filings.toolsItem 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
| Page | |||||
| Overview | 88 | ||||
| Results of Operations by Registrant | 89 | ||||
| Sempra | 89 | ||||
| SDG&E | 101 | ||||
| SoCalGas | 104 | ||||
| Capital Resources and Liquidity | 107 | ||||
| Critical Accounting Estimates | 122 | ||||
| New Accounting Standards | 122 |
OVERVIEW
This combined MD&A includes the operational and financial results of the following three Registrants:
▪Sempra is a California-based holding company with energy infrastructure investments in North America. Our businesses invest in, develop and operate energy infrastructure, and provide electric and gas services to customers.
▪SDG&E is a regulated public utility that provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.
▪SoCalGas is a regulated public natural gas distribution utility, serving customers throughout most of Southern California and part of central California.
This combined MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and the Notes thereto in this report, and the Consolidated Financial Statements and the Notes thereto, “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A” in the Annual Report.
Sempra has the following three reportable segments, which reflect how the CODM oversees operational and financial performance:
▪Sempra California
▪Sempra Texas Utilities
▪Sempra Infrastructure
SDG&E and SoCalGas each has one reportable segment.
RESULTS OF OPERATIONS BY REGISTRANT
Throughout the 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 three months (Q2) and six months (YTD) ended June 30, 2025 compared to the same periods in 2024. We also discuss herein the impact of foreign currency and inflation rates on Sempra’s results of operations.
Due to the delay in the issuance of the CPUC’s FD in the SDG&E and SoCalGas 2024 GRC, Sempra California recorded revenues in the first three quarters of 2024 based on levels authorized for 2023 under the 2019 GRC. In December 2024, the CPUC approved an FD in the 2024 GRC, effective retroactive to January 1, 2024, for which Sempra California recorded the retroactive impacts in the fourth quarter of 2024. Sempra California’s authorized base revenues in the first half of 2025 are based on the revenues authorized for the 2024 test year plus the amount authorized for attrition for 2025. We provide additional information on the 2024 GRC FD in Note 4 of the Notes to Condensed Consolidated Financial Statements in this report and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
RESULTS OF OPERATIONS
| RESULTS OF OPERATIONS | ||||||||
| (Dollars and shares in millions, except per share amounts) |
| EARNINGS BY SEGMENT | |||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Sempra: | |||||||||||||||||||||||
| Sempra California | $ | 259 | $ | 316 | $ | 983 | $ | 898 | |||||||||||||||
| Sempra Texas Utilities | 208 | 202 | 354 | 385 | |||||||||||||||||||
| Sempra Infrastructure | 72 | 291 | 218 | 422 | |||||||||||||||||||
| Segment earnings attributable to common shares | 539 | 809 | 1,555 | 1,705 | |||||||||||||||||||
| Parent and other | (78) | (96) | (188) | (191) | |||||||||||||||||||
| Earnings attributable to common shares | $ | 461 | $ | 713 | $ | 1,367 | $ | 1,514 |
Sempra California
Sempra California’s earnings are comprised of SDG&E and SoCalGas. Because changes in SDG&E’s and SoCalGas’ cost of natural gas and/or electricity are recovered in rates, changes in these costs are offset in the changes in revenues and therefore do not impact earnings, other than potential impacts related to the GCIM for SoCalGas that we describe below. In addition to the changes in cost or market prices, natural gas or electric revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized amounts. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 4 of the Notes to Condensed Consolidated Financial Statements in this report and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
In the three months ended June 30, 2025 compared to the same period in 2024, the decrease in earnings of $57 million (18%) was primarily due to:
▪$25 million from disallowed regulatory recovery of COVID-19 costs
▪$20 million lower income tax benefits primarily from flow-through items, including gas repairs tax benefits, which in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$17 million higher net interest expense
▪$16 million lower CPUC base operating margin, net of operating expenses including higher depreciation and $9 million lower authorized cost of capital. In the first three quarters of 2024, Sempra California recorded CPUC-authorized base revenues based on 2023 authorized levels
Offset by:
▪$10 million regulatory award approved by the CPUC in 2025
▪$3 million higher electric transmission margin
▪$3 million higher AFUDC equity
In the six months ended June 30, 2025 compared to the same period in 2024, the increase in earnings of $85 million (9%) was primarily due to:
▪$72 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $22 million lower authorized cost of capital. In the first three quarters of 2024, Sempra California recorded CPUC-authorized base revenues based on 2023 authorized levels
▪$42 million higher income tax benefits primarily from flow-through items, including gas repairs tax benefits, which in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$10 million regulatory award approved by the CPUC in 2025
▪$4 million higher net regulatory interest income
▪$3 million higher electric transmission margin
▪$3 million higher AFUDC equity
Offset by:
▪$32 million higher net interest expense
▪$25 million from disallowed regulatory recovery of COVID-19 costs
Sempra Texas Utilities
In the three months ended June 30, 2025 compared to the same period in 2024, the increase in earnings of $6 million (3%) was primarily due to higher equity earnings from Oncor Holdings driven by:
▪overall higher revenues primarily attributable to:
◦rate updates to reflect increases in invested capital
◦increase due to Oncor’s SRP and the establishment of the UTM
◦customer growth
Offset by:
◦lower customer consumption primarily attributable to weather
Offset by:
▪higher interest expense and depreciation expense associated with increases in invested capital
▪higher O&M
In the six months ended June 30, 2025 compared to the same period in 2024, the decrease in earnings of $31 million (8%) was primarily due to lower equity earnings from Oncor Holdings driven by:
▪higher interest expense and depreciation expense associated with increases in invested capital
▪higher O&M
Offset by:
▪overall higher revenues primarily attributable to:
◦rate updates to reflect increases in invested capital
◦customer growth
◦increase due to Oncor’s SRP and the establishment of the UTM
◦higher customer consumption primarily attributable to weather
Offset by:
◦decreases in transmission billing units
Sempra Infrastructure
In the three months ended June 30, 2025 compared to the same period in 2024, the decrease in earnings of $219 million was primarily due to:
▪$251 million unfavorable impact from foreign currency and inflation effects on our monetary positions in Mexico, comprised of an $98 million unfavorable impact in 2025 compared to a $153 million favorable impact in 2024
▪$26 million income tax expense in 2025 due to the recognition of a Mexican deferred tax liability on our outside basis difference in Ecogas as a result of management’s decision to hold the asset for sale
Offset by:
▪$46 million from asset and supply optimization driven by unrealized gains in 2025 compared to unrealized losses in 2024 on commodity derivatives due to changes in natural gas prices and higher LNG diversion fees
▪$9 million higher revenues driven by satisfaction of performance obligations related to customer payments received in advance from a contract modification in December 2024 on an LNG storage and regasification agreement
In the six months ended June 30, 2025 compared to the same period in 2024, the decrease in earnings of $204 million (48%) was primarily due to:
▪$202 million unfavorable impact from foreign currency and inflation effects on our monetary positions in Mexico, comprised of an $90 million unfavorable impact in 2025 compared to a $112 million favorable impact in 2024
▪$26 million income tax expense in 2025 due to the recognition of a Mexican deferred tax liability on our outside basis difference in Ecogas as a result of management’s decision to hold the asset for sale
▪$15 million from TdM driven by unrealized losses in 2025 compared to unrealized gains in 2024 on commodity derivatives due to changes in power prices
▪$8 million interest expense from unrealized losses in 2025 on interest rate swaps related to the PA LNG Phase 1 project
▪$4 million from asset and supply optimization driven by lower optimization of transport and storage contracts offset by unrealized gains in 2025 compared to unrealized losses in 2024 on commodity derivatives due to changes in natural gas prices and higher LNG diversion fees
Offset by:
▪$17 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
▪$16 million lower O&M in 2025 from lower provisions for expected credit losses
▪$10 million interest income from a change in the fair value of the Support Agreement
▪$7 million higher revenues due to the commencement of commercial operations at Topolobampo marine terminal in June 2024
Parent and Other
In the three months ended June 30, 2025 compared to the same period in 2024, the decrease in losses of $18 million (19%) was primarily due to:
▪$16 million higher income tax benefit from the interim period application of an annual forecasted consolidated ETR
▪$15 million higher net investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan
▪$5 million related to settlement charges from our nonqualified pension plan in 2024
Offset by:
▪$23 million higher net interest expense
In the six months ended June 30, 2025 compared to the same period in 2024, the decrease in losses of $3 million (2%) was primarily due to:
▪$18 million higher income tax benefit from the interim period application of an annual forecasted consolidated ETR
▪$15 million higher net investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan
▪$5 million related to settlement charges from our nonqualified pension plan in 2024
Offset by:
▪$40 million higher net interest expense
SIGNIFICANT CHANGES IN REVENUES AND COSTS
The regulatory framework permits SDG&E and SoCalGas to recover certain program expenditures and other costs authorized by the CPUC (referred to as “refundable programs”).
Utilities: Natural Gas Revenues and Cost of Natural Gas
Our utilities revenues include natural gas revenues at Sempra California and Sempra Infrastructure, which includes Ecogas. Intercompany revenues are eliminated in Sempra’s Condensed Consolidated Statements of Operations.
SDG&E and SoCalGas operate under a regulatory framework that permits the cost of natural gas purchased for core customers to be passed through to customers in rates substantially as incurred and without markup. The GCIM provides for SoCalGas to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between SoCalGas and its core customers. We provide further discussion in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.
| UTILITIES: NATURAL GAS REVENUES AND COST OF NATURAL GAS | |||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Sempra: | |||||||||||||||||||||||
| Natural gas revenues: | |||||||||||||||||||||||
| Sempra California | $ | 1,458 | $ | 1,480 | $ | 3,799 | $ | 3,564 | |||||||||||||||
| Sempra Infrastructure | 18 | 18 | 44 | 48 | |||||||||||||||||||
| Segment totals | 1,476 | 1,498 | 3,843 | 3,612 | |||||||||||||||||||
| Eliminations and adjustments | (6) | (4) | (11) | (9) | |||||||||||||||||||
| Total | $ | 1,470 | $ | 1,494 | $ | 3,832 | $ | 3,603 | |||||||||||||||
| Cost of natural gas(1): | |||||||||||||||||||||||
| Sempra California | $ | 181 | $ | 136 | $ | 666 | $ | 680 | |||||||||||||||
| Sempra Infrastructure | 4 | 5 | 15 | 14 | |||||||||||||||||||
| Segment totals | 185 | 141 | 681 | 694 | |||||||||||||||||||
| Eliminations and adjustments | (2) | (4) | (5) | (3) | |||||||||||||||||||
| Total | $ | 183 | $ | 137 | $ | 676 | $ | 691 |
(1) Excludes depreciation and amortization, which are presented separately on Sempra’s Condensed Consolidated Statements of Operations.
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s natural gas revenues decreased by $24 million (2%) driven by Sempra California, which included:
▪$97 million lower revenues associated with refundable programs, which are fully offset in O&M
▪$70 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$29 million lower revenues from disallowed regulatory recovery of COVID-19 costs
▪$7 million lower regulatory revenues, including gas repairs tax benefits, which are offset in income tax expense. Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$3 million lower revenues associated with impacts resulting from changes in tax laws tracked in the income tax expense memorandum account
Offset by:
▪$129 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $8 million lower authorized cost of capital
▪$45 million increase in cost of natural gas sold, which we discuss below
▪$14 million regulatory award approved by the CPUC in 2025
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s cost of natural gas increased by $46 million (34%) driven by Sempra California, primarily due to higher average natural gas prices.
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s natural gas revenues increased by $229 million (6%) driven by Sempra California, which included:
▪$308 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $21 million lower authorized cost of capital
▪$66 million higher revenues associated with refundable programs, which are fully offset in O&M
▪$45 million higher regulatory revenues, including gas repairs tax benefits, which are offset in income tax expense. Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$14 million regulatory award approved by the CPUC in 2025
Offset by:
▪$141 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$29 million lower revenues from disallowed regulatory recovery of COVID-19 costs
▪$14 million decrease in cost of natural gas sold, which we discuss below
▪$11 million lower revenues associated with impacts resulting from changes in tax laws tracked in the income tax expense memorandum account
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s cost of natural gas decreased by $15 million (2%) driven by Sempra California, which included:
▪$25 million lower volumes driven by weather
Offset by:
▪$11 million higher average natural gas prices
Utilities: Electric Revenues and Cost of Electric Fuel and Purchased Power
Our utilities revenues include electric revenues at Sempra California, substantially all of which is at SDG&E. Intercompany revenues are eliminated in Sempra’s Condensed Consolidated Statements of Operations.
SDG&E operates under a regulatory framework that permits it to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered or refunded in subsequent periods through rates.
Utility cost of electric fuel and purchased power includes utility-owned generation, power purchased from third parties, and net power purchases and sales to/from the California ISO.
| UTILITIES: ELECTRIC REVENUES AND COST OF ELECTRIC FUEL AND PURCHASED POWER | |||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Sempra: | |||||||||||||||||||||||
| Electric revenues: | |||||||||||||||||||||||
| Sempra California | $ | 1,032 | $ | 1,145 | $ | 2,092 | $ | 2,202 | |||||||||||||||
| Eliminations and adjustments | (1) | (1) | (2) | (2) | |||||||||||||||||||
| Total | $ | 1,031 | $ | 1,144 | $ | 2,090 | $ | 2,200 | |||||||||||||||
| Cost of electric fuel and purchased power(1): | |||||||||||||||||||||||
| Sempra California | $ | 106 | $ | 175 | $ | 179 | $ | 282 | |||||||||||||||
| Eliminations and adjustments | (15) | (19) | (36) | (37) | |||||||||||||||||||
| Total | $ | 91 | $ | 156 | $ | 143 | $ | 245 |
(1) Excludes depreciation and amortization, which are presented separately on Sempra’s Condensed Consolidated Statements of Operations.
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s electric revenues decreased by $113 million (10%) driven by Sempra California, which included:
▪$69 million decrease in cost of electric fuel and purchased power, which we discuss below
▪$28 million lower revenues associated with refundable programs, which are fully offset in O&M
▪$23 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax (expense) benefit
Offset by:
▪$7 million higher revenues from transmission operations
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s cost of electric fuel and purchased power decreased by $65 million (42%) driven by Sempra California, which included:
▪$44 million lower purchased power primarily due to change in excess capacity sales and lower renewable energy costs
▪$24 million lower purchased power from the California ISO due to lower customer demand from departing load now served by CCAs
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s electric revenues decreased by $110 million (5%) driven by Sempra California, which included:
▪$103 million decrease in cost of electric fuel and purchased power, which we discuss below
▪$67 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax (expense) benefit
▪$11 million lower revenues associated with refundable programs, which are fully offset in O&M
Offset by:
▪$47 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $9 million lower authorized cost of capital
▪$14 million higher revenues from incremental and balanced capital projects offset by certain projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$13 million higher revenues from transmission operations
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s cost of electric fuel and purchased power decreased by $102 million (42%) driven by Sempra California, which included:
▪$73 million lower purchased power primarily due to change in excess capacity sales and lower renewable energy costs
▪$44 million lower purchased power from the California ISO due to lower customer demand from departing load now served by CCAs
Offset by:
▪$15 million lower sales to the California ISO due to decreased utility-owned generator availability
Energy-Related Businesses: Revenues and Cost of Sales
| ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES | |||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Sempra: | |||||||||||||||||||||||
| Revenues: | |||||||||||||||||||||||
| Sempra Infrastructure | $ | 512 | $ | 391 | $ | 912 | $ | 880 | |||||||||||||||
| Parent and other(1) | (13) | (18) | (32) | (32) | |||||||||||||||||||
| Total | $ | 499 | $ | 373 | $ | 880 | $ | 848 | |||||||||||||||
| Cost of sales(2): | |||||||||||||||||||||||
| Sempra Infrastructure | $ | 85 | $ | 54 | $ | 204 | $ | 163 |
(1) Includes eliminations of intercompany activity.
(2) Excludes depreciation and amortization, which are presented separately on Sempra’s Condensed Consolidated Statements of Operations.
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s revenues from energy-related businesses increased by $126 million (34%) primarily due to:
▪$104 million from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:
◦$60 million from $48 million unrealized gains in 2025 compared to $12 million unrealized losses in 2024 on commodity derivatives
◦$25 million primarily from higher natural gas prices
◦$12 million primarily from higher diversion fees due to higher natural gas prices
▪$18 million higher revenues driven by satisfaction of performance obligations related to customer payments received in advance from a contract modification in December 2024 on an LNG storage and regasification agreement
▪$9 million from TdM driven by higher volumes in 2025 from scheduled major maintenance in April 2024
▪$7 million higher revenues in 2025 due to the commencement of commercial operations at the Topolobampo marine terminal in June 2024
Offset by:
▪$11 million from lower power prices from solar generation assets and lower volumes from wind power generation assets
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s cost of sales from energy-related businesses increased by $31 million primarily due to $29 million higher natural gas purchases related to asset and supply optimization.
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s revenues from energy-related businesses increased by $32 million (4%) primarily due to:
▪$35 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
▪$14 million higher revenues in 2025 due to the commencement of commercial operations at the Topolobampo marine terminal in June 2024
▪$12 million from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:
◦$23 million from higher natural gas prices offset by lower volumes
◦$15 million lower unrealized losses on commodity derivatives
◦$12 million primarily from higher diversion fees due to higher natural gas prices
Offset by:
◦$38 million from lower optimization of transport and storage contracts primarily due to changes in natural gas prices
Offset by:
▪$11 million from lower power prices from solar generation assets and lower volumes from wind power generation assets
▪$7 million from TdM mainly due to lower volumes
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s cost of sales from energy-related businesses increased by $41 million (25%) primarily due to:
▪$43 million driven by higher natural gas purchases related to asset and supply optimization
Offset by:
▪$7 million at TdM driven by lower volumes offset by higher natural gas prices
Operation and Maintenance
| OPERATION AND MAINTENANCE | |||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Sempra: | |||||||||||||||||||||||
| Sempra California | $ | 1,000 | $ | 1,106 | $ | 2,175 | $ | 2,110 | |||||||||||||||
| Sempra Texas Utilities | 1 | 2 | 3 | 4 | |||||||||||||||||||
| Sempra Infrastructure | 213 | 209 | 387 | 398 | |||||||||||||||||||
| Segment totals | 1,214 | 1,317 | 2,565 | 2,512 | |||||||||||||||||||
| Parent and other(1) | 25 | 16 | 17 | 33 | |||||||||||||||||||
| Total | $ | 1,239 | $ | 1,333 | $ | 2,582 | $ | 2,545 |
(1) Includes eliminations of intercompany activity.
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s O&M decreased by $94 million (7%) primarily due to:
▪$106 million decrease at Sempra California due to:
◦$125 million lower expenses associated with refundable programs, which costs are recovered in revenue
Offset by:
◦$19 million higher non-refundable operating costs
Offset by:
▪$9 million increase at Parent and other primarily due to higher deferred compensation expense
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s O&M increased by $37 million (1%) primarily due to:
▪$65 million increase at Sempra California due to:
◦$55 million higher expenses associated with refundable programs, which costs are recovered in revenue
◦$10 million higher non-refundable operating costs
Offset by:
▪$16 million decrease at Parent and other primarily due to lower deferred compensation expense
▪$11 million decrease at Sempra Infrastructure due to:
◦$22 million from lower provisions for expected credit losses
Offset by:
◦$4 million higher development costs and certain non-capitalized expenses from projects under construction
Other Income, Net
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s other income, net, increased by $29 million to $59 million primarily due to:
▪$20 million higher investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan at Parent and other
▪$8 million higher AFUDC equity primarily at Sempra Infrastructure
▪$3 million higher net interest income on regulatory balancing accounts at Sempra California
Offset by:
▪$7 million reduction in regulatory interest from disallowed regulatory recovery of COVID-19 costs at Sempra California
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s other income, net, increased by $21 million (16%) to $150 million primarily due to:
▪$12 million higher AFUDC equity primarily at Sempra Infrastructure
▪$6 million higher net interest income on regulatory balancing accounts at Sempra California
▪$6 million higher investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan at Parent and other
▪$5 million gains in 2025 from impacts associated with interest rate and foreign exchange instruments and foreign currency transactions driven by other foreign currency transactional effects primarily at Sempra Infrastructure
Offset by:
▪$7 million reduction in regulatory interest from disallowed regulatory recovery of COVID-19 costs at Sempra California
Interest Income
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s interest income increased by $18 million to $48 million primarily due to a $14 million change in the fair value of the Support Agreement at Sempra Infrastructure.
Interest Expense
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s interest expense increased by $48 million (15%) to $359 million primarily due to:
▪$34 million at Parent and other from higher debt balances from debt issuances
▪$19 million at Sempra California from higher debt balances from debt issuances
Offset by:
▪$6 million at Sempra Infrastructure primarily from $9 million in unrealized gains in 2025 on interest rate swaps related to the PA LNG Phase 1 project
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s interest expense increased by $176 million (29%) to $792 million primarily due to:
▪$71 million at Sempra Infrastructure primarily from $56 million in unrealized losses in 2025 on interest rate swaps related to the PA LNG Phase 1 project
▪$65 million at Parent and other from higher debt balances from debt issuances offset by lower borrowings on commercial paper and higher capitalization of interest expense on projects under construction at Sempra Infrastructure
▪$39 million at Sempra California from higher debt balances from debt issuances
Income Taxes
| INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES | |||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Sempra: | |||||||||||||||||||||||
| Income tax expense (benefit) | $ | 172 | $ | (130) | $ | 229 | $ | 42 | |||||||||||||||
| Income before income taxes and equity earnings | $ | 298 | $ | 308 | $ | 949 | $ | 1,013 | |||||||||||||||
| Equity earnings, before income tax(1) | 169 | 160 | 310 | 294 | |||||||||||||||||||
| Pretax income | $ | 467 | $ | 468 | $ | 1,259 | $ | 1,307 | |||||||||||||||
| Effective income tax rate | 37 | % | (28) | % | 18 | % | 3 | % |
(1) We discuss how we recognize equity earnings in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
We report as part of our pretax results the income or loss attributable to NCI. However, we do not record income taxes for a portion of this income or loss, as some of our entities with NCI are currently treated as partnerships for U.S. income tax purposes, and thus we are only liable for income taxes on the portion of the earnings that are allocated to us. Our pretax income, however, includes 100% of these entities. If our entities with NCI grow, and if we continue to invest in such entities, the impact on our ETR may become more significant.
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra had an income tax expense in 2025 compared to an income tax benefit in 2024 primarily due to:
▪$308 million from $122 million income tax expense in 2025 compared to $186 million income tax benefit in 2024 from foreign currency and inflation effects on our monetary positions in Mexico
▪$38 million income tax expense in 2025 due to the recognition of a Mexican deferred tax liability on our outside basis difference in Ecogas as a result of management’s decision to hold the asset for sale
Offset by:
▪higher income tax benefit in 2025 from higher ITCs from standalone energy storage projects
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s income tax expense increased by $187 million primarily due to:
▪$245 million from $112 million income tax expense in 2025 compared to $133 million income tax benefit in 2024 from foreign currency and inflation effects on our monetary positions in Mexico
▪$38 million income tax expense in 2025 due to the recognition of a Mexican deferred tax liability on our outside basis difference in Ecogas as a result of management’s decision to hold the asset for sale
Offset by:
▪higher income tax benefit in 2025 from higher ITCs from standalone energy storage projects
▪higher income tax benefits from flow-through items
▪lower pretax income
We discuss the impact of foreign currency exchange rates and inflation on income taxes below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.” See Note 1 of the Notes to Condensed Consolidated Financial Statements in this report and Notes 1 and 7 of the Notes to Consolidated Financial Statements in the Annual Report for further details about our accounting for income taxes and items subject to flow-through treatment.
Equity Earnings
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s equity earnings decreased by $40 million (9%) to $393 million primarily due to:
▪$51 million at IMG due to income tax expense in 2025 compared to an income tax benefit in 2024 primarily from foreign currency and inflation effects
▪$5 million at TAG Norte due to income tax expense in 2025 compared to an income tax benefit in 2024 primarily from foreign currency and inflation effects offset by foreign currency gains in 2025 compared to foreign currency losses in 2024
Offset by:
▪$10 million at Cameron LNG JV primarily from higher maintenance revenues and lower interest expense
▪$7 million at Oncor Holdings driven by:
◦overall higher revenues primarily attributable to:
-
rate updates to reflect increases in invested capital
-
increase due to Oncor’s SRP and the establishment of the UTM
-
customer growth
Offset by:
- lower customer consumption primarily attributable to weather
Offset by:
◦higher interest expense and depreciation expense associated with increases in invested capital
◦higher O&M
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s equity earnings decreased by $63 million (8%) to $718 million primarily due to:
▪$50 million at IMG due to income tax expense in 2025 compared to an income tax benefit in 2024 primarily from foreign currency and inflation effects
▪$30 million at Oncor Holdings driven by:
◦higher interest expense and depreciation expense associated with increases in invested capital
◦higher O&M
Offset by:
◦overall higher revenues primarily attributable to:
-
rate updates to reflect increases in invested capital
-
customer growth
-
increase due to Oncor’s SRP and the establishment of the UTM
-
higher customer consumption primarily attributable to weather
Offset by:
- decreases in transmission billing units
Offset by:
▪$17 million at Cameron LNG JV primarily from higher maintenance revenues and lower interest expense
Earnings Attributable to Noncontrolling Interests
In the three months ended June 30, 2025 compared to the same period in 2024, Sempra’s earnings attributable to NCI decreased by $100 million to $46 million primarily due to a decrease in SI Partners subsidiaries’ net income driven by foreign currency and inflation effects on our monetary positions in Mexico.
In the six months ended June 30, 2025 compared to the same period in 2024, Sempra’s earnings attributable to NCI decreased by $167 million to $48 million primarily due to a decrease in SI Partners subsidiaries’ net income driven by foreign currency and inflation effects on our monetary positions in Mexico and unrealized losses in 2025 from interest rate swaps related to the PA LNG Phase 1 project.
IMPACT OF FOREIGN CURRENCY AND INFLATION RATES ON RESULTS OF OPERATIONS
Because our natural gas distribution utility in Mexico, Ecogas, uses its local currency as its functional currency, its revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra’s results of operations. We discuss further the impact of foreign currency and inflation rates on results of operations, including impacts on income taxes and related hedging activity, in “Part II – Item 7. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations” in the Annual Report.
Foreign Currency Translation
Any difference in average exchange rates used for the translation of income statement activity from year to year can cause a variance in Sempra’s comparative results of operations. In the three months and six months ended June 30, 2025 compared to the same periods in 2024, the change in our earnings as a result of foreign currency translation rates was negligible.
Transactional Impacts
Income statement activities at our foreign operations and their equity method investments are also impacted by transactional gains and losses, a summary of which is shown in the table below:
| TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION EFFECTS | |||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Total reported amounts | Transactional gains (losses) included in reported amounts | ||||||||||||||||||||||
| Three months ended June 30, | |||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Other income, net | $ | 59 | $ | 30 | $ | 1 | $ | (1) | |||||||||||||||
| Income tax (expense) benefit | (172) | 130 | (122) | 186 | |||||||||||||||||||
| Equity earnings | 393 | 433 | (25) | 38 | |||||||||||||||||||
| Net income | 519 | 871 | (146) | 223 | |||||||||||||||||||
| Earnings attributable to noncontrolling interests | (46) | (146) | 49 | (71) | |||||||||||||||||||
| Earnings attributable to common shares | 461 | 713 | (97) | 152 | |||||||||||||||||||
| Six months ended June 30, | |||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| Other income, net | $ | 150 | $ | 129 | $ | 5 | $ | — | |||||||||||||||
| Income tax (expense) benefit | (229) | (42) | (112) | 133 | |||||||||||||||||||
| Equity earnings | 718 | 781 | (27) | 30 | |||||||||||||||||||
| Net income | 1,438 | 1,752 | (134) | 163 | |||||||||||||||||||
| Earnings attributable to noncontrolling interests | (48) | (215) | 45 | (52) | |||||||||||||||||||
| Earnings attributable to common shares | 1,367 | 1,514 | (89) | 111 |
We discuss herein SDG&E’s results of operations and significant changes in earnings, revenues and costs for the three months (Q2) and six months (YTD) ended June 30, 2025 compared to the same period in 2024.
Due to the delay in the issuance of the CPUC’s FD in the SDG&E 2024 GRC, SDG&E recorded revenues in the first three quarters of 2024 based on levels authorized for 2023 under the 2019 GRC. In December 2024, the CPUC approved an FD in the 2024 GRC, effective retroactive to January 1, 2024, for which SDG&E recorded the retroactive impacts in the fourth quarter of 2024. SDG&E’s authorized base revenues for the first half of 2025 are based on the revenues authorized for the 2024 test year plus the amount authorized for attrition for 2025. We provide additional information on the 2024 GRC FD in Note 4 of the Notes to Condensed Consolidated Financial Statements in this report and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
RESULTS OF OPERATIONS
| RESULTS OF OPERATIONS | ||||||||
| (Dollars in millions) |
In the three months ended June 30, 2025 compared to the same period in 2024, the decrease in earnings of $11 million (6%) was primarily due to:
▪$16 million lower CPUC base operating margin, net of operating expenses including higher depreciation and $4 million lower authorized cost of capital. In the first three quarters of 2024, SDG&E recorded CPUC-authorized base revenues based on 2023 authorized levels
▪$8 million higher net interest expense
Offset by:
▪$4 million higher AFUDC equity
▪$3 million higher electric transmission margin
▪$3 million higher net regulatory interest income
In the six months ended June 30, 2025 compared to the same period in 2024, the increase in earnings of $47 million (11%) was primarily due to:
▪$34 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $9 million lower authorized cost of capital. In the first three quarters of 2024, SDG&E recorded CPUC-authorized base revenues based on 2023 authorized levels
▪$7 million higher income tax benefits primarily from flow-through items, including gas repairs tax benefits, which in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$6 million higher net regulatory interest income
▪$3 million higher electric transmission margin
▪$3 million higher AFUDC equity
Offset by:
▪$14 million higher net interest expense
SIGNIFICANT CHANGES IN REVENUES AND COSTS
Electric Revenues and Cost of Electric Fuel and Purchased Power
In the three months ended June 30, 2025 compared to the same period in 2024, SDG&E’s electric revenues decreased by $115 million (10%) to $1.0 billion primarily due to:
▪$69 million decrease in cost of electric fuel and purchased power, which we discuss below
▪$28 million lower revenues associated with refundable programs, which are fully offset in O&M
▪$23 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax expense
Offset by:
▪$7 million higher revenues from transmission operations
In the three months ended June 30, 2025 compared to the same period in 2024, SDG&E’s cost of electric fuel and purchased power decreased by $69 million (39%) to $106 million primarily due to:
▪$44 million lower purchased power primarily due to change in excess capacity sales and lower renewable energy costs
▪$24 million lower purchased power from the California ISO due to lower customer demand from departing load now served by CCAs
In the six months ended June 30, 2025 compared to the same period in 2024, SDG&E’s electric revenues decreased by $111 million (5%) to $2.1 billion primarily due to:
▪$103 million decrease in cost of electric fuel and purchased power, which we discuss below
▪$67 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax expense
▪$11 million lower revenues associated with refundable programs, which are fully offset in O&M
Offset by:
▪$47 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $9 million lower authorized cost of capital
▪$14 million higher revenues from incremental and balanced capital projects offset by certain projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$13 million higher revenues from transmission operations
In the six months ended June 30, 2025 compared to the same period in 2024, SDG&E’s cost of electric fuel and purchased power decreased by $103 million (37%) to $179 million primarily due to:
▪$73 million lower purchased power primarily due to change in excess capacity sales and lower renewable energy costs
▪$44 million lower purchased power from the California ISO due to lower customer demand from departing load now served by CCAs
Offset by:
▪$15 million lower sales to the California ISO due to decreased utility-owned generator availability
Natural Gas Revenues and Cost of Natural Gas
In the three months ended June 30, 2025 and 2024, SDG&E’s average cost of natural gas per thousand cubic feet was $4.60 and $3.53, respectively. In the six months ended June 30, 2025 and 2024, SDG&E’s average cost of natural gas per thousand cubic feet was $4.86 and $5.08, respectively. The average cost of natural gas sold at SDG&E is impacted by market prices, as well as transportation, tariff and other charges.
In the three months ended June 30, 2025 compared to the same period in 2024, SDG&E’s natural gas revenues increased by $22 million (11%) to $228 million primarily due to:
▪$18 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $1 million lower authorized cost of capital
▪$7 million increase in cost of natural gas sold, which we discuss below
In the three months ended June 30, 2025 compared to the same period in 2024, SDG&E’s cost of natural gas increased by $7 million (19%) to $44 million primarily due to higher average natural gas prices.
In the six months ended June 30, 2025 compared to the same period in 2024, SDG&E’s natural gas revenues increased by $59 million (11%) to $584 million primarily due to:
▪$50 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $3 million lower authorized cost of capital
▪$19 million higher revenues associated with refundable programs, which are fully offset in O&M
▪$8 million higher regulatory revenues, including gas repairs tax benefits, which are offset in income tax expense. Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
Offset by:
▪$14 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$8 million decrease in cost of natural gas sold, which we discuss below
In the six months ended June 30, 2025 compared to the same period in 2024, SDG&E’s cost of natural gas decreased by $8 million (6%) to $131 million primarily due to lower average natural gas prices.
Operation and Maintenance
In the three months ended June 30, 2025 compared to the same period in 2024, SDG&E’s O&M decreased by $20 million (5%) to $403 million due to:
▪$26 million lower expenses associated with refundable programs, which costs are recovered in revenue
Offset by:
▪$6 million higher non-refundable operating costs
In the six months ended June 30, 2025 compared to the same period in 2024, SDG&E’s O&M increased by $9 million (1%) to $843 million primarily due to higher expenses associated with refundable programs, which costs are recovered in revenue.
Other Income, Net
In the three months ended June 30, 2025 compared to the same period in 2024, SDG&E’s other income, net, increased by $8 million (35%) to $31 million primarily due to:
▪$4 million higher net interest income on regulatory balancing accounts
▪$4 million higher AFUDC equity
In the six months ended June 30, 2025 compared to the same period in 2024, SDG&E’s other income, net, increased by $15 million (27%) to $71 million primarily due to:
▪$8 million higher net interest income on regulatory balancing accounts
▪$3 million higher AFUDC equity
Income Taxes
| INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES | |||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| SDG&E: | |||||||||||||||||||||||
| Income tax expense | $ | 7 | $ | 34 | $ | 21 | $ | 74 | |||||||||||||||
| Income before income taxes | $ | 182 | $ | 220 | $ | 477 | $ | 483 | |||||||||||||||
| Effective income tax rate | 4 | % | 15 | % | 4 | % | 15 | % |
SDG&E records regulatory liabilities for benefits that will be flowed through to customers in the future.
In the three months and six months ended June 30, 2025 compared to the same periods in 2024, SDG&E’s income tax expense decreased by $27 million and $53 million, respectively, primarily due to:
▪higher income tax benefit in 2025 from higher ITCs from standalone energy storage projects
▪lower pretax income
We discuss herein SoCalGas’ results of operations and significant changes in earnings, revenues and costs for the three months (Q2) and six months (YTD) ended June 30, 2025 compared to the same period in 2024.
Due to the delay in the issuance of the CPUC’s FD in the SoCalGas 2024 GRC, SoCalGas recorded revenues in the first three quarters of 2024 based on levels authorized for 2023 under the 2019 GRC. In December 2024, the CPUC approved an FD in the 2024 GRC, effective retroactive to January 1, 2024, for which SoCalGas recorded the retroactive impacts in the fourth quarter of 2024. SoCalGas’ authorized base revenues for the first half of 2025 are based on the revenues authorized for the 2024 test year plus the amount authorized for attrition for 2025. We provide additional information on the 2024 GRC FD in Note 4 of the Notes to Condensed Consolidated Financial Statements in this report and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
RESULTS OF OPERATIONS
| RESULTS OF OPERATIONS | ||||||||
| (Dollars in millions) |
In the three months ended June 30, 2025 compared to the same period in 2024, the decrease in earnings of $46 million (35%) was primarily due to:
▪$25 million from disallowed regulatory recovery of COVID-19 costs
▪$19 million lower income tax benefits primarily from flow-through items, including gas repairs tax benefits, which in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$9 million higher net interest expense
Offset by:
▪$10 million regulatory award approved by the CPUC in 2025
In the six months ended June 30, 2025 compared to the same period in 2024, the increase in earnings of $38 million (8%) was primarily due to:
▪$38 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $13 million lower authorized cost of capital. In the first three quarters of 2024, SoCalGas recorded CPUC-authorized base revenues based on 2023 authorized levels
▪$35 million higher income tax benefits primarily from flow-through items, including gas repairs tax benefits, which in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$10 million regulatory award approved by the CPUC in 2025
Offset by:
▪$25 million from disallowed regulatory recovery of COVID-19 costs
▪$18 million higher net interest expense
SIGNIFICANT CHANGES IN REVENUES AND COSTS
Natural Gas Revenues and Cost of Natural Gas
In the three months ended June 30, 2025 and 2024, SoCalGas’ average cost of natural gas per thousand cubic feet was $2.50 and $1.84, respectively. In the six months ended June 30, 2025 and 2024, SoCalGas’ average cost of natural gas per thousand cubic feet was $3.57 and $3.50, respectively. The average cost of natural gas sold at SoCalGas is impacted by market prices, as well as transportation and other charges.
In the three months ended June 30, 2025 compared to the same period in 2024, SoCalGas’ natural gas revenues decreased by $41 million (3%) remaining at $1.3 billion primarily due to:
▪$99 million lower revenues associated with refundable programs, which are fully offset in O&M
▪$68 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$29 million lower revenues from disallowed regulatory recovery of COVID-19 costs
▪$8 million lower regulatory revenues, including gas repairs tax benefits, which are offset in income tax expense. Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$3 million lower revenues associated with impacts resulting from changes in tax laws tracked in the income tax expense memorandum account
Offset by:
▪$111 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $7 million lower authorized cost of capital
▪$38 million increase in cost of natural gas sold, which we discuss below
▪$14 million regulatory award approved by the CPUC in 2025
In the three months ended June 30, 2025 compared to the same period in 2024, SoCalGas’ cost of natural gas increased by $38 million (33%) to $152 million primarily due to higher average natural gas prices.
In the six months ended June 30, 2025 compared to the same period in 2024, SoCalGas’ natural gas revenues increased by $174 million (6%) to $3.3 billion primarily due to:
▪$258 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $18 million lower authorized cost of capital
▪$47 million higher revenues associated with refundable programs, which are fully offset in O&M
▪$37 million higher regulatory revenues, including gas repairs tax benefits, which are offset in income tax expense. Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$14 million regulatory award approved by the CPUC in 2025
Offset by:
▪$127 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$29 million lower revenues from disallowed regulatory recovery of COVID-19 costs
▪$12 million decrease in cost of natural gas sold, which we discuss below
▪$11 million lower revenues associated with impacts resulting from changes in tax laws tracked in the income tax expense memorandum account
In the six months ended June 30, 2025 compared to the same period in 2024, SoCalGas’ cost of natural gas decreased by $12 million (2%) to $567 million primarily due to:
▪$23 million lower volumes driven by weather
Offset by:
▪$11 million higher average natural gas prices
Operation and Maintenance
In the three months ended June 30, 2025 compared to the same period in 2024, SoCalGas’ O&M decreased by $85 million (12%) to $622 million primarily due to:
▪$99 million lower expenses associated with refundable programs, which costs are recovered in revenue
Offset by:
▪$14 million higher non-refundable operating costs
In the six months ended June 30, 2025 compared to the same period in 2024, SoCalGas’ O&M increased by $59 million (4%) to $1.4 billion primarily due to:
▪$47 million higher expenses associated with refundable programs, which costs are recovered in revenue
▪$12 million higher non-refundable operating costs
Other (Expense) Income, Net
In the three months ended June 30, 2025 compared to the same period in 2024, SoCalGas had $2 million of other expense, net, in 2025 compared to $13 million of other income, net, in 2024 primarily due to:
▪$7 million reduction in regulatory interest from disallowed regulatory recovery of COVID-19 costs
▪$6 million higher non-service components of net periodic benefit cost
In the six months ended June 30, 2025 compared to the same period in 2024, SoCalGas’ other income, net, decreased by $20 million (33%) to $40 million primarily due:
▪$10 million decrease from a $6 million cost in 2025 compared to $4 million credit in 2024 for the non-service components of net periodic benefit cost
▪$7 million reduction in regulatory interest from disallowed regulatory recovery of COVID-19 costs
Income Taxes
| INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES | |||||||||||||||||||||||
| (Dollars in millions) | |||||||||||||||||||||||
| Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||
| SoCalGas: | |||||||||||||||||||||||
| Income tax expense | $ | 6 | $ | 10 | $ | 44 | $ | 53 | |||||||||||||||
| Income before income taxes | $ | 91 | $ | 141 | $ | 572 | $ | 543 | |||||||||||||||
| Effective income tax rate | 7 | % | 7 | % | 8 | % | 10 | % |
In the three months ended June 30, 2025 compared to the same period in 2024, SoCalGas’ income tax expense decreased by $4 million (40%) primarily due to lower pretax income.
In the six months ended June 30, 2025 compared to the same period in 2024, SoCalGas’ income tax expense decreased by $9 million (17%) primarily due to higher income tax benefit from flow-through items.
CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW
Sempra
Liquidity
We expect to meet our cash requirements through cash flows from operations, unrestricted cash and cash equivalents, borrowings under or supported by our credit facilities, other incurrences of debt which may include issuing debt securities and obtaining term loans, issuing equity securities under our ATM program or other offerings, funding from NCI owners, and selling assets or equity interests in our subsidiaries or development projects. We believe that these cash flow sources, combined with available funds, will be adequate to fund our operations in both the short-term and long-term, including to:
▪finance capital expenditures
▪repay debt
▪fund dividends
▪fund contractual and other obligations and otherwise meet liquidity requirements
▪fund capital contribution requirements
▪fund new business or asset acquisitions
Sempra, SDG&E and SoCalGas currently have reasonable access to the money markets and capital markets and are not currently constrained in their ability to borrow or otherwise raise money at market rates from commercial banks, under existing revolving credit facilities, through public offerings of debt or equity securities (including under our ATM program or other offerings), or through private placements of debt supported by our revolving credit facilities in the case of commercial paper. However, our ability to access these markets or obtain credit from commercial banks outside of our committed revolving credit facilities could become materially constrained if economic conditions worsen or disruptions to or volatility in these markets increase. In addition, our financing activities, actions by credit rating agencies and prevailing interest rates, as well as many other factors, could negatively affect the availability and cost of both short-term and long-term debt and equity financing. Also, cash flows from operations may be impacted by the timing and outcomes of regulatory proceedings, commencement and completion of, and potential cost overruns for, large projects and other material events. If cash flows from operations were to be significantly reduced or we were unable to borrow or obtain other financing under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety/reliability) and investments in new businesses. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our goal to maintain our investment-grade credit ratings.
ATM Program and Forward Sales Agreements
In November 2024, we established an ATM program providing for the offer and sale of shares of Sempra common stock having an aggregate gross sales price of up to $3.0 billion through agents acting as our sales agents or as forward sellers or directly to the agents as principals. The shares may be offered and sold in amounts and at times to be determined by us from time to time.
Since establishing the ATM program, an aggregate of 4,996,591 shares have been sold under the forward sale agreements described below with an average initial forward price of $83.175. Such average initial forward price is weighted to take into account the number of shares sold under each forward sale agreement.
In the fourth quarter of 2024, we entered into a forward sale agreement under the ATM program for the sale of 2,909,274 shares of Sempra common stock that remain subject to future settlement. At the initial forward price of $92.1546 per share, the net proceeds from this forward sale agreement if we elect full physical settlement would be approximately $268 million. At June 30, 2025, a total of 2,909,274 shares of Sempra common stock remain subject to future settlement under this forward sale agreement, which may be settled on one or more dates specified by us no later than June 30, 2026.
In the first quarter of 2025, we entered into a forward sale agreement under the ATM program for the sale of 2,087,317 shares of Sempra common stock that remain subject to future settlement. At the initial forward price of $70.6593 per share, the net proceeds from this forward sale agreement if we elect full physical settlement would be approximately $147 million. At June 30, 2025, a total of 2,087,317 shares of Sempra common stock remain subject to future settlement under this forward sale agreement, which may be settled on one or more dates specified by us no later than March 31, 2027.
We did not initially receive any proceeds from the sale of shares pursuant to the forward sale agreements. Although we may settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may, subject to certain conditions, elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements.
At June 30, 2025, approximately $2.6 billion of common stock remained available for sale under the ATM program.
We further discuss these activities, including the intended use of proceeds and effect on diluted EPS, in Note 10 of the Notes to Condensed Consolidated Financial Statements.
Available Funds
Our committed lines of credit provide liquidity and support commercial paper. Sempra, SDG&E and SoCalGas each has a committed line of credit expiring in 2029 and Sempra Infrastructure has four committed lines of credit expiring on various dates from 2025 through 2030, and an uncommitted line of credit expiring in 2026.
| AVAILABLE FUNDS AT JUNE 30, 2025 | |||||||||||||||||
| (Dollars in millions) | |||||||||||||||||
| Sempra | SDG&E | SoCalGas | |||||||||||||||
| Unrestricted cash and cash equivalents(1) | $ | 155 | $ | 28 | $ | — | |||||||||||
| Available unused credit(2) | 7,628 | 1,500 | 989 |
(1) Amounts at Sempra include $81 held in non-U.S. jurisdictions. We discuss repatriation in Note 7 of the Notes to Consolidated Financial Statements in the Annual Report.
(2) Available unused credit is the total available on committed and uncommitted lines of credit that we discuss in Note 7 of the Notes to Condensed Consolidated Financial Statements. Because our commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding and any letters of credit outstanding as a reduction to the available unused credit.
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 and lines of credit were our primary sources of short-term debt funding in the first six months of 2025.
We discuss our short-term debt activities in Note 7 of the Notes to Condensed Consolidated Financial Statements and below in “Sources and Uses of Cash.”
Long-Term Debt Activities
Significant issuances of and payments on long-term debt in the first six months of 2025 included the following:
| LONG-TERM DEBT ISSUANCES AND PAYMENTS | |||||||||||
| (Dollars in millions) | |||||||||||
| Issuances: | Amount at issuance | Maturity | |||||||||
| SDG&E 5.40% first mortgage bonds | $ | 850 | 2035 | ||||||||
| SoCalGas 5.45% first mortgage bonds | 600 | 2035 | |||||||||
| SoCalGas 6.00% first mortgage bonds | 500 | 2055 | |||||||||
| Sempra Infrastructure variable rate notes (ECA LNG Phase 1 project) | 125 | 2027 | |||||||||
| Sempra Infrastructure variable rate term loan (PA LNG Phase 1 project) | 1,542 | 2030 | |||||||||
| Sempra Infrastructure 6.27% senior secured notes (PA LNG Phase 1 project) | 750 | 2042 | |||||||||
| Sempra Infrastructure 6.32% senior secured notes (PA LNG Phase 1 project) | 250 | 2042 | |||||||||
| Payments: | Payments | Maturity | |||||||||
| SoCalGas 3.20% first mortgage bonds | $ | 350 | 2025 | ||||||||
| Sempra 3.30% notes | 750 | 2025 | |||||||||
| Sempra Infrastructure variable rate term loan (PA LNG Phase 1 project) | 983 | 2030 | |||||||||
| Sempra Infrastructure loan at variable rates (4.03% after floating-to-fixed rate swap effective 2019) payable June 15, 2022 through November 19, 2034 | 25 | 2034 |
We discuss our long-term debt activities, including the use of proceeds on long-term debt issuances, in Note 7 of the Notes to Condensed Consolidated Financial Statements.
Credit Ratings
We provide additional information about the credit ratings of Sempra, SDG&E and SoCalGas in “Part I – Item 1A. Risk Factors” and “Part II – Item 2. MD&A – Capital Resources and Liquidity” in the Annual Report.
The issuer credit ratings of Sempra, SDG&E and SoCalGas remained at investment grade levels in the first six months of 2025.
| ISSUER CREDIT RATINGS AT JUNE 30, 2025 | |||||||||||||||||
| Sempra | SDG&E | SoCalGas | |||||||||||||||
| Moody’s | Baa2 with a negative outlook | A3 with a stable outlook | A2 with a stable outlook | ||||||||||||||
| S&P | BBB+ with a negative outlook | BBB+ with a stable outlook | A- with a stable outlook | ||||||||||||||
| Fitch | BBB+ with a stable outlook | BBB+ with a stable outlook | A with a stable outlook |
A downgrade of Sempra’s or any of its subsidiaries’ credit ratings or rating outlooks may, depending on the severity, result in the imposition of new financial or other burdensome covenants or a requirement for collateral to be posted in the case of certain financing arrangements and may materially and adversely affect the market prices of their equity and debt securities, the rates at which borrowings are made and commercial paper is issued, and the various fees on their outstanding credit facilities. This could make it more costly for Sempra, SDG&E, SoCalGas and Sempra’s other subsidiaries to issue debt or equity securities, to borrow under credit facilities and to raise certain other types of financing. We provide additional information about our credit ratings at Sempra, SDG&E and SoCalGas in “Part I – Item 1A. Risk Factors” in the Annual Report.
Sempra has agreed that, if the credit rating of Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. Oncor’s senior secured debt was rated A2, A+ and A at Moody’s, S&P and Fitch, respectively, at June 30, 2025. On July 29, 2025, S&P downgraded Oncor’s senior secured debt rating from A+ to A and revised its outlook from negative to stable.
Loans due to/from Affiliates
At June 30, 2025, Sempra had $359 million in loans due to unconsolidated affiliates.
One Big Beautiful Bill Act
The OBBBA was signed into law on July 4, 2025. The OBBBA includes revisions to tax credits and incentives for energy and climate initiatives of the Inflation Reduction Act enacted in 2022 and extends or revises key provisions of the Tax Cuts and Jobs Act enacted in 2017, among other changes. The OBBBA leaves the U.S. corporate tax rate and the corporate alternative minimum tax rate unchanged at 21% and 15%, respectively. We will continue to assess the impacts of the OBBBA as the U.S. Department of the Treasury and the IRS issue guidance. We do not expect the OBBBA to have a material adverse effect on Sempra’s, SDG&E’s or SoCalGas’ results of operations, financial condition and/or cash flows.
Pillar Two
The Organization for Economic Cooperation and Development has introduced a framework known as “Pillar Two” to implement a global minimum effective tax rate of 15% in every jurisdiction (generally, every country) in which a company does business. Many aspects of the Pillar Two framework became effective beginning in 2024. While it is uncertain whether the U.S. or Mexico will enact legislation to adopt the Pillar Two framework, other countries are in the process of introducing and enacting legislation to implement Pillar Two. We do not currently expect the Pillar Two framework to have a material effect on Sempra’s, SDG&E’s or SoCalGas’ results of operations, financial condition and/or cash flows.
Sempra California
SDG&E’s and SoCalGas’ operations have historically provided relatively stable earnings and liquidity. Their future performance and liquidity will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by legislatures, litigation and the changing energy marketplace, as well as other matters described in this report and the Annual Report. SDG&E and SoCalGas expect that the available unused funds from their credit facilities described above, which also supports their commercial paper programs, cash flows from operations, and other incurrences of debt including issuing debt securities and obtaining term loans will continue to be adequate to fund their respective current operations and planned capital expenditures. SDG&E and SoCalGas manage their capital structures and pay dividends when appropriate and as approved by their respective boards of directors.
SDG&E and SoCalGas have regulatory mechanisms to recover credit losses and thus record changes in the allowances for credit losses related to Accounts Receivable – Trade that are probable of recovery in regulatory accounts. Although SDG&E and SoCalGas have regulatory mechanisms to recover credit losses, delay in payments by customers impacts the timing of their cash flows.
As we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements, changes in regulatory balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change between over- and undercollected status, may have a significant impact on cash flows. These changes generally represent the difference between when costs are incurred and when they are ultimately recovered or refunded in rates through billings to customers.
CPUC GRC
As we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements, in December 2024, the CPUC approved an FD in the 2024 GRC for SDG&E and SoCalGas that authorizes SDG&E’s and SoCalGas’ revenue requirements for 2024 and attrition year adjustments for 2025 through 2027, inclusively.
Since the GRC FD is effective retroactive to January 1, 2024, SDG&E and SoCalGas recorded the retroactive impacts in the fourth quarter of 2024. The incremental revenue requirements associated with the period from January 1, 2024 through January 31, 2025 are being recovered in rates over an 18-month period that began on February 1, 2025.
Existing and Anticipated Requests for Recovery of Specified Safety, Maintenance and Reliability Investments. The GRC also provides SDG&E and SoCalGas with numerous mechanisms to seek cost recovery of specified projects and programs. We expect that the requests for cost recovery of these projects and programs, which remain subject to CPUC approval, may result in additional amounts of authorized revenue requirement. These projects and programs include (i) the Track 2 and Track 3 requests that we describe below, (ii) the ability to file advice letters to implement the revenue requirements associated with the costs of SDG&E’s Moreno compressor station project and SoCalGas’ Honor Rancho compressor station and customer information system replacement projects, which projects were all approved by the CPUC subject to applicable cost caps, and (iii) the opportunity to file separate applications for cost recovery of mobile home park and gas integrity management programs at both SDG&E and SoCalGas, advanced metering infrastructure replacements at SDG&E, and other projects and programs.
2024 GRC Track 2. In October 2023, SDG&E submitted a separate request to the CPUC in its 2024 GRC, known as a Track 2 request. This request seeks review and recovery of $1.5 billion of wildfire mitigation plan costs incurred from 2019 through 2022 that were in addition to amounts authorized in the 2019 GRC and not addressed in the 2024 GRC FD. SDG&E expects to receive a proposed decision for its Track 2 request in the second half of 2025.
Revenue requirements associated with the Track 2 request have been recorded in a regulatory account. In February 2024, the CPUC approved an interim cost recovery mechanism that permits SDG&E to recover in rates $194 million and $96 million of this regulatory account balance in 2024 and 2025, respectively. Such recovery of SDG&E’s wildfire mitigation plan regulatory account balance will be subject to refund, contingent on the reasonableness review decision for its Track 2 request.
2024 GRC Track 3. In April 2025, SDG&E and SoCalGas each submitted additional requests to the CPUC in the 2024 GRC, known as Track 3 requests. SDG&E submitted a request seeking review and recovery of $417 million of its wildfire mitigation plan costs incurred in 2023 that were in addition to the amounts authorized in the 2019 GRC and not addressed in the 2024 GRC. Additionally, SDG&E and SoCalGas submitted a combined request seeking review and recovery of $240 million and $499 million, respectively, of PSEP costs incurred from 2014 through 2019 and 2015 through 2020, respectively. SDG&E and SoCalGas expect to receive proposed decisions for their Track 3 requests in the first half of 2026.
Revenue requirements associated with the Track 3 requests have been recorded in regulatory accounts. SDG&E and SoCalGas are authorized interim rate recovery of up to 50% of the recorded PSEP regulatory account balance at the end of each year. Such interim rate recovery is subject to refund, contingent on the reasonableness review decision for their Track 3 requests.
CPUC Cost of Capital
In March 2025, SDG&E and SoCalGas each filed applications with the CPUC seeking to update their cost of capital for 2026 through 2028, subject to the CCM. SDG&E and SoCalGas expect to receive an FD by the end of 2025. We further discuss the cost of capital and CCM in Note 4 of the Notes to Condensed Consolidated Financial Statements.
SDG&E
Wildfire Fund
We describe the Wildfire Legislation and SDG&E’s commitment to make annual shareholder contributions to the Wildfire Fund through 2028 in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
SDG&E is exposed to the risk that the participating California electric IOUs may incur third-party wildfire costs for which they will seek recovery from the Wildfire Fund with respect to wildfires that have occurred since enactment of the 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 Wildfire Fund could be completely exhausted due to fires in the other California electric IOUs’ service territories, by fires in SDG&E’s service territory or by a combination thereof, which would result in accelerated amortization of SDG&E’s Wildfire Fund asset. The carrying value of SDG&E’s Wildfire Fund asset totaled $269 million at June 30, 2025.
PG&E is seeking reimbursement from the Wildfire Fund for losses associated with the Dixie fire, which burned from July 2021 through October 2021. Although the cause of the LA Fires has not been determined, these fires may have a material adverse impact on the Wildfire Fund. Multiple lawsuits related to the Eaton fire have been initiated against Edison, and in July 2025, Edison announced that it is beginning a claims process for the Eaton fire in advance of a formal agency determination of the cause of the fire. Edison has disclosed that its equipment could have been associated with the ignition of the Eaton fire and that a liability is probable but not reasonably estimable.
If any California electric IOUs’ assets are determined to be a cause of fires, including fires of the size and scope of the LA Fires, payments of claims associated with those events could have a material adverse effect on the Wildfire Fund, including potentially exhausting the fund, and on SDG&E’s and Sempra’s financial condition and results of operations up to the carrying value of our Wildfire Fund asset, with additional potential material exposure if SDG&E’s equipment is determined to be a cause of a fire. Moreover, in the event that the Wildfire Fund is materially diminished, exhausted or terminated, SDG&E would lose the protection afforded by the Wildfire Fund, and as a consequence, a fire in SDG&E’s service territory could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.
FERC Rate Matters
SDG&E files separately with the FERC for its authorized transmission revenue requirement and ROE on FERC-regulated electric transmission operations and assets.
TO5 Settlement. SDG&E’s authorized TO5 settlement provided for an ROE of 10.60%, consisting of a base ROE of 10.10% plus the California ISO adder. In December 2024, the FERC issued an order, which SDG&E has appealed, finding that SDG&E is not eligible for the California ISO adder and that the TO5 adder refund provision had been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019.
TO6 Filing. In October 2024, SDG&E submitted its TO6 filing to the FERC and requested it to be effective January 1, 2025. SDG&E’s TO6 filing proposes, among other items, an increase to SDG&E’s currently authorized base ROE from 10.10% to 11.75% plus the California ISO adder, for a total ROE of 12.25%. In December 2024, the FERC accepted SDG&E’s TO6 filing, subject to refund; suspended the effective date to June 1, 2025; established hearing and settlement judge procedures; and disallowed the inclusion of the California ISO adder, the last of which SDG&E has appealed.
Off-Balance Sheet Arrangements
SDG&E has entered into PPAs and tolling agreements that are variable interests in unconsolidated entities. We discuss variable interests in Note 1 of the Notes to Condensed Consolidated Financial Statements.
SoCalGas
Catastrophic Events Cost Recovery
In July 2025, the CPUC issued an FD that authorizes partial recovery of costs recorded in SoCalGas’ Catastrophic Event Memorandum Account. The FD authorizes the recovery of $19 million out of the requested $55 million, denying recovery of COVID-19 costs included in the Catastrophic Event Memorandum Account. In the three months and six months ended June 30, 2025, SoCalGas recorded a write-off of $36 million ($25 million after tax) in disallowed costs, comprising a $29 million reduction in Utilities: Natural Gas Revenues and a $7 million reduction in regulatory interest in Other (Expense) Income, Net.
LA Fires
The LA Fires burned in SoCalGas’ service territory. The California Department of Forestry and Fire Protection estimated that the Palisades and Eaton fires damaged approximately 2,000 structures and destroyed approximately 16,200 structures. SoCalGas’ infrastructure in the fire-affected areas that is underground, which constitutes most of its infrastructure in these areas, remains undamaged by the fires and we believe safe to continue serving customers as they return to their homes and businesses. To date, natural gas service has been restored to almost 16,000 customers in the Eaton and Palisades fire areas, and crews will continue that work as customers return to their properties.
Aliso Canyon Natural Gas Storage Facility
Litigation. From October 23, 2015 through February 11, 2016, SoCalGas experienced the Leak, which we discuss in Note 12 of the Notes to Condensed Consolidated Financial Statements in this report and in “Part I – Item 1A. Risk Factors” in the Annual Report. As of August 4, 2025, there are approximately eight outstanding plaintiffs who have not entered into a settlement agreement. SoCalGas’ loss contingency accruals do not include any amounts in excess of what has been reasonably estimated to resolve these matters, nor any amounts that may be necessary to resolve threatened litigation, other potential litigation or other costs. We are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued, which could be significant and could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Operations and Reliability. Natural gas withdrawn from storage is important to help maintain service reliability during peak demand periods, including consumer heating needs in the winter and peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility is the largest SoCalGas storage facility and an important component of SoCalGas’ delivery system. Subject to future CPUC biennial reviews and potential additional proceedings, the CPUC determined that the Aliso Canyon natural gas storage facility is currently necessary for natural gas and electric reliability and affordable rates and authorized it to continue operating at a maximum working natural gas storage level of 68.6 bcf. The first biennial assessment from the CPUC, originally due in June 2025, has been granted an extension and is now due in August 2025.
Labor Relations
Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers Union of America or the International Chemical Workers Union Council. The collective bargaining agreement for these employees covering wages, hours, working conditions, and medical and other benefit plans was due to expire on September 30, 2024, but was extended by mutual agreement while SoCalGas and the unions continued negotiations. A new collective bargaining agreement was ratified on March 31, 2025 and is scheduled to expire on September 30, 2028.
Sempra Texas Utilities
Oncor relies on external financing as a significant source of liquidity for its capital requirements. In the event that Oncor fails to meet its capital requirements, access sufficient capital, or raise capital on favorable terms to finance its ongoing needs, we may elect to make additional capital contributions to Oncor (as our commitments to the PUCT prohibit us from making loans to Oncor), which could be substantial and reduce the cash available to us for other purposes, increase our indebtedness and ultimately materially adversely affect our results of operations, financial condition, cash flows and/or prospects. Oncor’s ability to make distributions may be limited by factors such as its credit ratings, regulatory capital requirements, increases in its capital plan, debt-to-equity ratio approved by the PUCT and other restrictions and considerations. In addition, Oncor will not make distributions if a majority of Oncor’s independent directors or any minority member director determines it is in the best interests of Oncor to retain such amounts to meet expected future requirements.
Oncor
2025 Comprehensive Base Rate Review. In June 2025, Oncor filed a request for a comprehensive base rate review with the PUCT and the 210 cities in its service territory that have retained original jurisdiction over rates. The base rate review test year is based on calendar year 2024 results with certain adjustments. The base rate review includes a request for an average increase over test year adjusted annualized revenue of approximately 13%, and if approved as requested, would result in an aggregate annualized revenue increase of approximately $834 million over current adjusted rates. The base rate review also requests a revised regulatory capital structure ratio of 55% debt to 45% equity, an authorized ROE of 10.55%, and a 4.94% authorized cost of debt. Oncor’s current authorized regulatory capital structure ratio is 57.5% debt to 42.5% equity, a 9.7% authorized ROE and 4.39% authorized cost of debt.
PUCT rules permit the filing of a request for interim rates while a base rate proceeding is pending. In July 2025, Oncor filed a request for an interim revenue requirement increase of $360 million over current adjusted rates, which excludes certain requested adjustments in the pending base rate proceeding, including the requested modifications to Oncor’s regulatory capital structure, authorized return on equity, and self-insurance reserve accrual. PUCT rules provide that interim rate relief may be granted upon the agreement of all parties to the proceeding, and that absent such agreement the administrative law judge administering the proceeding may grant interim rate relief upon a showing of good cause. If they become effective, such interim rates would be subject to refund or surcharge to the extent the rates ultimately established in the base rate proceeding are different from the interim rates.
Appeal of 2023 Comprehensive Base Rate Review Order. The PUCT issued a final order in Oncor’s comprehensive base rate proceeding in April 2023, and rates implementing that order went into effect on May 1, 2023. In June 2023, the PUCT issued an order on rehearing in response to the motions for rehearing filed by Oncor and certain intervening parties in the proceeding. The order on rehearing made certain technical and typographical corrections to the final order but otherwise affirmed the material provisions of the final order and did not require modification of the rates that went into effect on May 1, 2023. In September 2023, Oncor filed an appeal in Travis County District Court seeking judicial review of certain rate base disallowances and related expense effects of those disallowances in the PUCT’s order on rehearing. In February 2024, the court dismissed the appeal for lack of jurisdiction. In March 2024, Oncor appealed the court’s dismissal, which is currently with the Fifteenth Court of Appeals in Texas. Oral argument on the appeal was held on April 15, 2025.
Unified Tracker Mechanism. In June 2025, Texas House Bill 5247 was signed into law and became effective. The bill establishes what is known as the UTM, which creates an alternative method, available through 2035, for qualifying electric utilities to apply for interim rate adjustments once annually using a comprehensive regulatory filing for cost recovery of certain transmission and distribution capital expenditures.
A qualifying utility electing to use the UTM is permitted to defer all or a portion of the costs associated with its eligible transmission and distribution capital investments placed into service during the period covered by the UTM, including depreciation expense and carrying costs, as a regulatory asset. Texas House Bill 5247 provides that the PUCT must review a UTM filing within 120 days, and if a final order is not issued by the PUCT within 165 days after the UTM filing is submitted, the utility can place the requested rates into effect on a temporary basis and refund or credit against future customer bills any difference between such temporary rates and the final approved rates.
Oncor expects to make its first comprehensive UTM filing in the first half of 2026 with a view toward recovering the costs associated with eligible transmission and distribution investments that were placed into service after December 31, 2024 and that are not currently reflected in rates. In June 2025, Oncor 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 June 30, 2025, including depreciation expense, carrying costs on unrecovered balances and related taxes. Oncor expects to continue recognizing revenues and corresponding regulatory assets as UTM-eligible transmission and distribution capital investments are placed into service.
Sharyland Utilities
On May 1, 2025, Sharyland Utilities filed its 2025 rate case using a test year based on calendar year 2024 with certain adjustments. Sharyland Utilities is seeking a revenue requirement of $55 million, which is an approximately 14% increase over adjusted test-year revenues. Sharyland Utilities is also requesting a rate of return of 7.32%, which is based on a proposed capital structure ratio of 55% debt to 45% equity; a proposed ROE of 10.75%; and a proposed long-term cost of debt of 4.52%. On July 16, 2025, the PUCT filed direct testimony recommending a revenue requirement of $51 million and a rate of return of 6.49%, which is based on a capital structure ratio of 60% debt to 40% equity; an ROE of 9.45%; and a long-term cost of debt of 4.52%. Sharyland Utilities expects to receive an FD in the fourth quarter of 2025, with rates, if approved, going into effect in December 2025.
Off-Balance Sheet Arrangement
Our investment in Oncor Holdings is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to Condensed Consolidated Financial Statements.
Sempra Infrastructure
Sempra Infrastructure expects to fund capital expenditures, investments and operations in part with available funds, including existing credit facilities, and cash flows from operations from the Sempra Infrastructure businesses. We expect Sempra Infrastructure will require additional funding for the development and expansion of its portfolio of projects, which may be financed through a combination of funding from the parent and NCI owners, bank financing, issuances of debt, project financing, partnering in JVs and asset sales.
In the six months ended June 30, 2025 and 2024, Sempra Infrastructure distributed $91 million and $203 million, respectively, to its NCI owners, and NCI owners contributed $83 million and $786 million, respectively, to Sempra Infrastructure.
As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements, on March 28, 2025, we issued a notice to KKR Pinnacle and ADIA of our intent to pursue a process to sell a portion of our 70% equity interest in SI Partners. We expect to complete the sale in the second or third quarter of 2026, subject to reaching agreement on acceptable pricing and other terms, securing required regulatory and other approvals, finalizing definitive contracts and other factors and considerations.
Sempra Infrastructure is in various stages of development or construction of natural gas liquefaction projects, pipeline and terminal projects, and renewable power generation and sequestration projects, which we describe below. The successful development and/or construction of these projects is subject to numerous risks and uncertainties.
With respect to projects in development, these risks and uncertainties include, as applicable depending on the project, any failure to:
▪secure binding customer commitments
▪identify suitable project and equity partners
▪obtain sufficient financing
▪reach agreement with project partners or other applicable parties to proceed
▪obtain, modify, and/or maintain permits and regulatory approvals, including LNG export applications to non-FTA countries
▪negotiate, complete and maintain suitable commercial agreements, which may include EPC, tolling, equity acquisition, governance, LNG sales, gas supply and transportation contracts
▪reach a positive final investment decision
With respect to projects under construction, these risks and uncertainties include, in addition to the risks described above as applicable to each project, construction delays, unforeseen design flaws, cost overruns and other construction-related issues.
An unfavorable outcome with respect to any of these factors could have a material adverse effect on (i) the development and construction of the applicable project, including a potential impairment of all or a substantial portion of the capital costs invested in the project to date, which could be material, and (ii) for any project that has reached a positive final investment decision, Sempra’s results of operations, financial condition, cash flows and/or prospects. For a further discussion of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.
The descriptions below discuss several HOAs, MOUs and other non-binding development agreements with respect to Sempra Infrastructure’s various development projects. These arrangements do not commit any party to enter into definitive agreements or otherwise participate in the applicable project, and the ultimate participation by the parties remains subject to negotiation and finalization of definitive agreements, among other factors.
LNG
Cameron LNG Phase 2 Project. Cameron LNG JV is developing a proposed expansion project that would add one electric drive liquefaction train with an expected maximum production capacity of approximately 6.75 Mtpa and would increase the production capacity of the existing three trains at the Cameron LNG Phase 1 facility by up to approximately 1 Mtpa through debottlenecking activities. The Cameron LNG JV site can accommodate additional trains beyond the proposed Cameron LNG Phase 2 project.
Cameron LNG JV has received major permits, which have been amended to allow the use of electric drives for a one-train electric drive expansion along with other design enhancements, and FTA and non-FTA approvals associated with the potential expansion. The non-FTA approval for the proposed Cameron LNG Phase 2 project includes, among other things, a May 2026 deadline to commence commercial exports, for which we expect to request an extension.
Sempra Infrastructure and the other Cameron LNG JV members, namely affiliates of TotalEnergies SE, Mitsui & Co., Ltd. and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha, have entered into a non-binding HOA for the potential development of the Cameron LNG Phase 2 project. The non-binding HOA provides a commercial framework for the proposed project, including the contemplated allocation to SI Partners of 50.2% of the fourth train production capacity and 25% of the debottlenecking capacity from the project under tolling agreements. The non-binding HOA contemplates the remaining capacity to be allocated equally to the existing Cameron LNG Phase 1 facility customers.
Entergy Louisiana, LLC, a subsidiary of Entergy Corporation, and Cameron LNG JV have an electricity service agreement (and related ancillary agreements) for the supply to Cameron LNG JV of up to 950 MW of power from new renewable sources in Louisiana.
Cameron LNG JV concluded additional value engineering work on the proposed project in December 2024, which improved the overall anticipated value of the project and enabled evaluation of another potential EPC contractor. In collaboration with our partners, we continue to evaluate the results of this work as well as the full scope of the proposed project.
Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the members, including with respect to the equity investment obligation of each member. Expansion of the Cameron LNG Phase 1 facility beyond the first three trains is also subject to certain restrictions and conditions under the JV project financing agreements, including among others, scope restrictions on expansion of the project unless appropriate prior consent is obtained from the existing project lenders. A final investment decision remains subject to, among other things, securing these consents of the members and project lenders, satisfactory conclusion on the EPC process, negotiation and finalization of definitive offtake agreements and completion of all related financing and permitting activities.
ECA LNG Phase 1 Project. ECA LNG Phase 1 is constructing a one-train natural gas liquefaction facility at the site of Sempra Infrastructure’s existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa. We do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility. SI Partners owns an 83.4% interest in ECA LNG Phase 1, resulting in Sempra Infrastructure holding a 58.4% interest in the project. An affiliate of TotalEnergies SE owns the remaining 16.6% interest in the project.
We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the ECA LNG Phase 1 project. ECA LNG Phase 1 has definitive 20-year SPAs with an affiliate of TotalEnergies SE for approximately 1.7 Mtpa of LNG and with Mitsui & Co., Ltd. for approximately 0.8 Mtpa of LNG. The customers have a termination right if the ECA LNG Phase 1 project does not commence commercial operations under the SPAs by February 24, 2026, subject to certain additional conditions, for which we expect to request an extension if necessary.
We have an EPC contract with TP Oil & Gas Mexico, S. De R.L. De C.V., an affiliate of Technip Energies N.V., to construct the ECA LNG Phase 1 project. We estimate the total price of the EPC contract to be approximately $1.6 billion, with capital expenditures approximating $2.5 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. We expect the ECA LNG Phase 1 project to reach substantial completion in the spring of 2026 and begin generating revenues from cargoes around that time. We expect sales under the long-term SPAs to begin shortly thereafter in the summer of 2026 when the facility commences commercial operations.
ECA LNG Phase 1 has a loan agreement with a syndicate of external lenders that was set to mature in December 2025 and was originally for an aggregate principal amount of up to $1.3 billion. As we discuss in Note 7 of the Notes to Condensed Consolidated Financial Statements, in July 2025, ECA LNG Phase 1 amended the loan agreement, which included extending the maturity date to December 2027 and increasing the aggregate borrowing capacity to $1.5 billion. At June 30, 2025 and December 31, 2024, $1.2 billion and $1.1 billion, respectively, of borrowings were outstanding under the loan agreement, with a weighted-average interest rate of 7.28% and 7.29%, respectively. Proceeds from the loan are being used to finance the cost of construction of the ECA LNG Phase 1 project.
With respect to the ECA LNG Phase 1 and Phase 2 projects, recent and proposed changes to the Mexican Constitution and certain laws in Mexico and an unfavorable resolution of a land dispute and permit challenges, in each case that we discuss in Note 12 of the Notes to Condensed Consolidated Financial Statements, could have a material adverse effect on the development and construction of these projects.
ECA LNG Phase 2 Project. Sempra Infrastructure is developing a second, large-scale natural gas liquefaction project at the site of its existing ECA Regas Facility. We expect the proposed ECA LNG Phase 2 project to be comprised of two trains and one LNG storage tank and produce approximately 12 Mtpa of export capacity. The ECA Regas Facility currently has firm storage service agreements and nitrogen injection service agreements with Shell México Gas Natural, S. de R.L. de C.V. and SEFE Marketing & Trading México S. de R.L. de C.V. that expire in May 2028 and December 2025, respectively. We expect that future construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility to the extent those agreements have not expired or have 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.
We have non-binding MOUs and/or HOAs with Mitsui & Co., Ltd., an affiliate of TotalEnergies SE, and ConocoPhillips that provide a framework for their potential offtake of LNG from the proposed ECA LNG Phase 2 project and potential acquisition of an equity interest in ECA LNG Phase 2.
PA LNG Phase 1 Project. Sempra Infrastructure is constructing a natural gas liquefaction project on a greenfield site that it owns in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. The PA LNG Phase 1 project will consist of two liquefaction trains, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services with a nameplate capacity of approximately 13 Mtpa and an initial offtake capacity of approximately 10.5 Mtpa. SI Partners, KKR Denali and an affiliate of ConocoPhillips own a 28%, 42% and 30% interest, respectively, in the PA LNG Phase 1 project. Sempra Infrastructure holds a 19.6% interest in the project.
Sempra Infrastructure has received authorizations from the DOE that permit the LNG to be produced from the PA LNG Phase 1 project to be exported to all current and future FTA and non-FTA countries. In April 2019, the FERC approved the siting, construction and operation of the PA LNG Phase 1 project. Port Arthur LNG has received authorization from the FERC to increase its work force and implement a 24-hours-per-day construction schedule to further enhance construction efficiency while reducing temporal impacts to the community and environment in the vicinity of the project. The authorization provides the EPC contractor with more optionality to meet or exceed the project’s construction schedule.
The PA LNG Phase 1 project holds two Clean Air Act, Prevention of Significant Deterioration permits issued by the TCEQ, which we refer to as the “2016 Permit” and the “2022 Permit.” The 2022 Permit also governs emissions for the proposed PA LNG Phase 2 project. In November 2023, a panel of the U.S. Court of Appeals for the Fifth Circuit issued a decision to vacate and remand the 2022 Permit to the TCEQ for additional explanation of the agency’s permit decision. In February 2024, the court withdrew its opinion and referred the case to the Supreme Court of Texas to resolve the question of the appropriate standard to be applied by the TCEQ. In February 2025, the Supreme Court of Texas adopted Port Arthur LNG’s interpretation of the standard. Port Arthur LNG continues to litigate this matter before the U.S. Court of Appeals for the Fifth Circuit, which we expect will apply the standard adopted by the Supreme Court of Texas. The 2022 Permit is effective during the pending litigation. The 2016 Permit was not the subject of, and is unaffected by, the pending litigation of the 2022 Permit. Construction of the PA LNG Phase 1 project is proceeding uninterrupted under existing permits, and we do not currently anticipate the pending litigation to materially impact the PA LNG Phase 1 project cost, schedule or expected commercial operations at this stage.
Sempra Infrastructure has definitive SPAs for LNG offtake from the PA LNG Phase 1 project with:
▪an affiliate of ConocoPhillips for a 20-year term for 5 Mtpa of LNG, as well as a natural gas supply management agreement whereby an affiliate of ConocoPhillips will manage the feed gas supply requirements for the PA LNG Phase 1 project.
▪RWE Supply & Trading GmbH, a subsidiary of RWE AG, for a 15-year term for 2.25 Mtpa of LNG.
▪INEOS Energy Trading Limited, a subsidiary of INEOS Limited, for a 20-year term for approximately 1.4 Mtpa of LNG.
▪Polski Koncern Naftowy Orlen S.A. for a 20-year term for approximately 1 Mtpa of LNG.
▪ENGIE S.A. for a 15-year term for approximately 0.875 Mtpa of LNG.
We have an EPC contract with Bechtel to construct the PA LNG Phase 1 project, which has an estimated price of approximately $10.8 billion, including change orders contemplated in project contingency. Estimated capital expenditures for the PA LNG Phase 1 project remain unchanged at approximately $13 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ materially from our estimates, including as a result of the imposition of tariffs. We expect the first and second trains of the PA LNG Phase 1 project to commence commercial operations in 2027 and 2028, respectively.
As we discuss in Note 12 of the Notes to Condensed Consolidated Financial Statements, in April 2025, an incident occurred at the site of the PA LNG Phase 1 project that resulted in the deaths of three Bechtel employees and the injury of two Bechtel employees. OSHA opened inspections with respect to Bechtel and Sempra Infrastructure but has released the site. Bechtel is continuing construction of the PA LNG Phase 1 project while the cause of the incident remains under investigation. In connection with the incident, as of August 4, 2025, there are two complaints outstanding on behalf of 17 plaintiffs. We believe we are entitled to indemnification from Bechtel under Port Arthur LNG’s EPC contract with Bechtel with respect to this incident.
As we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements, SI Partners and ConocoPhillips have provided guarantees relating to their respective affiliate’s commitment to make its pro rata equity share of capital contributions to fund 110% of the development budget of the PA LNG Phase 1 project, in an aggregate amount of up to $9.0 billion. SI Partners’ guarantee covers 70% of this amount plus enforcement costs of its guarantee. As of June 30, 2025, an aggregate amount of $2.7 billion has been paid by SI Partners’ subsidiary in satisfaction of its commitment to fund its portion of the development budget of the PA LNG Phase 1 project.
Port Arthur LNG 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 June 30, 2025, $1.6 billion of borrowings were outstanding under the term loan facility agreement. Proceeds from the loan are being used to finance the cost of construction of the PA LNG Phase 1 project.
In January 2025, Port Arthur LNG issued senior secured notes for an aggregate principal amount of $750 million and received proceeds of $742 million (net of debt issuance costs of $8 million). In April 2025, Port Arthur LNG issued senior secured notes for an aggregate principal amount of $250 million and received proceeds of $248 million (net of debt issuance costs of $2 million). The notes mature in December 2042. The net proceeds were used to repay borrowings and accrued interest under the existing Port Arthur LNG term loan facility.
PA LNG Phase 2 Project. Sempra Infrastructure is developing a second phase of the Port Arthur natural gas liquefaction project that we expect will be a similar size to the PA LNG Phase 1 project. We are progressing the development of the proposed PA LNG Phase 2 project, while continuing to evaluate overall opportunities to develop the entirety of the Port Arthur site.
Sempra Infrastructure has received authorizations from the DOE that permit the export of LNG from the proposed PA LNG Phase 2 project to all current and future FTA and non-FTA countries. In September 2023, the FERC approved the siting, construction and operation of the proposed PA LNG Phase 2 project, which would include the addition of two liquefaction trains.
As we discuss above, a U.S. federal court previously issued and subsequently withdrew a decision that would have vacated and remanded the 2022 Permit authorizing emissions from the PA LNG Phase 1 and Phase 2 projects to the TCEQ for additional explanation of the agency’s permit decision. The U.S. Court of Appeals for the Fifth Circuit referred the case to the Supreme Court of Texas to resolve the question of the appropriate standard to be applied by the TCEQ. In February 2025, the Supreme Court of Texas adopted Port Arthur LNG’s interpretation of the standard. Port Arthur LNG continues to litigate this matter before the U.S. Court of Appeals for the Fifth Circuit, which will apply the standard adopted by the Supreme Court of Texas. The 2022 Permit is effective during the pending litigation.
Sempra Infrastructure has entered into a non-binding HOA for a 20-year SPA with Aramco International Gas Holding Co B.V. (Aramco) for 5 Mtpa of LNG offtake from the proposed PA LNG Phase 2 project. The HOA further contemplates Aramco’s 25% participation in the project-level equity of the PA LNG Phase 2 project. Additionally, in July 2025, Sempra Infrastructure entered into a definitive 20-year SPA with JERA Co. Inc. for 1.5 Mtpa of LNG offtake on a free-on-board basis from the proposed PA LNG Phase 2 project, subject to making a positive final investment decision and customary closing conditions.
In July 2024, Sempra Infrastructure entered into an $8.2 billion EPC contract with Bechtel for the proposed PA LNG Phase 2 project. The EPC contract contemplates the construction of two liquefaction trains capable of producing approximately 13 Mtpa, an additional LNG storage tank and marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services. In June 2025, we amended and restated the EPC contract to reflect an estimated price of approximately $8.7 billion, subject to adjustments. The price is subject to increase if certain limited notices to proceed and the full notice to proceed are not issued, each by specified dates. We have no obligation to move forward on the EPC contract, and we may release Bechtel to perform portions of the work pursuant to limited notices to proceed.
In June 2025, we issued a limited notice to proceed under the EPC contract, authorizing the performance of discrete portions of work, which is subject to a firm cancelation cap if the EPC contract is subsequently terminated prior to issuance of the full notice to proceed. We expect to work with Bechtel with respect to the ultimate timeline for the project and plan to fully release Bechtel to perform all the work to construct the PA LNG Phase 2 project only after we reach a final investment decision, which we are targeting in 2025, but which is subject to other conditions being met, including obtaining permits, executing definitive agreements for LNG offtake and equity investments, and securing construction funding for the project. Tariffs levied by the U.S. Administration introduce macroeconomic uncertainty, which may affect the business development efforts and timing of the PA LNG Phase 2 project.
Vista Pacifico LNG Liquefaction Project. Sempra Infrastructure is developing the Vista Pacifico LNG project, a mid-scale natural gas liquefaction export facility proposed to be located in the vicinity of the Port of Topolobampo in Sinaloa, Mexico. In June 2024, we extended the non-binding development agreement with the CFE through December 2025. We continue to progress with the CFE on the negotiation of definitive agreements, including a natural gas supply agreement. The proposed LNG export terminal would be supplied with U.S. natural gas and would use excess capacity on existing pipelines in Mexico with the intent of helping to meet growing demand for natural gas and LNG in the Mexican and Pacific markets.
Sempra Infrastructure received authorization from the DOE to permit the export of U.S.-produced natural gas to Mexico and for LNG produced from the proposed Vista Pacifico LNG facility to be re-exported to all current and future FTA countries and non-FTA countries.
In March 2022, TotalEnergies SE and Sempra Infrastructure entered into a non-binding MOU that contemplates TotalEnergies SE potentially contracting approximately one-third of the long-term export production of the proposed Vista Pacifico LNG project and potentially participating as a minority partner in the project.
Asset and Supply Optimization. As we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in the Annual Report, Sempra Infrastructure enters into hedging transactions to help mitigate commodity price risk and optimize the value of its LNG, natural gas pipelines and storage, and power-generating assets. Some of these derivatives that we use as economic hedges do not meet the requirements for hedge accounting, or hedge accounting is not elected, and as a result, the changes in fair value of these derivatives are recorded in earnings. Consequently, significant changes in commodity prices have in the past and could in the future result in earnings volatility, which may be material, as the economic offset of these derivatives may not be recorded at fair value.
Off-Balance Sheet Arrangements. Our investment in Cameron LNG JV is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to Condensed Consolidated Financial Statements.
In February 2025, SI Partners entered into a credit support agreement, which constitutes a guarantee, for the benefit of a third-party financial institution with a maximum exposure to loss of $85 million. The guarantee will terminate in May 2026. We discuss this guarantee in Note 12 of the Notes to Condensed Consolidated Financial Statements.
In June 2021, Sempra provided a promissory note, which constitutes a guarantee, for the benefit of Cameron LNG JV with a maximum exposure to loss of $165 million. The guarantee will terminate upon full repayment of Cameron LNG JV’s debt, scheduled to occur in 2039, or replenishment of the amount withdrawn by Sempra Infrastructure from the SDSRA. We discuss this guarantee in Note 12 of the Notes to Condensed Consolidated Financial Statements.
In July 2020, Sempra entered into a Support Agreement, which contains a guarantee and represents a variable interest, for the benefit of CFIN with a maximum exposure to loss of $979 million. The guarantee will terminate upon full repayment of the guaranteed debt by 2039, including repayment following an event in which the guaranteed debt is put to Sempra. We discuss this guarantee in Notes 1, 9 and 12 of the Notes to Condensed Consolidated Financial Statements.
Energy Networks
Ecogas. As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements, in June 2025, management committed to a formal plan to market and sell Ecogas, a natural gas regulated distribution utility that operates in three separate distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico. We expect to complete the sale in the second or third quarter of 2026. As a result of satisfying all applicable criteria, we classified Ecogas’ assets and liabilities as held for sale and ceased depreciation. Successful completion of a sale and the timing of such sale is subject to a number of risks and uncertainties, including reaching agreement on acceptable pricing and other terms, securing required regulatory and other approvals, finalizing definitive contracts and other factors and considerations.
Sonora Pipeline. Sempra Infrastructure’s Sonora natural gas pipeline consists of two pipeline segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. Following the start of commercial operations of the Guaymas-El Oro segment, Sempra Infrastructure reported damage to the pipeline in the Yaqui territory that has made that section inoperable since August 2017 because it was not able to be repaired due to legal challenges, which were resolved in March 2023, by some members of the Yaqui tribe.
In September 2019, Sempra Infrastructure and the CFE reached an agreement to modify the tariff structure and extend the term of the contract by 10 years. Under the revised agreement, the CFE will resume making payments only when the damaged section of the Guaymas-El Oro segment of the Sonora pipeline is back in service.
Sempra Infrastructure and the CFE have agreed to an amendment to their transportation services agreement and to re-route the portion of the pipeline that is in the Yaqui territory, whereby the CFE would pay for the re-routing with a new tariff. This amendment will terminate if certain conditions are not met, and Sempra Infrastructure retains the right to terminate the transportation services agreement and seek to recover its reasonable and documented costs and lost profit. Sempra Infrastructure continues to acquire and pursue the necessary rights-of-way and permits for the portion of the pipeline that needs to be re-routed.
The Guaymas-El Oro segment of the Sonora pipeline currently constitutes a Sole Risk Project under the terms of the SI Partners limited partnership agreement, which means that Sempra Infrastructure holds a 100% interest in the project. Sole Risk Projects are separated from other SI Partners projects and are conducted at Sempra’s sole cost, expense and liability and Sempra Infrastructure receives, through the acquisition of Sole Risk Interests, any economic and other benefits from such projects. At June 30, 2025, Sempra Infrastructure had $395 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.
Port Arthur Pipeline Louisiana Connector. Sempra Infrastructure is constructing the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana. In April 2019, the FERC approved the siting, construction and operation of the Port Arthur Pipeline Louisiana Connector, which will be used to supply feed gas to the PA LNG Phase 1 project. Sempra Infrastructure received FERC approval to implement construction process enhancements and minor modifications to several discrete sections of the Port Arthur Pipeline Louisiana Connector. These modifications are intended to decrease environmental impacts, accommodate landowner routing requests and enhance construction procedures. We expect the Port Arthur Pipeline Louisiana Connector to be ready for service ahead of the PA LNG Phase 1 project’s gas requirements. We estimate the capital expenditures for the project will be approximately $1 billion, including capitalized interest at the project level and project contingency. The actual amount of these capital expenditures may differ substantially from our estimates.
Louisiana Storage. Sempra Infrastructure is constructing Louisiana Storage, a 12.5-Bcf salt dome natural gas storage facility to support the PA LNG Phase 1 project. The construction includes an 11-mile pipeline that will connect to the Port Arthur Pipeline Louisiana Connector. In September 2022, the FERC approved the development of the project. We expect Louisiana Storage to be ready for service in time to support the needs of the PA LNG Phase 1 project. We estimate the capital expenditures for the project will be approximately $400 million, including capitalized interest at the project level and project contingency. The actual amount of these capital expenditures may differ substantially from our estimates.
Low Carbon Solutions
Cimarrón Wind. Sempra Infrastructure has made a positive final investment decision on and begun constructing the Cimarrón Wind project, an approximately 320-MW wind generation facility in Baja California, Mexico. Sempra Infrastructure has a 20-year PPA with Silicon Valley Power for the long-term supply of renewable energy to the City of Santa Clara, California. Cimarrón Wind will utilize one of Sempra Infrastructure’s existing cross-border high voltage transmission lines to interconnect and deliver clean energy to the East County substation in San Diego County. We estimate the capital expenditures for the project will be approximately $550 million, including capitalized interest at the project level and project contingency. The actual amount of these capital expenditures may differ substantially from our estimates. We expect the Cimarrón Wind project to begin generating energy in late 2025 and commence commercial operations in the first half of 2026.
Hackberry Carbon Sequestration Project. Sempra Infrastructure is developing the potential Hackberry Carbon Sequestration project near Hackberry, Louisiana, together with TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation. This proposed project is designed to permanently sequester carbon dioxide from the Cameron LNG Phase 1 facility, the proposed Cameron LNG Phase 2 project and potentially other sources. In April 2025, the Louisiana Department of Energy and Natural Resources (LDENR) issued a draft Class VI carbon injection well construction permit and held the required public hearing. We expect the LDENR to issue the final permit in 2025.
Legal and Regulatory Matters
See Note 12 of the Notes to Condensed Consolidated Financial Statements in this report and “Part I – Item 1A. Risk Factors” in the Annual Report for discussions of the following legal and regulatory matters affecting our operations in Mexico and risks associated with Mexican laws, policies and government influence:
Energía Costa Azul
▪Environmental and Social Impact Permits
One or more unfavorable final decisions on these land disputes or environmental and social impact permit challenges could materially adversely affect our existing natural gas regasification operations and proposed natural gas liquefaction projects at the site of the ECA Regas Facility and have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.
Regulatory and Other Actions by the Mexican Government
In 2021, the Mexican government amended the LIE and LH to empower Mexican regulators to, among other things, revoke or suspend permits under certain circumstances. In 2024, the Mexican government adopted changes to the Mexican Constitution to reinforce state control over strategic sectors by granting a central role to government entities like the CFE and PEMEX, which have been converted from for-profit state-owned enterprises into federal administrative agencies under SENER. Following these constitutional reforms, in March 2025, the Mexican government adopted energy-related laws (2025 Energy Laws), including the ESL, which repealed the LIE, and the HSL, which repealed the LH. The 2025 Energy Laws increase the government’s control and participation in the energy sector and may create novel challenges for infrastructure development and operations. Like the LIE and LH, the ESL and HSL give Mexican authorities broad discretion to revoke or suspend permits under certain circumstances.
Although the extent of the impact of the 2025 Energy Laws is uncertain, these laws and future implementation of regulations could adversely affect Sempra Infrastructure’s ability to operate its existing assets at their current levels, result in increased costs to Sempra Infrastructure and its customers, adversely impact Sempra Infrastructure’s ability to develop new projects in Mexico, result in decreased revenues and/or cash flows, and negatively impact Sempra Infrastructure’s ability to recover the carrying values of its investments in Mexico, any of which could have a material adverse impact on Sempra’s business, results of operations, financial condition, cash flow and/or prospects.
SOURCES AND USES OF CASH
The following tables include only significant changes in cash flow activities for each of the Registrants.
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
| Six months ended June 30, | Sempra | SDG&E | SoCalGas | |||||||||||||||||
| 2025 | $ | 2,266 | $ | 865 | $ | 1,142 | ||||||||||||||
| 2024 | 2,520 | 1,056 | 1,046 | |||||||||||||||||
| Change | $ | (254) | $ | (191) | $ | 96 | ||||||||||||||
| Change in accounts receivable | $ | (326) | $ | (184) | $ | (67) | ||||||||||||||
| Change in regulatory accounts, current and noncurrent | (255) | 48 | (303) | |||||||||||||||||
| Change in deferred excess capacity sales | (161) | (161) | ||||||||||||||||||
| (Lower) higher net income, adjusted for noncash items included in earnings | (57) | 31 | 6 | |||||||||||||||||
| Change in net margin posted, current and noncurrent | (42) | |||||||||||||||||||
| Change in inventories | (42) | (45) | ||||||||||||||||||
| Higher distributions from Cameron LNG JV | 29 | |||||||||||||||||||
| Change in GHG obligations, current and noncurrent | 52 | 71 | ||||||||||||||||||
| Change in GHG allowances, current and noncurrent | 62 | 58 | 50 | |||||||||||||||||
| Higher distributions from Oncor Holdings | 82 | |||||||||||||||||||
| Change in accrued franchise fees | 83 | 68 | 15 | |||||||||||||||||
| Change in fixed-price contracts and other derivatives, current and noncurrent | 149 | 155 | ||||||||||||||||||
| Change in accounts payable | 176 | 143 | ||||||||||||||||||
| Other | (4) | (6) | 26 | |||||||||||||||||
| $ | (254) | $ | (191) | $ | 96 |
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
| Six months ended June 30, | Sempra | SDG&E | SoCalGas | |||||||||||||||||
| 2025 | $ | (5,563) | $ | (1,240) | $ | (1,045) | ||||||||||||||
| 2024 | (4,168) | (1,206) | (978) | |||||||||||||||||
| Change | $ | (1,395) | $ | (34) | $ | (67) | ||||||||||||||
| Increase in capital expenditures | $ | (810) | $ | (36) | $ | (67) | ||||||||||||||
| Higher contributions to Oncor Holdings | (586) | |||||||||||||||||||
| Other | 1 | 2 | — | |||||||||||||||||
| $ | (1,395) | $ | (34) | $ | (67) |
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
| Six months ended June 30, | Sempra | SDG&E | SoCalGas | |||||||||||||||||
| 2025 | $ | 1,891 | $ | 403 | $ | (109) | ||||||||||||||
| 2024 | 1,618 | 166 | (60) | |||||||||||||||||
| Change | $ | 273 | $ | 237 | $ | (49) | ||||||||||||||
| Higher issuances of long-term debt | $ | 2,226 | $ | 254 | $ | 593 | ||||||||||||||
| Change in borrowings and repayments of short-term debt, net | 1,499 | (417) | 714 | |||||||||||||||||
| Lower distributions to NCI | 112 | |||||||||||||||||||
| Higher common dividends paid | (46) | |||||||||||||||||||
| Higher payments on short-term debt with maturities greater than 90 days | (510) | (700) | ||||||||||||||||||
| Lower issuances of short-term debt with maturities greater than 90 days | (580) | (300) | ||||||||||||||||||
| Lower contributions from NCI | (703) | |||||||||||||||||||
| (Higher) lower payments on long-term debt and finance leases | (1,704) | 401 | (352) | |||||||||||||||||
| Other | (21) | (1) | (4) | |||||||||||||||||
| $ | 273 | $ | 237 | $ | (49) |
Capital Expenditures for PP&E and Investments
| CAPITAL EXPENDITURES FOR PP&E AND INVESTMENTS | |||||||||||
| (Dollars in millions) | |||||||||||
| Six months ended June 30, | |||||||||||
| 2025 | 2024 | ||||||||||
| Sempra: | |||||||||||
| Sempra California(1) | $ | 2,315 | $ | 2,212 | |||||||
| Sempra Texas Utilities | 971 | 385 | |||||||||
| Sempra Infrastructure | 2,323 | 1,619 | |||||||||
| Segment totals | 5,609 | 4,216 | |||||||||
| Parent and other | 3 | 1 | |||||||||
| Total Sempra | $ | 5,612 | $ | 4,217 |
(1) Includes capital expenditures for PP&E of $1,270 and $1,234 at SDG&E and $1,045 and $978 at SoCalGas for 2025 and 2024, respectively.
We expect capital expenditures for PP&E and investments in 2025 to total $12.1 billion. When (i) including Sempra’s proportionate ownership interest in expected capital expenditures for PP&E at unconsolidated equity method investees while excluding Sempra’s expected capital contributions to those unconsolidated equity method investees and (ii) excluding NCI’s proportionate ownership interest in expected capital expenditures for PP&E at Sempra and at unconsolidated equity method investees, we expect capital expenditures for PP&E in 2025 to total $12.5 billion.
In addition, Oncor anticipates that its capital plan will grow over the 2025 through 2029 period, particularly in the latter years of its five-year capital plan, due to a variety of potential projects and developments, and that such incremental capital expenditures may exceed $12 billion over that period. Changes in Oncor’s capital expenditures plan could result in corresponding changes to our capital expenditures plan based on our ownership interest in Oncor.
Our level of capital expenditures for PP&E and investments will depend on, among other things, the cost and availability of financing, regulatory approvals, changes in tax law and business opportunities providing desirable rates of return, among various other factors described in this MD&A and in “Part I – Item 1A. Risk Factors” in the Annual Report. We aim to finance our capital expenditures for PP&E and investments in a manner that will maintain our investment-grade credit ratings and capital structure, but there is no guarantee that we will be able to do so.
CRITICAL ACCOUNTING ESTIMATES
Management views certain accounting estimates as critical because their application is the most relevant, judgmental and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss critical accounting estimates in “Part II – Item 7. MD&A” in the Annual Report.
NEW ACCOUNTING STANDARDS
We discuss any recent accounting pronouncements that have had or may have a significant effect on our financial statements and/or disclosures in Note 2 of the Notes to Condensed Consolidated Financial Statements.
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