SEMPRA (SRE)

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

This combined MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and the Notes thereto in this report, and the Consolidated Financial Statements and the Notes thereto, “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A” in the Annual Report.

Sempra has the following three reportable segments, which reflect how the CODM oversees operational and financial performance:

▪Sempra California

▪Sempra Texas Utilities

▪Sempra Infrastructure

SDG&E and SoCalGas each have one reportable segment.

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RESULTS OF OPERATIONS BY REGISTRANT

Throughout this MD&A, our references to earnings represent earnings attributable to common shares. Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates unless otherwise noted) and after NCI but before foreign currency and inflation effects, where applicable.

We discuss herein Sempra’s results of operations and significant changes in earnings, revenues and costs by segment, as well as Parent and other, in the three months ended March 31, 2026 compared to the same period in 2025. We also discuss herein the impact of foreign currency and inflation rates on Sempra’s results of operations.

RESULTS OF OPERATIONS

Sempra California

Sempra California’s earnings are comprised of SDG&E and SoCalGas. Because changes in SDG&E’s and SoCalGas’ cost of natural gas and/or electricity are recovered in rates, changes in these costs are offset in the changes in revenues and therefore do not impact earnings, other than potential impacts related to the GCIM for SoCalGas that we describe below. In addition to the changes in cost or market prices, natural gas or electric revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized amounts. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 4 of the Notes to Condensed Consolidated Financial Statements in this report and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

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In the three months ended March 31, 2026 compared to the same period in 2025, the decrease in earnings of $4 million (1%) was primarily due to:

▪$34 million lower income tax benefits primarily from flow-through items

▪$14 million higher net interest expense

Offset by:

▪$38 million higher CPUC base operating margin, net of operating expenses, including $43 million recognition of regulatory revenue reflecting returns on approved WMP capital projects resulting from the 2024 GRC Track 2 FD

▪$6 million regulatory award approved by the CPUC in 2026

Sempra Texas Utilities

In the three months ended March 31, 2026 compared to the same period in 2025, the increase in earnings of $25 million (17%) was primarily due to higher equity earnings from Oncor Holdings driven by:

▪overall higher revenues primarily attributable to:

◦the establishment of the UTM in June 2025 and the SRP

◦rate updates to reflect increases in invested capital

◦customer growth

Offset by:

◦lower customer consumption primarily attributable to weather

Offset by:

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

▪higher O&M

Sempra Infrastructure

In the three months ended March 31, 2026 compared to the same period in 2025, the increase in earnings of $116 million was primarily due to:

▪$58 million from asset and supply optimization driven by unrealized gains on commodity derivatives in 2026 compared to unrealized losses on commodity derivatives in 2025 due to changes in natural gas prices and higher optimization of transport and storage contracts

▪$36 million lower depreciation expense as a result of classifying SI Partners and Ecogas as held for sale in September 2025 and June 2025, respectively

▪$35 million net income tax benefit in 2026 as a result of classifying SI Partners and Ecogas as held for sale, comprised of the following:

◦$33 million net income tax benefit to adjust deferred income tax liabilities primarily related to outside basis differences in our investment in SI Partners

◦$2 million income tax benefit to adjust a Mexican deferred income tax liability on our outside basis difference in Ecogas

▪$12 million favorable impact from foreign currency and inflation effects on our monetary positions in Mexico and associated undesignated derivatives, comprised of a $19 million favorable impact in 2026 compared to a $7 million favorable impact in 2025

Offset by:

▪$11 million higher O&M from changes in provisions for expected credit losses

▪$9 million from revenues in 2025 driven by a contract modification in December 2024 on an LNG storage and regasification agreement that ended in December 2025

Parent and Other

In the three months ended March 31, 2026 compared to the same period in 2025, the increase in losses of $6 million (5%) was primarily due to:

▪$17 million higher net interest expense

▪$14 million unfavorable impact from $4 million net investment losses in 2026 compared to $10 million net investment gains in 2025 on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan

Offset by:

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

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SIGNIFICANT CHANGES IN REVENUES AND COSTS

The regulatory framework permits SDG&E and SoCalGas to recover certain program expenditures and other costs authorized by the CPUC (referred to as “refundable programs”), 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 Condensed Consolidated Statements of Operations.

SDG&E and SoCalGas operate under a regulatory framework that permits the cost of natural gas purchased for core customers to be passed through to customers in rates substantially as incurred and without markup. The GCIM provides for SoCalGas to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between SoCalGas and its core customers. We provide further discussion in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.

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

In the three months ended March 31, 2026 compared to the same period in 2025, Sempra’s natural gas revenues decreased by $337 million (14%) driven by Sempra California, which included:

▪$164 million lower regulatory revenues associated with refundable programs, which are fully offset in O&M

▪$155 million decrease in cost of natural gas sold, which we discuss below

▪$29 million lower regulatory revenues associated with the acceleration of self-developed software deductions, which are offset in income tax expense

▪$9 million lower regulatory revenues primarily from higher gas repairs tax benefits

Offset by:

▪$37 million higher CPUC-authorized base revenues

▪$8 million regulatory award approved by the CPUC in 2026

In the three months ended March 31, 2026 compared to the same period in 2025, Sempra’s cost of natural gas decreased by $158 million (32%) driven by Sempra California, which included:

▪$95 million lower volumes driven by weather

▪$60 million lower average natural gas prices

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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 Condensed Consolidated Statements of Operations.

SDG&E operates under a regulatory framework that permits it to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered or refunded in subsequent periods through rates.

Utility cost of electric fuel and purchased power includes utility-owned generation, power purchased from third parties, and net power purchases and sales to/from the California ISO.

(1)    Excludes depreciation and amortization, which are presented separately on Sempra’s Condensed Consolidat

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

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

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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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(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.

(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

(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

(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

(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.

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

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

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

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

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.

(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.

Long-Term Debt Activities

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

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.

(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.”

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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.

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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.

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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.

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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.

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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.

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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.

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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.

(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.

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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.

(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.

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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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:

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%.

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:

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.