ 1,320 in pipelines and storage, $ 628 in refined products terminals, $ 76 in other, and $ 688 in accumulated depreciation.

LESSOR INFORMATION ON THE CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra – Sales-type leases:
Interest income	$ 3	$ 5	$ 6
Total revenues from sales-type leases (1)	$ 3	$ 5	$ 6
Sempra – Operating leases:
Fixed lease payments	$ 362	$ 340	$ 321
Variable lease payments	24	38	34
Total revenues from operating leases (1)	$ 386	$ 378	$ 355
Depreciation expense	$ 53	$ 73	$ 62

(1) Included in Revenues: Energy-Related Businesses on the Sempra Consolidated Statements of Operations.

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CONTRACTUAL COMMITMENTS

Natural Gas Contracts

SoCalGas procures natural gas for both SDG&E’s and SoCalGas’ core customers in a combined portfolio. SoCalGas purchases natural gas under short-term and long-term contracts for this portfolio from various producing regions, including from Canada, the U.S. Rockies and the southwestern regions of the U.S. Purchases of natural gas are primarily priced based on published indices, which can be subject to volatility.

SoCalGas transports natural gas primarily under long-term firm and variable interstate pipeline capacity contracts that require the payment of fixed and variable tariffed and negotiated reservation charges to reserve firm and interruptible transportation rights. Commitments under these contracts expire at various dates through 2035.

Within our disposal group that is classified as held for sale, which we discuss in Note 6, SI Partners has various capacity agreements for natural gas storage and transportation that expire at various dates through 2059. SI Partners procures natural gas supply through both short-term and long-term contracts with payment terms that are either indexed to natural gas hubs or at fixed prices. Transportation costs on these agreements vary based on pipeline capacity.

Payments on our natural gas contracts could exceed the minimum commitment based on portfolio needs. At December 31, 2025, the future minimum payments under existing fixed price transportation contracts at SoCalGas are as follows:

FUTURE MINIMUM PAYMENTS
(Dollars in millions)
2026	$ 94
2027	78
2028	72
2029	60
2030	57
Thereafter	66
Total minimum payments	$ 427

At December 31, 2025, SI Partners’ future minimum payments under existing fixed price natural gas storage and transportation contracts of $ 99 million in 2026, $ 100 million in 2027, $ 86 million in 2028, $ 221 million in 2029, $ 263 million in 2030, and $ 4,454 million thereafter are within the disposal group that is classified as held for sale.

The net volumetric exposure and fair value of natural gas derivatives related to contracts with index-based payment terms are discussed in Notes 10 and 11, respectively.

Total payments under natural gas contracts and natural gas storage and transportation contracts as well as payments to meet additional portfolio needs at Sempra and SoCalGas were as follows:

PAYMENTS UNDER NATURAL GAS CONTRACTS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra	$ 1,284	$ 1,185	$ 4,030
SoCalGas	1,192	1,088	3,857

LNG Purchase Agreement

SI Partners has an SPA for the supply of LNG to the ECA Regas Facility, which is included within the disposal group that is classified as held for sale. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2026 to 2029. Although this agreement specifies a number of cargoes to be delivered, under its terms, the supplier may divert certain cargoes, which would reduce amounts paid under the agreement by SI Partners. Based on the assumption that all LNG cargoes under the agreement are delivered less those already confirmed to be diverted as of December 31, 2025, SI Partners expects LNG commitments to total $ 1,859 million with expected purchases of $ 389 million in 2026, $ 569 million in 2027, $ 553 million in 2028 and $ 348 million in 2029. Actual LNG purchases were approximately $ 7 million in 2025, $ 23 million in 2024 and $ 30 million in 2023.

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PPAs Not Accounted for as Leases

Payments on SDG&E’s PPAs could exceed the minimum commitments based on energy needs. These PPAs expire on various dates through 2043. At December 31, 2025, the future minimum payments under long-term PPAs for Sempra and SDG&E are as follows:

FUTURE MINIMUM PAYMENTS (1)
(Dollars in millions)
2026	$ 113
2027	117
2028	122
2029	123
2030	123
Thereafter	744
Total minimum payments	$ 1,342

(1) Excludes PPAs accounted for as operating leases and finance leases.

Payments on these contracts represent capacity charges and minimum energy and transmission purchases that exceed the minimum commitment. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. SDG&E estimates these variable payments to be $ 79 million in each of 2026 and 2027, $ 80 million in each of 2028 through 2030, and $ 361 million thereafter. Total fixed and variable payments under PPAs not accounted for as leases for Sempra and SDG&E were $ 312 million in 2025, $ 326 million in 2024 and $ 325 million in 2023.

Construction and Development Projects

Our total contractual commitments on various capital projects in progress at December 31, 2025 are approximately $ 200 million, requiring future payments of $ 126 million in 2026, $ 18 million in 2027, $ 15 million in 2028, $ 13 million in 2029, $ 2 million in 2030, and $ 26 million thereafter. The following is a summary of contractual commitments and contingencies related to such projects.

SDG&E

At December 31, 2025, SDG&E has commitments to make future payments of $ 184 million for construction projects that include:

▪ $ 93 million related to construction supply agreements

▪ $ 19 million related to spent fuel management at SONGS

▪ $ 72 million for infrastructure improvements for electric transmission and distribution systems

SDG&E expects future payments under these contractual commitments to be $ 126 million in 2026, $ 13 million in 2027, $ 10 million in 2028, $ 7 million in 2029, $ 2 million in 2030, and $ 26 million thereafter.

SoCalGas

At December 31, 2025, SoCalGas has commitments to make future payments of $ 16 million for an information technology software project. SoCalGas expects future payments under this contractual commitment to be $ 5 million in each of 2027 and 2028, and $ 6 million in 2029.

OTHER COMMITMENTS

SDG&E

We discuss nuclear insurance and nuclear fuel disposal related to SONGS in Note 15.

Fire Mitigation Fund

In connection with the completion of the Sunrise Powerlink project in 2012, the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink. The future payments for these contractual commitments, for which a liability has been recorded, are expected to be $ 4 million in each of 2026 through 2030, and $ 260 million thereafter, subject to escalation of 2 % per year, ending in 2069. At December 31, 2025, the present value of these future payments of $ 125 million has been recorded as a regulatory asset as the amounts represent a cost that we expect will be recovered from customers in the future.

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Franchise Agreements

In July 2021, SDG&E’s natural gas and electric franchise agreements for the City of San Diego went into effect. These franchise agreements provide SDG&E the opportunity to serve the City of San Diego for a period of 20 years, consisting of 10 -year agreements that will automatically renew for an additional 10 years unless the City Council voids the automatic renewals. At December 31, 2025, SDG&E has commitments to make future principal and interest payments as consideration for the franchise agreements of $ 4 million in 2026, $ 2 million in each of 2027 through 2029, $ 14 million in 2030, and $ 30 million thereafter. The consideration paid will not be recovered from customers and will be amortized over 20 years.

ENVIRONMENTAL ISSUES

Our operations are subject to federal, state, regional, local, tribal and foreign environmental laws. We also are subject to regulations related to hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. These laws and regulations generally require that we investigate and correct the effects of the release or disposal of certain materials at sites associated with our past and our present operations. These sites include those at which we have been identified as a PRP under the federal Superfund laws and similar state laws.

In addition, we are required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate our businesses. The related costs of environmental monitoring, pollution control equipment, environmental safety practices, cleanup and other mitigation costs, and emissions fees and other payments are significant. Increasing national and international concerns regarding global warming and mercury, carbon dioxide, nitrogen oxide and sulfur dioxide emissions could increase these requirements in a manner that could adversely affect our businesses. Although SDG&E’s and SoCalGas’ costs to operate their facilities in compliance with these laws and regulations generally have been recovered in customer rates, this may not be the case in the future or with respect to all costs.

We disclose any proceeding under environmental laws to which a government authority is a party when the potential monetary sanctions, exclusive of interest and costs, exceed the lesser of $ 1 million or 1 % of current assets, which was $ 348 million for Sempra, $ 18 million for SDG&E and $ 19 million for SoCalGas at December 31, 2025.

Other Environmental Issues

We generally capitalize the significant costs we incur to mitigate or prevent future environmental contamination or extend the life, increase the capacity, or improve the safety or efficiency of property used in current operations. The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:

CAPITAL EXPENDITURES FOR ENVIRONMENTAL ISSUES
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Sempra	$ 63	$ 65	$ 107
SDG&E	24	23	29
SoCalGas	39	42	78

We have not identified any significant environmental issues outside the U.S.

At SDG&E and SoCalGas, costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.

The environmental issues currently facing us, except for those resolved during the last three years, include (1) investigation and remediation of SDG&E’s and SoCalGas’ manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by SDG&E and SoCalGas at which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS.

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The table below shows the status at December 31, 2025 of SDG&E’s and SoCalGas’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:

STATUS OF ENVIRONMENTAL SITES	# Sites complete (1)	# Sites in process
SDG&E:
Manufactured-gas sites	3	—
Third-party waste-disposal sites	2	1
SoCalGas:
Manufactured-gas sites	39	3
Third-party waste-disposal sites	5	2

(1) There may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.

We record environmental liabilities when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and cleanups proceed, we make adjustments as necessary.

The following table shows our accrued liabilities for environmental matters at December 31, 2025. Of the total liability, $ 18 million at SoCalGas is recorded on a discounted basis, with a weighted-average discount rate of 2.24 %.

ACCRUED LIABILITIES FOR ENVIRONMENTAL MATTERS
(Dollars in millions)
	Sempra (1)	SDG&E (1)	SoCalGas
Manufactured-gas sites	$ 39	$ —	$ 39
Waste disposal sites (PRP) (2)	8	5	3
Other hazardous waste sites	12	11	1
Total (3)	$ 59	$ 16	$ 43

(1) Excludes SDG&E’s liability for SONGS marine environment mitigation.

(2) Sites for which we have been identified as a PRP.

(3) Includes $ 3 , $ 1 , $ 2 classified as current liabilities and $ 56 , $ 15 and $ 41 classified as noncurrent liabilities on Sempra’s, SDG&E’s and SoCalGas’ Consolidated Balance Sheets, respectively.

We expect future payments related to our environmental liabilities on an undiscounted basis to be $ 3 million in 2026, $ 8 million in 2027, $ 8 million in 2028, $ 24 million in 2029, $ 1 million in 2030, and $ 19 million thereafter.

In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached an agreement with the California Coastal Commission to mitigate the damage to the marine environment caused by the cooling-water discharge from SONGS during its operation. SONGS’ early retirement, described in Note 15, does not impact SDG&E’s mitigation obligation under this agreement. SDG&E’s share of the estimated mitigation costs is $ 154 million, of which $ 57 million has been incurred through December 31, 2025 and $ 97 million is accrued for remaining costs through 2059, which is recoverable in rates and included in noncurrent Regulatory Assets on Sempra’s and SDG&E’s Consolidated Balance Sheets.

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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 December 31, 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 planned 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 the 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

▪ 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

▪ 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 11). At December 31, 2025, the fair value of the Support Agreement is $ 41 million, of which $ 8 million is included in Other Current Assets and $ 33 million is included in Other Long-Term Assets on Sempra’s Consolidated Balance Sheet.

This guarantee will remain with Sempra after the planned sale of a portion of our equity interest in SI Partners is complete, which we discuss in Note 6.

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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 December 31, 2025, SI Partners’ maximum exposure to loss under this off-balance sheet arrangement is $ 60 million.

This guarantee, if not yet terminated, will remain with SI Partners after the planned sale of a portion of our equity interest in SI Partners is complete, which we discuss in Note 6.

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NOTE 17. SEGMENT INFORMATION

SEMPRA

Sempra is a holding company whose principal businesses are regulated utilities in California and Texas. Our businesses invest in and operate electric and gas utilities and other energy infrastructure that provide energy 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, 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, constructs, 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, which is focused on safety, reliability and modernization of its segments’ infrastructure while supporting customer affordability; investing in incremental infrastructure growth projects with attractive risk-adjusted returns; maintaining a strong balance sheet; and returning cash to shareholders.

The accounting policies of the segments are consistent with those described in the summary of significant accounting policies in Note 1. Sempra accounts for intersegment sales as if the sales were to third parties, that is, at current market prices. The cost of common services shared by the reportable segments is assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Parent and other allocates depreciation expense to the reportable segments without allocating the related depreciable assets to those reportable segments. Interest income and interest expense are recorded on intersegment loans. We have eliminated intersegment accounts and transactions within Sempra’s consolidated financial statements. 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)
		December 31,
		2025	2024
ASSETS
Sempra California		$ 60,364	$ 56,116
Sempra Texas Utilities		17,733	15,534
Sempra Infrastructure		32,796	22,954
Segment totals		110,893	94,604
Parent and other		1,084	2,622
Intersegment eliminations (1)		( 1,099 )	( 1,071 )
Total Sempra		$ 110,878	$ 96,155
EQUITY METHOD INVESTMENTS
Sempra Texas Utilities		$ 17,601	$ 15,522
Sempra Infrastructure (2)		17	2,411
Segment totals/Total Sempra		$ 17,618	$ 17,933
GEOGRAPHIC LOCATION OF PROPERTY, PLANT AND EQUIPMENT, NET (3)
United States		$ 48,622	$ 52,952
Mexico		389	8,485
Total Sempra		$ 49,011	$ 61,437
	Years ended December 31,
	2025	2024	2023
CAPITAL EXPENDITURES FOR PROPERTY, PLANT AND EQUIPMENT
Sempra California	$ 4,543	$ 4,753	$ 4,560
Sempra Infrastructure	6,063	3,459	3,832
Segment totals	10,606	8,212	8,392
Parent and other	6	3	5
Total Sempra	$ 10,612	$ 8,215	$ 8,397
GEOGRAPHIC LOCATION OF REVENUES (4)
United States	$ 12,136	$ 11,623	$ 14,973
Mexico	1,566	1,562	1,747
Total Sempra	$ 13,702	$ 13,185	$ 16,720

(1) Primarily includes an intersegment loan from Sempra Infrastructure to Parent and other related to deferred income taxes.

(2) At December 31, 2025, $ 2,566 is included in Assets Held for Sale on the Sempra 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 16.

(3) At December 31, 2025, excludes total PP&E of $ 21,356 , which is included in Assets Held for Sale on the Sempra Consolidated Balance Sheet and is comprised of $ 12,724 in the United States and $ 8,632 in Mexico.

(4) Amounts are based on where the revenue originated, after intersegment eliminations.

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SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
	Sempra California	Sempra Texas Utilities (1)	Sempra Infrastructure	Sempra
	Year ended December 31, 2025
Revenues	$ 11,818		$ 1,965
Operation and maintenance	( 4,315 )		( 865 )
Depreciation and amortization	( 2,332 )		( 226 )
Interest income	8		66
Interest expense (2)	( 926 )		( 28 )
Income tax benefit (expense)	166		( 1,200 )
Equity earnings		$ 869	735
Earnings attributable to noncontrolling interests			( 238 )
Losses attributable to contingently redeemable noncontrolling interest			3
Other segment items (3)	( 2,991 )	( 8 )	( 372 )
Segment earnings (losses) attributable to common shares	$ 1,428	$ 861	$ ( 160 )	$ 2,129
Parent and other				( 333 )
Earnings attributable to common shares				$ 1,796
	Year ended December 31, 2024
Revenues	$ 11,382		$ 1,882
Operation and maintenance	( 4,398 )		( 858 )
Depreciation and amortization	( 2,133 )		( 297 )
Interest income	14		25
Interest expense (2)	( 848 )		243
Income tax (expense) benefit	( 184 )		164
Equity earnings		$ 788	802
Earnings attributable to noncontrolling interests			( 638 )
Other segment items (3)	( 1,987 )	( 7 )	( 412 )
Segment earnings attributable to common shares	$ 1,846	$ 781	$ 911	$ 3,538
Parent and other				( 721 )
Earnings attributable to common shares				$ 2,817
	Year ended December 31, 2023
Revenues	$ 13,761		$ 3,071
Operation and maintenance	( 4,591 )		( 793 )
Depreciation and amortization	( 1,937 )		( 281 )
Interest income	24		43
Interest expense	( 782 )		( 129 )
Income tax benefit (expense)	31		( 673 )
Equity earnings		$ 701	740
Earnings attributable to noncontrolling interests			( 543 )
Other segment items (3)	( 4,759 )	( 7 )	( 558 )
Segment earnings attributable to common shares	$ 1,747	$ 694	$ 877	$ 3,318
Parent and other				( 288 )
Earnings attributable to common shares				$ 3,030

(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, regulatory disallowances, franchise fees and other taxes, other income (expense), net, and preferred dividends for Sempra California; O&M, interest expense, and income tax (expense) benefit for Sempra Texas Utilities related to activities at the holding company; and cost of natural gas, energy-related businesses cost of sales, 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 California	Sempra Infrastructure	Sempra
	Year ended December 31, 2025
Revenues from external customers:
Utilities	$ 11,429	$ 78
Energy-related businesses	—	911
Total revenues from external customers (1)	11,429	989	$ 12,418
Other revenues (2) :
Utilities	364	—
Energy-related businesses	—	920
Total other revenues	364	920	1,284
Intersegment revenues (3) :
Utilities	25	—
Energy-related businesses	—	56
Total intersegment revenues	25	56	81
Segment revenues	$ 11,818	$ 1,965	13,783
Intersegment eliminations			( 81 )
Revenues			$ 13,702
	Year ended December 31, 2024
Revenues from external customers:
Utilities	$ 10,985	$ 78
Energy-related businesses	—	755
Total revenues from external customers (1)	10,985	833	$ 11,818
Other revenues (2) :
Utilities	374	—
Energy-related businesses	—	993
Total other revenues	374	993	1,367
Intersegment revenues (3) :
Utilities	23	—
Energy-related businesses	—	56
Total intersegment revenues	23	56	79
Segment revenues	$ 11,382	$ 1,882	13,264
Intersegment eliminations			( 79 )
Revenues			$ 13,185
	Year ended December 31, 2023
Revenues from external customers:
Utilities	$ 13,668	$ 87
Energy-related businesses	—	1,094
Total revenues from external customers (1)	13,668	1,181	$ 14,849
Other revenues (2) :
Utilities	75	—
Energy-related businesses	—	1,796
Total other revenues	75	1,796	1,871
Intersegment revenues (3) :
Utilities	18	—
Energy-related businesses	—	94
Total intersegment revenues	18	94	112
Segment revenues	$ 13,761	$ 3,071	16,832
Intersegment eliminations			( 112 )
Revenues			$ 16,720

(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 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 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 allocates resources to support the delivery of safe, reliable and affordable energy to customers. SDG&E’s CODM was previously its chief executive officer.

Total assets at SDG&E were $ 32.7 billion and $ 30.8 billion at December 31, 2025 and 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)
	Years ended December 31,
	2025	2024	2023
SDG&E:
Revenues from external customers:
Electric	$ 4,122	$ 4,164	$ 4,750
Natural gas	1,043	878	1,204
Total revenues from external customers (1)	5,165	5,042	5,954
Other revenues (2) :
Electric	446	149	( 401 )
Natural gas	86	150	44
Total other revenues	532	299	( 357 )
Total revenues	5,697	5,341	5,597
Operation and maintenance	( 1,725 )	( 1,692 )	( 1,846 )
Depreciation and amortization	( 1,316 )	( 1,223 )	( 1,098 )
Interest income	2	5	15
Interest expense	( 559 )	( 525 )	( 497 )
Income tax benefit (expense)	128	( 153 )	26
Other segment items (3)	( 1,664 )	( 862 )	( 1,261 )
Earnings attributable to common shares	$ 563	$ 891	$ 936
Capital expenditures for property, plant and equipment	$ 2,427	$ 2,522	$ 2,540

(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 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, regulatory disallowances, 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, who is its chief executive officer, utilizes earnings attributable to common shares to manage the business, assess performance and allocate resources. SoCalGas’ CODM allocates resources to support the delivery of safe, reliable and affordable energy to customers.

Total assets at SoCalGas were $ 27.7 billion and $ 25.4 billion at December 31, 2025 and 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)
	Years ended December 31,
	2025	2024	2023
SoCalGas:
Natural gas:
Revenues from external customers (1)	$ 6,459	$ 6,134	$ 7,857
Other revenues (2)	( 168 )	75	432
Total revenues	6,291	6,209	8,289
Operation and maintenance	( 2,689 )	( 2,791 )	( 2,821 )
Depreciation and amortization	( 1,016 )	( 910 )	( 839 )
Interest income	6	9	9
Interest expense	( 367 )	( 323 )	( 285 )
Income tax benefit (expense)	38	( 31 )	5
Other segment items (3)	( 1,398 )	( 1,208 )	( 3,547 )
Earnings attributable to common shares	$ 865	$ 955	$ 811
Capital expenditures for property, plant and equipment	$ 2,116	$ 2,231	$ 2,020

(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 for a description of this revenue source, which may be additive or subtractive from period to period.

(3) Includes cost of natural gas, franchise fees and other taxes, other income (expense), net, and preferred dividends.

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SCHEDULE I – SEMPRA
INDEX TO CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Statements of Operations for the years ended December 31, 2025 , 2024 and 2023	S-2
Condensed Statements of Comprehensive Income (Loss) for the years ended December 31, 2025 , 2024 and 2023	S-3
Condensed Balance Sheets at December 31, 2025 and 2024	S-4
Condensed Statements of Cash Flows for the years ended December 31, 2025 , 2024 and 2023	S-5
Notes to Condensed Financial Information of Parent
Note 1. Basis of Presentation	S-6
Note 2. New Accounting Standards	S-6
Note 3. Debt and Credit Facility	S-6
Note 4. Commitments and Contingencies	S-8

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SEMPRA
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Years ended December 31,
	2025	2024	2023
Interest income	$ 48	$ 29	$ 31
Interest expense	( 569 )	( 490 )	( 444 )
Operating expenses	( 129 )	( 105 )	( 101 )
Other income, net	45	25	31
Income tax benefit	196	165	134
Loss before equity in earnings of subsidiaries	( 409 )	( 376 )	( 349 )
Equity in earnings of subsidiaries, net of income taxes	2,245	3,237	3,423
Net income	1,836	2,861	3,074
Preferred deemed dividends	( 11 )	—	—
Preferred dividends	( 29 )	( 44 )	( 44 )
Earnings	$ 1,796	$ 2,817	$ 3,030
Basic EPS:
Earnings	$ 2.75	$ 4.44	$ 4.81
Weighted-average common shares outstanding	652,697	633,795	630,296
Diluted EPS:
Earnings	$ 2.75	$ 4.42	$ 4.79
Weighted-average common shares outstanding	653,826	637,943	632,733

See Notes to Condensed Financial Information of Parent.

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SEMPRA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Years ended December 31, 2025, 2024 and 2023
	Pretax amount	Income tax benefit (expense)	Net-of-tax amount
2025:
Net income	$ 1,640	$ 196	$ 1,836
Other comprehensive income (loss):
Foreign currency translation adjustments	21	—	21
Financial instruments	( 76 )	7	( 69 )
Pension and other postretirement benefits	19	( 2 )	17
Total other comprehensive loss	( 36 )	5	( 31 )
Comprehensive income	$ 1,604	$ 201	$ 1,805
2024:
Net income	$ 2,696	$ 165	$ 2,861
Other comprehensive income (loss):
Foreign currency translation adjustments	( 30 )	—	( 30 )
Financial instruments	14	( 2 )	12
Pension and other postretirement benefits	18	( 16 )	2
Total other comprehensive income (loss)	2	( 18 )	( 16 )
Comprehensive income	$ 2,698	$ 147	$ 2,845
2023:
Net income	$ 2,940	$ 134	$ 3,074
Other comprehensive income (loss):
Foreign currency translation adjustments	23	—	23
Financial instruments	57	( 18 )	39
Pension and other postretirement benefits	( 39 )	8	( 31 )
Total other comprehensive income	41	( 10 )	31
Comprehensive income	$ 2,981	$ 124	$ 3,105

See Notes to Condensed Financial Information of Parent.

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SEMPRA
CONDENSED BALANCE SHEETS
(Dollars in millions)
	December 31,
	2025	2024
Assets:
Cash and cash equivalents	$ 2	$ 1,416
Restricted cash	2	2
Due from affiliates	173	88
Income taxes receivable, net	—	71
Other current assets	23	10
Total current assets	200	1,587
Investments in subsidiaries	45,575	42,305
Due from affiliates	1,578	25
Deferred income taxes	135	209
Other long-term assets	1,199	1,152
Total assets	$ 48,687	$ 45,278
Liabilities and shareholders’ equity:
Short-term debt	$ 2,732	$ —
Due to affiliates	199	241
Other current liabilities	1,260	1,410
Total current liabilities	4,191	1,651
Long-term debt	11,279	11,028
Due to affiliates	138	739
Deferred income taxes	825	—
Other long-term liabilities	660	638
Commitments and contingencies (Note 4)
Shareholders’ equity	31,594	31,222
Total liabilities and shareholders’ equity	$ 48,687	$ 45,278

See Notes to Condensed Financial Information of Parent.

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SEMPRA
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2025	2024	2023
Net cash provided by operating activities	$ 1,007	$ 120	$ 1,576
Expenditures for property, plant and equipment	( 6 )	( 3 )	( 5 )
Proceeds from sale of assets	—	—	2
Capital contributions to investees	( 831 )	( 933 )	( 1,749 )
Distributions from investments	351	9	108
Purchases of trust assets	( 105 )	( 63 )	( 78 )
Proceeds from sales of trust assets	124	68	69
Increase in loans to affiliates, net	( 1,553 )	( 117 )	( 90 )
Other	( 9 )	( 1 )	( 1 )
Net cash used in investing activities	( 2,029 )	( 1,040 )	( 1,744 )
Common dividends paid	( 1,603 )	( 1,499 )	( 1,483 )
Preferred dividends paid	( 40 )	( 44 )	( 44 )
Redemption of preferred stock	( 900 )	—	—
Issuances of common stock, net	32	1,219	145
Repurchases of common stock	( 58 )	( 43 )	( 32 )
Issuances of debt (maturities greater than 90 days)	2,550	3,695	1,918
Payments on debt (maturities greater than 90 days)	( 750 )	( 350 )	( 672 )
Increase (decrease) in short-term debt, net	982	( 365 )	( 89 )
(Decrease) increase in loans from affiliates, net	( 595 )	( 241 )	220
Other	( 10 )	( 38 )	( 10 )
Net cash (used in) provided by financing activities	( 392 )	2,334	( 47 )
Effect of exchange rate changes on cash, cash equivalents and restricted cash	—	( 1 )	—
(Decrease) increase in cash, cash equivalents and restricted cash	( 1,414 )	1,413	( 215 )
Cash, cash equivalents and restricted cash, January 1	1,418	5	220
Cash, cash equivalents and restricted cash, December 31	$ 4	$ 1,418	$ 5
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Accrued interest receivable capitalized to note receivable	$ 18	$ 17	$ 16
Change in equity related to allocation of interests, net of tax	1,089	—	—
Preferred deemed dividends	11	—	—
Preferred dividends declared but not paid	—	11	11
Common dividends declared but not paid	421	393	376
Common dividends issued in stock	52	54	—
Equitization of amounts due from affiliates	56	110	92

See Notes to Condensed Financial Information of Parent.

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NOTES TO CONDENSED FINANCIAL INFORMATION OF PARENT

NOTE 1. BASIS OF PRESENTATION

The condensed financial information of Sempra has been prepared in accordance with SEC Regulation S-X Rule 5-04 and Rule 12-04. We apply the same accounting policies as in the consolidated financial statements of Sempra, except that Sempra accounts for the earnings of its subsidiaries under the equity method in this unconsolidated financial information. This financial information should be read in conjunction with Sempra’s consolidated financial statements and the accompanying notes thereto included in this Form 10-K.

Sempra received cash dividends from its subsidiaries totaling $ 1.5 billion, $ 908 million and $ 1.9 billion in 2025, 2024 and 2023, respectively.

NOTE 2. NEW ACCOUNTING STANDARDS

We describe in Note 2 of the Notes to Consolidated Financial Statements recent pronouncements that have had or may have a significant effect on Sempra’s results of operations, financial condition, cash flows or disclosures.

NOTE 3. DEBT AND CREDIT FACILITY

SHORT-TERM DEBT

Committed Line of Credit

At December 31, 2025, Sempra had capacity of $ 4.0 billion under a committed line of credit that expires in October 2030, which provides liquidity and supports its commercial paper program, with available unused credit of $ 3.0 billion before reductions of any unamortized discounts.

The principal terms of Sempra’s committed line of credit include the following:

▪ The facility has a syndicate of 23 lenders. No single lender has greater than a 6 % share in the facility.

▪ The facility provides for the issuance of $ 200 million of letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, Sempra has the right to increase its letter of credit commitment to up to $ 500 million. No letters of credit were outstanding at December 31, 2025.

▪ Borrowings bear interest at a benchmark rate plus a margin that varies with Sempra’s credit rating.

▪ Sempra must maintain a ratio of indebtedness to total capitalization (as defined in its credit facility) of no more than 65 % at the end of each quarter. At December 31, 2025, Sempra was in compliance with this ratio under its credit facility.

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LONG-TERM DEBT

The following table shows the detail and maturities of uncollateralized long-term debt outstanding.

LONG-TERM DEBT
(Dollars in millions)
	December 31,
	2025	2024
3.30 % Notes April 1, 2025	$ —	$ 750
5.40 % Notes August 1, 2026	550	550
3.25 % Notes June 15, 2027	750	750
3.40 % Notes February 1, 2028	1,000	1,000
3.70 % Notes April 1, 2029	500	500
5.50 % Notes August 1, 2033	700	700
3.80 % Notes February 1, 2038	1,000	1,000
6.00 % Notes October 15, 2039	750	750
4.00 % Notes February 1, 2048	800	800
4.125 % (next rate reset on April 1, 2027) Junior Subordinated Notes April 1, 2052 (1)	1,000	1,000
6.40 % (next rate reset on October 1, 2034) Junior Subordinated Notes October 1, 2054 (1)	1,250	1,250
6.875 % (next rate reset on October 1, 2029) Junior Subordinated Notes October 1, 2054 (1)	600	600
6.875 % (next rate reset on October 1, 2029) Junior Subordinated Notes October 1, 2054 (1)	500	500
6.55 % (next rate reset on April 1, 2035) Junior Subordinated Notes April 1, 2055 (1)	600	600
6.625 % (next rate reset on April 1, 2030) Junior Subordinated Notes April 1, 2055 (1)	400	400
6.375 % (next rate reset on April 1, 2031) Junior Subordinated Notes April 1, 2056 (1)	800	—
5.75 % Junior Subordinated Notes July 1, 2079 (1)	758	758
	11,958	11,908
Current portion of long-term debt	( 549 )	( 750 )
Unamortized discount on long-term debt	( 26 )	( 30 )
Unamortized debt issuance costs	( 104 )	( 100 )
Total long-term debt	$ 11,279	$ 11,028

(1) Callable long-term debt not subject to make-whole provisions.

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.

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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.

At December 31, 2025, scheduled maturities of Sempra’s long-term debt are $ 550 million in 2026, $ 750 million in 2027, $ 1.0 billion in 2028, $ 500 million in 2029, none in 2030, and $ 9.2 billion thereafter.

Additional information on Sempra’s short-term and long-term debt is provided in Note 7 of the Notes to Consolidated Financial Statements.

NOTE 4. COMMITMENTS AND CONTINGENCIES

At December 31, 2025 and 2024, Sempra had operating leases for real and personal property of $ 145 million and $ 150 million, respectively. Sempra expects undiscounted lease payments for its operating leases to be $ 12 million in 2026, $ 13 million in each of 2027 through 2030, and $ 139 million thereafter through 2040 for a total of $ 203 million. Operating lease costs were $ 14 million in each year ended December 31, 2025, 2024 and 2023, with a weighted-average discount rate of 4.67 % and 4.66 % at December 31, 2025 and 2024, respectively.

For other contingencies and guarantees related to Sempra, refer to Note 16 of the Notes to Consolidated Financial Statements.