Item 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

This combined MD&A for Sempra, SDG&E and SoCalGas 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.

OVERVIEW

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.

On August 2, 2023, Sempra’s board of directors declared a two-for-one split of Sempra’s common stock in the form of a 100% stock dividend for shareholders of record at the close of business on August 14, 2023. Sempra’s common stock began trading on a post-split basis effective August 22, 2023. All shares and per share information related to issued and outstanding common stock have been retroactively adjusted to reflect the stock split and are presented on a post-split basis herein.

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We are currently considering a resegmentation in which our SDG&E and SoCalGas segments would be combined into one segment, Sempra California, resulting in three reportable segments. We intend to complete our analysis in the fourth quarter of 2023 and, assuming a positive determination is made, we would implement the resegmentation in our annual report on Form 10-K for the period ending December 31, 2023.

RESULTS OF OPERATIONS

We discuss the following in Results of Operations:

▪Overall results of operations of Sempra;

▪Segment results;

▪Significant changes in revenues, costs and earnings; and

▪Impact of foreign currency and inflation rates on results of operations.

OVERALL RESULTS OF OPERATIONS OF SEMPRA

Sempra’s overall results of operations for the three months (Q3) and nine months (YTD) ended September 30, 2023 and 2022 were as follows:


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

178 179 180

Our earnings and diluted EPS were impacted by variances discussed below in “Segment Results.”

SEGMENT RESULTS

This section presents earnings (losses) by Sempra segment, as well as Parent and other, and a related discussion of the changes in segment earnings (losses). Throughout the MD&A, our reference to earnings represents earnings attributable to common shares. Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted, and before foreign currency and inflation effects and NCI, where applicable.


SEMPRA EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
SDG&E	$	274	$	271	$	716	$	681
SoCalGas	16		(82)		531		339
Sempra Texas Utilities	305		256		548		604
Sempra Infrastructure	223		114		746		392
Parent and other(1)	(97)		(74)		(248)		(360)
Earnings attributable to common shares	$	721	$	485	$	2,293	$	1,656

(1) Includes intercompany eliminations recorded in consolidation and certain corporate costs.

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SDG&E

The increase in earnings of $3 million (1%) in the three months ended September 30, 2023 compared to the same period in 2022 was primarily due to:

▪$11 million higher electric transmission margin;

▪$8 million higher CPUC base operating margin, net of operating expenses and $6 million from lower authorized cost of capital; and

▪$4 million higher net regulatory interest income; offset by

▪$13 million lower income tax benefit from the resolution of prior year income tax items; and

▪$6 million higher net interest expense.

The increase in earnings of $35 million (5%) in the nine months ended September 30, 2023 compared to the same period in 2022 was primarily due to:

▪$35 million higher CPUC base operating margin, net of operating expenses and $18 million from lower authorized cost of capital;

▪$16 million higher net regulatory interest income;

▪$12 million higher electric transmission margin; and

▪$12 million lower income tax expense primarily from flow-through items and lower associated regulatory revenues in 2022; offset by

▪$20 million higher net interest expense; and

▪$13 million lower income tax benefit from the resolution of prior year income tax items.

SoCalGas

Earnings of $16 million in the three months ended September 30, 2023 compared to losses of $82 million in the same period in 2022 were primarily due to:

▪$101 million charge in 2022 relating to litigation and regulatory matters pertaining to the Leak;

▪$11 million higher income tax benefits primarily from flow-through items; and

▪$4 million higher net regulatory interest income; offset by

▪$15 million higher net interest expense.

The increase in earnings of $192 million in the nine months ended September 30, 2023 compared to the same period in 2022 was primarily due to:

▪$199 million charge in 2022 relating to litigation and regulatory matters pertaining to the Leak;

▪$28 million higher income tax benefits primarily from flow-through items, which includes $25 million related to income tax benefits in 2023 for previously unrecognized income tax benefits pertaining to gas repairs expenditures;

▪$15 million higher net regulatory interest income;

▪$13 million higher regulatory awards approved by the CPUC; and

▪$10 million in penalties in 2022 related to energy efficiency and advocacy OSCs; offset by

▪$52 million higher net interest expense; and

▪$13 million lower CPUC base operating margin, net of operating expenses and $15 million from lower authorized cost of capital.

Sempra Texas Utilities

The increase in earnings of $49 million (19%) in the three months ended September 30, 2023 compared to the same period in 2022 was primarily due to higher equity earnings from Oncor Holdings driven by:

▪higher revenues attributable to:

◦higher customer consumption primarily attributable to weather,

◦updates to transmission billing factors,

◦new base rates implemented in May 2023,

◦interim rate updates to reflect increases in invested capital, and

◦customer growth; offset by

▪higher interest expense and depreciation expense attributable to invested capital; and

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▪higher O&M.

The decrease in earnings of $56 million (9%) in the nine months ended September 30, 2023 compared to the same period in 2022 was primarily due to lower equity earnings from Oncor Holdings driven by:

▪higher interest expense and depreciation expense attributable to invested capital;

▪write-off of rate base disallowances in 2023 resulting from the PUCT’s final order in Oncor’s comprehensive base rate review; and

▪higher O&M; offset by

▪higher revenues attributable to:

◦updates to transmission billing factors,

◦new base rates implemented in May 2023,

◦customer growth, and

◦interim rate updates to reflect increases in invested capital.

Sempra Infrastructure

The increase in earnings of $109 million in the three months ended September 30, 2023 compared to the same period in 2022 was primarily due to:

▪$50 million from asset and supply optimization driven by unrealized gains in 2023 compared to unrealized losses in 2022 on commodity derivatives due to changes in natural gas prices, offset by lower LNG diversion fees;

▪$50 million favorable impact from foreign currency and inflation effects on our monetary positions in Mexico, comprised of a $52 million favorable impact in 2023 compared to a $2 million favorable impact in 2022;

▪$21 million lower net interest expense due to higher capitalization of interest expense on projects under construction, offset by higher interest rates and borrowings on committed lines of credit;

▪$15 million net income tax benefit in 2023 compared to $6 million net income tax expense in 2022 primarily from outside basis differences in JV investments; and

▪$9 million from the transportation business driven by higher equity earnings from new tariffs going into effect in June 2023 for certain pipelines in Mexico; offset by

▪$122 million earnings attributable to NCI in 2023 compared to $65 million earnings attributable to NCI in 2022 primarily due to an increase in SI Partners’ net income.

The increase in earnings of $354 million in the nine months ended September 30, 2023 compared to the same period in 2022 was primarily due to:

▪$657 million from asset and supply optimization driven by unrealized gains in 2023 compared to unrealized losses in 2022 on commodity derivatives due to changes in natural gas prices;

▪$94 million from the transportation business driven by higher equity earnings and revenues, including the cumulative impact of new tariffs going into effect in June 2023 for certain pipelines in Mexico and a customer’s early termination of firm transportation agreements; and

▪$27 million higher net income tax benefit primarily from the remeasurement of certain deferred income taxes and outside basis differences in JV investments; offset by

▪$435 million earnings attributable to NCI in 2023 compared to $187 million earnings attributable to NCI in 2022 primarily due to an increase in SI Partners’ net income and from the sale of a 10% NCI in SI Partners to ADIA in June 2022;

▪$133 million unfavorable impact from foreign currency and inflation effects on our monetary positions in Mexico, comprised of a $244 million unfavorable impact in 2023 compared to a $111 million unfavorable impact in 2022;

▪$30 million higher net interest expense due to $27 million net unrealized losses in 2023 on a contingent interest rate swap related to the PA LNG Phase 1 project and higher interest rates and borrowings on committed lines of credit, offset by higher capitalization of interest expense on projects under construction; and

▪$18 million from the LNG business driven by higher development costs and certain non-capitalized expenses from projects under construction.

Parent and Other

The increase in losses of $23 million (31%) in the three months ended September 30, 2023 compared to the same period in 2022 was primarily due to:

▪$8 million income tax expense in 2023 compared to $23 million income tax benefit in 2022 from the interim period application of an annual forecasted consolidated ETR; and

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▪$22 million higher net interest expense; offset by

▪$23 million income tax benefit in 2023 from the remeasurement of certain deferred income taxes; and

▪$15 million income tax benefit in 2023 from the resolution of prior year income tax items.

The decrease in losses of $112 million (31%) in the nine months ended September 30, 2023 compared to the same period in 2022 was primarily due to:

▪$120 million deferred income tax expense in 2022 associated with the change in our indefinite reinvestment assertion related to our foreign subsidiaries;

▪$44 million lower net investment losses on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plans;

▪$23 million income tax benefit in 2023 from the remeasurement of certain deferred income taxes; and

▪$15 million income tax benefit in 2023 from the resolution of prior year income tax items; offset by

▪$43 million higher net interest expense;

▪$30 million income tax benefit in 2022 from changes to a valuation allowance against certain tax credit carryforwards; and

▪$24 million lower income tax benefit from the interim period application of an annual forecasted consolidated ETR.

SIGNIFICANT CHANGES IN REVENUES, COSTS AND EARNINGS

This section contains a discussion of the differences between periods in the specific line items of the Condensed Consolidated Statements of Operations for Sempra, SDG&E and SoCalGas.

Utilities Revenues and Cost of Sales

Our utilities revenues include natural gas revenues at SoCalGas and SDG&E and Sempra Infrastructure’s Ecogas and electric revenues at SDG&E. Intercompany revenues included in the separate revenues of each utility are eliminated in Sempra’s Condensed Consolidated Statements of Operations.

SoCalGas and SDG&E currently operate under a regulatory framework that permits:

▪The cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred and without markup. The GCIM provides for SoCalGas to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between core customers and SoCalGas.

▪SDG&E to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered or refunded in subsequent periods through rates.

▪SoCalGas and SDG&E to recover certain program expenditures and other costs authorized by the CPUC, herein referred to as “refundable programs.”

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

SoCalGas’ and SDG&E’s revenues are decoupled from, or not tied to, actual sales volumes. SoCalGas recognizes annual authorized revenue for natural gas customers using seasonal factors established in applicable proceedings, resulting in a significant portion of SoCalGas’ earnings being recognized in the first and fourth quarters of each year. SDG&E’s authorized revenue recognition is also impacted by seasonal factors, resulting in higher earnings in the third quarter when electric loads are typically higher than in the other three quarters of the year. We discuss this decoupling mechanism and its effects further in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.

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The table below summarizes utilities revenues and cost of sales.


UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
Natural gas revenues:
SoCalGas	$	1,313	$	1,385	$	6,574	$	4,879
SDG&E	188		209		1,014		741
Sempra Infrastructure	18		19		67		67
Eliminations and adjustments	(31)		(26)		(95)		(76)
Total	1,488		1,587		7,560		5,611
Electric revenues:
SDG&E	1,254		1,360		3,343		3,672
Eliminations and adjustments	(4)		(3)		(12)		(9)
Total	1,250		1,357		3,331		3,663
Total utilities revenues	$	2,738	$	2,944	$	10,891	$	9,274
Cost of natural gas(1):
SoCalGas	$	224	$	441	$	2,855	$	1,577
SDG&E	45		65		462		260
Sempra Infrastructure	4		7		5		21
Eliminations and adjustments	(13)		(8)		(68)		(23)
Total	260		505		3,254		1,835
Cost of electric fuel and purchased power(1):
SDG&E	200		316		442		806
Eliminations and adjustments	(17)		(9)		(57)		(43)
Total	183		307		385		763
Total utilities cost of sales	$	443	$	812	$	3,639	$	2,598

(1) Excludes depreciation and amortization, which are presented separately on the Sempra, SDG&E and SoCalGas Condensed Consolidated Statements of Operations.

Natural Gas Revenues and Cost of Natural Gas

The table below summarizes the average cost of natural gas sold by Sempra California and included in cost of natural gas. The average cost of natural gas sold at each utility is impacted by market prices, as well as transportation, tariff and other charges.


SEMPRA CALIFORNIA AVERAGE COST OF NATURAL GAS
(Dollars per thousand cubic feet)
	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
SoCalGas	$	4.84	$	9.46	$	12.10	$	7.64
SDG&E	6.33		10.20		12.10		7.74

In the three months ended September 30, 2023, our natural gas revenues decreased by $99 million (6%) to $1.5 billion compared to the same period in 2022 primarily due to:

▪$72 million decrease at SoCalGas, which included:

◦$217 million decrease in cost of natural gas sold, which we discuss below, and

◦$36 million lower non-service components of net periodic benefit cost, which fully offsets in other income (expense), net, offset by

◦$143 million higher revenues associated with refundable programs, which are fully offset in O&M, and

◦$32 million higher CPUC-authorized revenues; and

▪$21 million decrease at SDG&E, which included:

◦$20 million decrease in cost of natural gas sold, which we discuss below, and

◦$7 million lower revenues associated with refundable programs, which are fully offset in O&M, offset by

◦$4 million higher revenues from balanced capital projects.

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In the three months ended September 30, 2023, our cost of natural gas decreased by $245 million (49%) to $260 million compared to the same period in 2022 primarily due to:

▪$217 million decrease at SoCalGas primarily due to lower average natural gas prices; and

▪$20 million decrease at SDG&E, including $27 million from lower average natural gas prices, offset by $7 million from higher volumes driven by weather.

In the nine months ended September 30, 2023, our natural gas revenues increased by $1.9 billion (35%) to $7.6 billion compared to the same period in 2022 primarily due to:

▪$1.7 billion increase at SoCalGas, which included:

◦$1.3 billion increase in cost of natural gas sold, which we discuss below,

◦$284 million higher revenues associated with refundable programs, which are fully offset in O&M,

◦$75 million higher CPUC-authorized revenues,

◦$28 million higher non-service components of net periodic benefit cost, which fully offsets in other income (expense), net,

◦$24 million higher franchise fee revenues, and

◦$18 million higher regulatory awards approved by the CPUC, offset by

◦$26 million lower regulatory revenues in 2023 from the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures, which are offset in income tax benefit (expense); and

▪$273 million increase at SDG&E, which included:

◦$202 million increase in cost of natural gas sold, which we discuss below,

◦$28 million higher revenues from balanced capital projects, and

◦$23 million higher revenues associated with refundable programs, which are fully offset in O&M.

In the nine months ended September 30, 2023, our cost of natural gas increased by $1.4 billion to $3.3 billion compared to the same period in 2022 primarily due to:

▪$1.3 billion increase at SoCalGas, including $1.1 billion from higher average natural gas prices and $226 million from higher volumes driven by weather; and

▪$202 million increase at SDG&E, including $167 million from higher average natural gas prices and $35 million from higher volumes driven by weather.

Electric Revenues and Cost of Electric Fuel and Purchased Power

In the three months ended September 30, 2023, our electric revenues decreased by $107 million (8%) to $1.3 billion compared to the same period in 2022 primarily due to a $106 million decrease at SDG&E, which included:

▪$116 million lower cost of electric fuel and purchased power, which we discuss below; and

▪$63 million in 2023 from the recognition of investment tax credits from standalone energy storage projects, which are offset in income tax benefit (expense); offset by

▪$29 million higher revenues from balanced capital projects;

▪$25 million higher revenues associated with refundable programs, which are fully offset in O&M;

▪$22 million higher revenues from transmission operations; and

▪$9 million higher CPUC-authorized revenues.

Our utility cost of electric fuel and purchased power includes utility-owned generation, power purchased from third parties, and net power purchases and sales to/from the California ISO. In the three months ended September 30, 2023, the cost of electric fuel and purchased power decreased by $124 million (40%) to $183 million compared to the same period in 2022 primarily due to a $116 million decrease at SDG&E, which included:

▪$180 million lower purchased power from the California ISO due to lower customer demand from departing load now served by CCAs, and lower market prices; and

▪ $77 million lower utility-owned generation costs; offset by

▪$169 million lower sales to the California ISO due to lower market prices.

In the nine months ended September 30, 2023, our electric revenues decreased by $332 million (9%) to $3.3 billion compared to the same period in 2022 primarily due to a $329 million decrease at SDG&E, which included:

▪$364 million lower cost of electric fuel and purchased power, which we discuss below; and

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▪$165 million in 2023 from the recognition of investment tax credits from standalone energy storage projects, which are offset in income tax benefit (expense); offset by

▪$69 million higher revenues from balanced capital projects;

▪$36 million higher revenues associated with refundable programs, which are fully offset in O&M;

▪$32 million higher CPUC-authorized revenues;

▪$29 million higher revenues from transmission operations; and

▪$10 million higher revenues associated with impacts resulting from changes in tax laws tracked in the income tax expense memorandum account.

In the nine months ended September 30, 2023, the cost of electric fuel and purchased power decreased by $378 million to $385 million compared to the same period in 2022 primarily due to a $364 million decrease at SDG&E, which included:

▪$138 million lower purchased power from the California ISO due to lower customer demand from departing load now served by CCAs, net of higher market prices;

▪$98 million lower purchased power from, net of higher excess capacity sales to, third parties;

▪$55 million higher realized gains on fixed-price natural gas derivative contracts, which are entered into to hedge the cost of electric fuel; and

▪$54 million lower utility-owned generation costs.

Energy-Related Businesses: Revenues and Cost of Sales

The table below shows revenues and cost of sales for our energy-related businesses.


ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
	Three months ended September 30,				Nine months ended September 30,
	2023		2022		2023		2022
Revenues:
Sempra Infrastructure	$	611	$	678	$	2,418	$	1,743
Parent and other(1)	(15)		(5)		(80)		(33)
Total revenues	$	596	$	673	$	2,338	$	1,710
Cost of sales(2):
Sempra Infrastructure	$	163	$	340	$	437	$	764
Total cost of sales	$	163	$	340	$	437	$	764

(1) Includes eliminations of intercompany activity.

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

In the three months ended September 30, 2023, revenues from our energy-related businesses decreased by $77 million (11%) to $596 million compared to the same period in 2022 primarily due to:

▪$48 million decrease in revenues from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:

◦$32 million from lower LNG diversion fees, and

◦$11 million primarily driven by $113 million from lower natural gas prices and volumes offset by $2 million unrealized gains in 2023 compared to $76 million unrealized losses in 2022 on commodity derivatives; and

▪$35 million decrease in revenues from TdM mainly due to lower power prices.

In the three months ended September 30, 2023, the cost of sales for our energy-related businesses decreased by $177 million to $163 million compared to the same period in 2022 primarily due to:

▪$151 million driven by lower natural gas purchases related to asset and supply optimization; and

▪$32 million at TdM driven by lower natural gas prices.

In the nine months ended September 30, 2023, revenues from our energy-related businesses increased by $628 million (37%) to $2.3 billion compared to the same period in 2022 primarily due to:

▪$652 million increase in revenues from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:

◦$720 million primarily driven by $619 million unrealized gains in 2023 compared to $183 million unrealized losses in 2022 on commodity derivatives offset by $72 million from lower natural gas prices, net of higher volumes, offset by

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◦$71 million lower LNG sales; and

▪$35 million higher transportation revenues driven by a customer’s early termination of firm transportation agreements; offset by

▪$40 million decrease in revenues from TdM mainly due to lower power prices and lower volumes from maintenance on a third-party pipeline in 2023 that supplies gas to the plant.

In the nine months ended September 30, 2023, the cost of sales for our energy-related businesses decreased by $327 million (43%) to $437 million compared to the same period in 2022 primarily due to:

▪$355 million decrease driven by lower natural gas and LNG purchases, net of higher prices, related to asset and supply optimization; offset by

▪$20 million increase at TdM driven by higher natural gas prices offset by lower volumes from maintenance on a third-party pipeline in 2023 that supplies gas to the plant.

Operation and Maintenance

In the three months ended September 30, 2023, O&M increased by $177 million (15%) to $1.4 billion compared to the same period in 2022 primarily due to:

▪$143 million increase at SoCalGas due to higher expenses associated with refundable programs, which costs incurred are recovered in revenue; and

▪$24 million increase at SDG&E due to:

◦$18 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue, and

◦$6 million higher non-refundable operating costs.

In the nine months ended September 30, 2023, O&M increased by $504 million (15%) to $4.0 billion compared to the same period in 2022 primarily due to:

▪$327 million increase at SoCalGas due to:

◦$284 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue, and

◦$43 million higher non-refundable operating costs;

▪$108 million increase at SDG&E due to:

◦$59 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue, and

◦$49 million higher non-refundable operating costs; and

▪$71 million increase at Sempra Infrastructure due to:

◦$34 million higher development costs and certain non-capitalized expenses from projects under construction,

◦$13 million higher purchased services, and

◦$12 million higher operating cost due to remeasurement of operating leases at the refined products terminals in 2022.

Aliso Canyon Litigation and Regulatory Matters

In the three months and nine months ended September 30, 2022, SoCalGas recorded charges of $122 million and $259 million, respectively, relating to litigation and regulatory matters pertaining to the Leak.

Other Income (Expense), Net

As part of our central risk management function, we may enter into foreign currency derivatives to hedge SI Partners’ exposure to movements in the Mexican peso from its controlling interest in IEnova. The gains/losses associated with these derivatives are included in other income (expense), net, as described below, and partially mitigate the transactional effects of foreign currency and inflation included in income tax expense for SI Partners’ consolidated entities and in equity earnings for SI Partners’ equity method investments. We discuss policies governing our risk management in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in the Annual Report.

Other income, net, in the three months ended September 30, 2023 was $3 million compared to other expense, net, of $40 million in the same period in 2022 primarily due to:

▪$49 million lower non-service components of net periodic benefit cost, including $12 million at SDG&E and $36 million at SoCalGas; and

▪$12 million higher net interest income on regulatory balancing accounts, including $5 million at SDG&E and $7 million at SoCalGas; offset by

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▪$6 million higher net investment losses on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plans.

Other income, net, in the nine months ended September 30, 2023 was $75 million compared to other expense, net, of $3 million in the same period in 2022 primarily due to:

▪$58 million lower net investment losses on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plans;

▪$44 million higher net interest income on regulatory balancing accounts, including $22 million at SDG&E and $22 million at SoCalGas; and

▪$6 million gains in 2023 compared to $16 million losses in 2022 from impacts associated with interest rate and foreign exchange instruments and foreign currency transactions, including:

◦$11 million foreign currency losses in 2022 on a Mexican peso-denominated loan to IMG, which is fully offset in equity earnings, and

◦$1 million gain in 2023 compared to $7 million losses in 2022 on other foreign currency transactional effects; and

▪$10 million in penalties at SoCalGas in 2022 related to energy efficiency and advocacy OSCs; offset by

▪$34 million higher non-service components of net periodic benefit cost, including $6 million at SDG&E and $28 million at SoCalGas.

Interest Expense

In the three months ended September 30, 2023, interest expense increased by $30 million (11%) to $312 million compared to the same period in 2022 primarily due to:

▪$29 million at Parent and other from higher debt balances from debt issuances and higher interest rates and borrowings on commercial paper;

▪$20 million at SoCalGas from higher debt balances from debt issuances and higher interest rates; and

▪$13 million at SDG&E primarily from higher debt balances from debt issuances; offset by

▪$32 million at Sempra Infrastructure primarily due to:

◦$39 million lower interest expense due to higher capitalization of interest expense on projects under construction, offset by

◦$17 million higher interest rates and borrowings on committed lines of credit.

In the nine months ended September 30, 2023, interest expense increased by $199 million (25%) to $995 million compared to the same period in 2022 primarily due to:

▪$75 million at SoCalGas from higher debt balances from debt issuances and higher interest rates;

▪$61 million at Parent and other from higher interest rates and borrowings on commercial paper and higher debt balances from debt issuances;

▪$34 million at SDG&E primarily from higher debt balances from debt issuances; and

▪$29 million at Sempra Infrastructure primarily due to:

◦$61 million higher interest rates and borrowings on committed lines of credit, and

◦$47 million interest expense in 2023 comprised of $33 million net unrealized losses and a $14 million settlement on a contingent interest rate swap related to the PA LNG Phase 1 project that we discuss in Note 7 of the Condensed Consolidated Financial Statements, offset by

◦$65 million lower interest expense due to higher capitalization of interest expense on projects under construction.

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Income Taxes

The table below shows the income tax expense and ETRs for Sempra, SDG&E and SoCalGas.


INCOME TAX (BENEFIT) EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
	Three months ended September 30,						Nine months ended September 30,
	2023			2022			2023			2022
Sempra:
Income tax (benefit) expense	$	(52)		$	21		$	499		$	435

Income before income taxes and equity earnings	$	323		$	165		$	2,175		$	1,194
Equity earnings, before income tax(1)	133			134			418			436
Pretax income	$	456		$	299		$	2,593		$	1,630

Effective income tax rate	(11)		%	7		%	19		%	27		%
SDG&E:
Income tax (benefit) expense	$	(15)		$	35		$	(4)		$	141
Income before income taxes	$	259		$	306		$	712		$	822
Effective income tax rate	(6)		%	11		%	(1)		%	17		%
SoCalGas:
Income tax (benefit) expense	$	(5)		$	(28)		$	68		$	75
Income (loss) before income taxes	$	11		$	(110)		$	600		$	415
Effective income tax rate	(45)		%	25		%	11		%	18		%

(1) We discuss how we recognize equity earnings in Note 6 of the Notes to Consolidated Financial Statements in the Annual Report.

Under the IRA, beginning in 2023, the scope of projects eligible for investment tax credits was expanded to include standalone energy storage projects. The IRA also provided an election that prospectively permits investment tax credits related to standalone energy storage projects to be returned to utility customers over a period that is shorter than the life of the applicable asset. Under this election, SDG&E recorded a regulatory liability to offset these investment tax credits, which reduced SDG&E’s and Sempra’s ETR in 2023.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. As a result of this Revenue Procedure, SoCalGas updated its assessment of prior years’ unrecognized income tax benefits and, in the nine months ended September 30, 2023, recorded an income tax benefit of $43 million for previously unrecognized income tax benefits pertaining to gas repairs expenditures. SoCalGas recorded an associated regulatory liability for the portion that will benefit customers in the future. We are assessing the potential future impacts of this Revenue Procedure.

Sempra

In the three months ended September 30, 2023, Sempra’s income tax benefit compared to income tax expense in the same period in 2022 was primarily due to:

▪$49 million income tax benefit in 2023 compared to $4 million income tax benefit in 2022 from foreign currency and inflation effects on our monetary positions in Mexico;

▪$23 million income tax benefit in 2023 associated with the remeasurement of certain deferred income taxes; and

▪income tax benefit in 2023 from the recognition of investment tax credits from standalone energy storage projects; offset by

▪$21 million income tax benefit in 2022 associated with charges relating to litigation and regulatory matters pertaining to the Leak; and

▪higher pretax income.

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In the nine months ended September 30, 2023, Sempra’s income tax expense increased by $64 million (15%) compared to the same period in 2022 primarily due to:

▪$203 million income tax expense in 2023 compared to $80 million income tax expense in 2022 from foreign currency and inflation effects on our monetary positions in Mexico;

▪$60 million income tax benefit in 2022 associated with charges relating to litigation and regulatory matters pertaining to the Leak;

▪$30 million income tax benefit in 2022 from changes to a valuation allowance against certain tax credit carryforwards;

▪$11 million lower income tax benefit from the remeasurement of certain deferred income taxes; and

▪higher pretax income; offset by

▪$120 million deferred income tax expense in 2022 associated with the change in our indefinite reinvestment assertion related to our foreign subsidiaries;

▪$43 million income tax benefit in 2023 from the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures; and

▪income tax benefit in 2023 from the recognition of investment tax credits from standalone energy storage projects.

We discuss the impact of foreign currency exchange rates and inflation on income taxes below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.” See Note 1 of the Notes to Condensed Consolidated Financial Statements in this report and Notes 1 and 8 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.

SDG&E

In the three months and nine months ended September 30, 2023, SDG&E’s income tax benefit compared to income tax expense in the same period in 2022 was primarily due to:

▪income tax benefit in 2023 from the recognition of investment tax credits from standalone energy storage projects; and

▪lower pretax income; offset by

▪$10 million lower income tax benefit from the resolution of prior year income tax items.

SoCalGas

In the three months ended September 30, 2023, SoCalGas’ income tax benefit decreased by $23 million compared to the same period in 2022 primarily due to a $21 million income tax benefit in 2022 associated with charges relating to litigation and regulatory matters pertaining to the Leak.

In the nine months ended September 30, 2023, SoCalGas’ income tax expense decreased by $7 million (9%) compared to the same period in 2022 primarily due to:

▪the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures; and

▪lower pretax income in 2023 compared to 2022 (before charges in 2022 relating to litigation and regulatory matters pertaining to the Leak); offset by

▪$60 million income tax benefit in 2022 associated with charges relating to litigation and regulatory matters pertaining to the Leak.

Equity Earnings

In the three months ended September 30, 2023, equity earnings increased by $62 million (15%) to $479 million compared to the same period in 2022 primarily due to:

▪$48 million at Oncor Holdings driven by:

◦higher revenues attributable to higher customer consumption primarily attributable to weather, updates to transmission billing factors, new base rates implemented in May 2023, interim rate updates to reflect increases in invested capital, and customer growth, offset by

◦higher interest expense and depreciation expense attributable to invested capital, and

◦higher O&M;

▪$9 million at TAG mainly due to higher revenues from new tariffs going into effect in June 2023; and

▪$6 million at IMG mainly due to lower income tax expense.

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In the nine months ended September 30, 2023, equity earnings decreased by $32 million (3%) to $1,086 million compared to the same period in 2022 primarily due to:

▪$55 million at Oncor Holdings driven by:

◦higher interest expense and depreciation expense attributable to invested capital,

◦write-off of rate base disallowances in 2023 resulting from the PUCT’s final order in Oncor’s comprehensive base rate review, and

◦higher O&M, offset by

◦higher revenues attributable to updates to transmission billing factors, new base rates implemented in May 2023, customer growth, and interim rate updates to reflect increases in invested capital;

▪$28 million at IMG due to foreign currency effects, including $11 million foreign currency gains in 2022 on IMG’s Mexican peso-denominated loans from its JV owners, which is fully offset in other income (expense), net, and higher interest expense and income tax expense; and

▪$17 million at Cameron LNG JV due to higher project development costs from the proposed Cameron LNG Phase 2 project; offset by

▪$69 million at TAG due to higher revenues, including the cumulative impact of new tariffs going into effect in June 2023, offset by higher income tax expense.

Earnings Attributable to Noncontrolling Interests

In the three months ended September 30, 2023, earnings attributable to NCI increased by $57 million to $122 million compared to the same period in 2022 due to an increase in SI Partners’ net income.

In the nine months ended September 30, 2023, earnings attributable to NCI increased by $248 million to $435 million compared to the same period in 2022 primarily due to:

▪$157 million increase from an increase in SI Partners’ net income; and

▪$91 million increase from a decrease in our ownership interest in SI Partners and SI Partners subsidiaries.

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, revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra’s results of operations. We discuss further the impact of foreign currency and inflation rates on results of operations, including impacts on income taxes and related hedging activity, in “Part II – Item 7. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations” in the Annual Report.

Foreign Currency Translation

Any difference in average exchange rates used for the translation of income statement activity from year to year can cause a variance in Sempra’s comparative results of operations. In the three months and nine months ended September 30, 2023, the change in our earnings as a result of foreign currency translation rates was higher by $1 million and $3 million, respectively, compared to the same periods in 2022.

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Transactional Impacts

Income statement activities at our foreign operations and their JVs are also impacted by transactional gains and losses, a summary of which is shown in the table below:


TRANSACTIONAL (LOSSES) GAINS FROM FOREIGN CURRENCY AND INFLATION EFFECTS
(Dollars in millions)
	Total reported amounts				Transactional (losses) gains included in reported amounts
	Three months ended September 30,
	2023		2022		2023		2022
Other income (expense), net	$	3	$	(40)	$	(2)	$	1
Income tax benefit (expense)	52		(21)		49		4
Equity earnings	479		417		5		(2)
Net income	854		561		52		3
Earnings attributable to noncontrolling interests	(122)		(65)		(16)		(1)
Earnings attributable to common shares	721		485		36		2

	Nine months ended September 30,
	2023		2022		2023		2022
Other income (expense), net	$	75	$	(3)	$	6	$	(16)
Income tax benefit (expense)	(499)		(435)		(203)		(80)
Equity earnings	1,086		1,118		(46)		(14)
Net income	2,762		1,877		(243)		(110)
Earnings attributable to noncontrolling interests	(435)		(187)		77		21
Earnings attributable to common shares	2,293		1,656		(166)		(89)

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, and other financing transactions which may include issuing equity securities, distributions from our equity method investments, project financing and funding from minority interest owners. We believe that these cash flow sources, combined with available funds, will be adequate to fund our operations in both the short-term and long-term, including to:

▪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 or start-ups

Sempra, SDG&E and SoCalGas currently have reasonable access to the money markets and capital markets and are not currently constrained in their ability to borrow money at market rates from commercial banks, under existing revolving credit facilities, through public offerings of debt securities, 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. Debt funding has become less attractive due to the recent rise in both short-term and long-term interest rates. In addition, our financing activities and actions by credit rating agencies, as well as many other factors, could negatively affect the availability and cost of both short-term and long-term debt financing and equity financing. Also, cash flows

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from operations may be impacted by the timing of commencement and completion, and potentially cost overruns, of large projects and other material events, such as the settlement of material litigation. If cash flows from operations were to be significantly reduced or we were unable to borrow 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.

Available Funds

Our committed lines of credit provide liquidity and support commercial paper. Sempra, SDG&E and SoCalGas each have five-year credit agreements expiring in 2028 and Sempra Infrastructure has four committed lines of credit expiring on various dates from 2025 through 2030, and an uncommitted revolving credit facility expiring in 2024.


AVAILABLE FUNDS AT SEPTEMBER 30, 2023
(Dollars in millions)
	Sempra		SDG&E		SoCalGas
Unrestricted cash and cash equivalents(1)	$	1,149	$	246	$	26
Available unused credit(2)	8,096		1,500		779

(1) Amounts at Sempra include $170 held in non-U.S. jurisdictions. We discuss repatriation in Note 8 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 6 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, acquisitions or start-ups. SDG&E and SoCalGas use short-term debt primarily to meet working capital needs or to help fund event-specific costs. Commercial paper, lines of credit and a term loan were our primary sources of short-term debt funding in the first nine months of 2023.

We discuss our short-term debt activities in Note 6 of the Notes to Condensed Consolidated Financial Statements and below in “Sources and Uses of Cash.”

Long-Term Debt Activities

Significant issuances of and payments on long-term debt in the first nine months of 2023 included the following:


LONG-TERM DEBT ISSUANCES AND PAYMENTS
(Dollars in millions)
Issuances:	Amount at issuance		Maturity
Sempra 5.40% senior unsecured notes	$	550	2026
Sempra 5.50% senior unsecured notes	700		2033
SDG&E 5.35% first mortgage bonds	800		2053
SDG&E 4.95% green first mortgage bonds	600		2028
SoCalGas 5.20% first mortgage bonds	500		2033
SoCalGas 5.75% first mortgage bonds	500		2053
Sempra Infrastructure variable rate notes (ECA LNG Phase 1 project)	207		2025
Sempra Infrastructure variable rate notes (PA LNG Phase 1 project)	243		2030

Payments:	Payments		Maturity
SDG&E 3.60% first mortgage bonds	$	450	2023
SoCalGas senior unsecured variable rate notes	300		2023
Sempra Infrastructure 6.3% notes (4.124% after cross-currency swap)	208		2023

We discuss our long-term debt activities, including the use of proceeds on long-term debt issuances, in Note 6 of the Notes to Condensed Consolidated Financial Statements.

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Credit Ratings

We provide additional information about the credit ratings of Sempra, SDG&E and SoCalGas in “Part I – Item 1A. Risk Factors” and “Part II – Item 2. MD&A – Capital Resources and Liquidity” in the Annual Report.

The credit ratings of Sempra, SDG&E and SoCalGas remained at investment grade levels in the first nine months of 2023.


CREDIT RATINGS AT SEPTEMBER 30, 2023

	Sempra	SDG&E	SoCalGas
Moody’s	Baa2 with a stable outlook	A3 with a stable outlook	A2 with a stable outlook
S&P	BBB+ with a stable outlook	BBB+ with a stable outlook	A with a negative 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 financial or other burdensome covenants or a requirement for collateral to be posted in the case of certain financing arrangements and may materially and adversely affect the market prices of their equity and debt securities, the rates at which borrowings are made and commercial paper is issued, and the various fees on their outstanding credit facilities. This could make it more costly for Sempra, SDG&E, SoCalGas and Sempra’s other subsidiaries to issue debt securities, to borrow under credit facilities and to raise certain other types of financing.

Sempra has agreed that, if the credit rating of Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. Oncor’s senior secured debt was rated A2, A+ and A at Moody’s, S&P and Fitch, respectively, at September 30, 2023.

Loans to/from Affiliates

At September 30, 2023, Sempra had $308 million in loans due to unconsolidated affiliates.

Inflation Reduction Act of 2022

The IRA was signed into law in August 2022. The IRA includes tax credits and other incentives for energy and climate initiatives and introduces a 15% corporate alternative minimum tax on adjusted financial statement income for tax years beginning after December 31, 2022. We do not currently expect the IRA to have a material adverse impact on Sempra’s, SDG&E’s or SoCalGas’ results of operations, financial condition and/or cash flows. We will continue to assess the impacts of the IRA as the U.S. Department of the Treasury and the IRS issue guidance on tax implementation, and the U.S. Environmental Protection Agency and DOE issue guidance on energy and climate initiatives.

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 legislators, litigation and the changing energy marketplace, as well as other matters described in this report. SDG&E and SoCalGas expect that the available unused funds from their credit facilities described above, which also supports their commercial paper programs, cash flows from operations, and other incurrences of debt including issuing debt securities and obtaining term loans will continue to be adequate to fund their respective current operations and planned capital expenditures. SDG&E and SoCalGas manage their capital structures and pay dividends when appropriate and as approved by their respective boards of directors.

As we discuss 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, 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.

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CPUC Cost of Capital

As we discuss in Note 4 of the Notes to the Condensed Consolidated Financial Statements, the CPUC approved the cost of capital for SDG&E and SoCalGas that became effective on January 1, 2023 and will remain in effect through December 31, 2025, subject to the CCM. The CPUC has issued a ruling to initiate a second phase of this cost of capital proceeding to evaluate potential modifications to the CCM.

The CCM applies in the interim years between required cost of capital applications and considers changes in the cost of capital based on changes in interest rates using the applicable utility bond index published by Moody’s (the CCM benchmark rate) for each 12-month period ending September 30 (the measurement period). The CCM benchmark rate is the basis of comparison to determine if the CCM is triggered, which occurs if the change in the applicable Moody’s utility bond index relative to the CCM benchmark rate is larger than plus or minus 1.000% at the end of the measurement period. The index applicable to SDG&E and SoCalGas is based on each utility’s credit rating. For the measurement period that ended on September 30, 2023, SDG&E’s CCM benchmark rate was 4.367% based on Moody’s Baa- utility bond index and SoCalGas’ CCM benchmark rate was 4.074% based on Moody’s A- utility bond index. SDG&E’s and SoCalGas’ average bond index rates for the period from October 1, 2022 through September 30, 2023 were more than 1.000% above their respective CCM benchmark rates, which triggered the CCM. Subject to regulatory approval, the CCM trigger would increase the authorized rate of return for SDG&E to 7.67% (including the cost of debt to 4.34% and return on equity to 10.65%) and increase the authorized rate of return for SoCalGas to 7.67% (including the cost of debt to 4.54% and return on equity to 10.50%), effective January 1, 2024.

SDG&E

Wildfire Fund

The carrying value of SDG&E’s Wildfire Fund asset totaled $310 million at September 30, 2023. 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 an impairment charge against earnings when available coverage is reduced due to recoverable claims from any of the participating IOUs. Pacific Gas and Electric Company has indicated that it will seek reimbursement from the Wildfire Fund for losses associated with the Dixie Fire, which burned from July 2021 through October 2021 and was reported to be the largest single wildfire (measured by acres burned) in California history. If any California electric IOU’s equipment is determined to be a cause of a fire, it could have a material adverse effect on SDG&E’s and Sempra’s financial condition and results of operations up to the carrying value of our Wildfire Fund asset, with additional potential material exposure if SDG&E’s equipment is determined to be a cause of a fire. In addition, the Wildfire Fund could be completely exhausted due to fires in the other California electric IOUs’ service territories, by fires in SDG&E’s service territory or by a combination thereof. In the event that the Wildfire Fund is materially diminished, exhausted or terminated, SDG&E will lose the protection afforded by the Wildfire Fund, and as a consequence, a fire in SDG&E’s service territory could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

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

Aliso Canyon Natural Gas Storage Facility Gas Leak

Insurance and Accounting and Other Impacts. Since 2015, SoCalGas has incurred significant costs related to the Leak, including costs to defend against and settle civil litigation arising from the Leak. Other than insurance for directors’ and officers’ liability, we have exhausted all of our insurance for this matter. We continue to pursue other sources of insurance coverage for costs related to this matter, but we may not be successful in obtaining additional insurance recovery for any of these costs.

At September 30, 2023, $126 million is accrued in Reserve for Aliso Canyon Costs and $3 million is accrued in Deferred Credits and Other on SoCalGas’ and Sempra’s Condensed Consolidated Balance Sheets. These accruals do not include any amounts in excess of what has been estimated to resolve certain matters that we describe in “Litigation” and “Regulatory Proceeding” nor any amounts that may be necessary to resolve threatened litigation, other potential litigation or other costs, in each case to the extent it

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is not possible to predict at this time the outcome of these actions or reasonably estimate the possible costs or a range of possible costs. Further, we are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued, which could be significant.

An adverse outcome with respect to (i) the unresolved litigation we describe under “Litigation,” (ii) the unresolved SB 380 OII proceeding we describe under “Regulatory Proceeding,” or (iii) threatened or other potential litigation related to the Leak, in each case that we discuss in Note 10 of the Notes to the Condensed Consolidated Financial Statements, could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Natural Gas Storage Operations and Reliability. Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and consumer heating needs in the winter. The Aliso Canyon natural gas storage facility is the largest SoCalGas storage facility and an important component of SoCalGas’ delivery system. In February 2017, the CPUC opened proceeding SB 380 OII to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, including considering alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated.

At September 30, 2023, the Aliso Canyon natural gas storage facility had a net book value of $993 million. If the Aliso Canyon natural gas storage facility were to be permanently closed or if future cash flows from its operation were otherwise insufficient to recover its carrying value, we may record an impairment of the facility, which could be material, or we could incur materially higher than expected operating costs and/or be required to make material additional capital expenditures (any or all of which may not be recoverable in rates), and natural gas reliability and electric generation could be jeopardized.

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.

Capital Structure and Return on Equity

In April 2023, the PUCT issued a final order in Oncor’s comprehensive base rate review. The final order sets Oncor’s authorized ROE at 9.7%, a decrease from its previously authorized ROE of 9.8%, and maintains Oncor’s authorized regulatory capital structure at 57.5% debt to 42.5% equity. The new rates became effective 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 intervenor 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.

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 of the Sempra Infrastructure businesses. We expect Sempra Infrastructure will require additional funding for the development and expansion of its portfolio of projects, which may be financed through a combination of funding from the parent and minority interest owners, bank financing, issuances of debt, project financing, partnering in JVs and asset sales.

In the nine months ended September 30, 2023, Sempra Infrastructure distributed $289 million to minority interest owners and minority interest owners contributed $1,236 million to Sempra Infrastructure.

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LNG and Net-Zero Solutions

Cameron LNG Phase 2 Project. Cameron LNG JV is developing a proposed expansion project that would add one liquefaction train with an expected maximum production capacity of approximately 6.75 Mtpa and would increase the production capacity of the existing three trains at the Cameron LNG Phase 1 facility by up to approximately 1 Mtpa through debottlenecking activities. The Cameron LNG JV site can accommodate additional trains beyond the proposed Cameron LNG Phase 2 project.

Cameron LNG JV previously received major permits and FTA and non-FTA approvals associated with the potential expansion that included up to two additional liquefaction trains and up to two additional full containment LNG storage tanks. 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. In March 2023, the FERC approved Cameron LNG JV’s request to amend the permits to allow the use of electric drives, instead of gas turbine drives, which would reduce overall emissions. The amendment also allows the design to be changed from a two-train gas turbine expansion to a one-train electric drive expansion along with other design enhancements that, together, are expected to result in a more cost-effective and efficient facility, while also reducing overall GHG emissions.

Sempra Infrastructure and the other Cameron LNG JV members, namely affiliates of TotalEnergies SE, Mitsui & Co., Ltd. and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha, have entered into 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. Sempra Infrastructure plans to sell the LNG corresponding to its allocated capacity from the proposed Cameron LNG Phase 2 project under long-term SPAs prior to making a final investment decision. The ultimate participation in and offtake by Sempra Infrastructure, TotalEnergies SE, Mitsui & Co., Ltd. and Japan LNG Investment, LLC remain subject to negotiation and finalization of definitive agreements, among other factors, and the non-binding HOA does not commit any party to enter into definitive agreements with respect to the proposed Cameron LNG Phase 2 project.

Sempra Infrastructure, the other Cameron LNG JV members, and Cameron LNG JV have entered into a Phase 2 Project Development Agreement under which Sempra Infrastructure, subject to certain conditions and ongoing approvals by the Cameron LNG JV board, will manage and lead the Cameron LNG Phase 2 project development work until Cameron LNG JV makes a final investment decision.

In April 2022, Cameron LNG JV, upon the unanimous approval of the Cameron LNG JV board, awarded two FEED contracts, one to Bechtel and the other to a joint venture between JGC America Inc. and Zachry Industrial Inc.

In connection with the execution of the Phase 2 Project Development Agreement and the award of the FEED contracts, the Cameron LNG JV board unanimously approved an expansion development budget to fund, subject to the terms of the Phase 2 Project Development Agreement, development work to prepare for a potential final investment decision.

In July 2023, Cameron LNG JV informed Bechtel that it has been selected to perform additional value engineering work on the proposed Cameron LNG Phase 2 project, which we expect will continue through the end of 2023. The parties are negotiating the terms and conditions of a definitive EPC contract for the project. The current arrangement with Bechtel does not commit any party to enter into a definitive EPC contract or to otherwise participate in the project.

Cameron LNG JV has entered into a non-binding MOU with Entergy Louisiana, LLC, a subsidiary of Entergy Corporation, to negotiate the terms and conditions for a new electric service agreement intended to reduce Cameron LNG JV’s scope 2 emissions from the electricity it purchases from Entergy Louisiana, LLC. The non-binding MOU sets forth a framework for Entergy Louisiana, LLC and Cameron LNG JV to finalize and sign a minimum 20-year agreement for the procurement of new renewable generation resources in Louisiana, subject to the approval of the renewable tariff by the Louisiana Public Service Commission. The ultimate arrangement between Cameron LNG JV and Entergy Louisiana, LLC remains subject to negotiation and finalization of definitive agreements, among other factors, and the non-binding MOU does not commit any party to enter into definitive agreements with respect to the proposed electric services agreement.

Sempra Infrastructure has entered into a non-binding HOA for the negotiation and potential finalization of a definitive 20-year SPA with ORLEN for 2 Mtpa of LNG offtake from the proposed Cameron LNG Phase 2 project. The ultimate participation in and offtake from the proposed project remains subject to negotiation and finalization of a definitive agreement, among other factors, and the non-binding HOA does not commit any party to enter into a definitive agreement with respect to the proposed project. Sempra Infrastructure also entered into a non-binding HOA with Williams for the negotiation of potential LNG offtake from, and feed gas supply to, the PA LNG Phase 2 project and Cameron LNG Phase 2 project that are under development, as well as a

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potential strategic JV related to the existing Cameron Interstate Pipeline and the proposed Port Arthur Pipeline Louisiana Connector. The term of this non-binding HOA ended in March 2023.

Expansion of the Cameron LNG Phase 1 facility beyond the first three trains is subject to certain restrictions and conditions under the JV project financing agreements, including among others, scope restrictions on expansion of the project unless appropriate prior consent is obtained from the existing project lenders. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the partners, including with respect to the equity investment obligation of each partner. Working under the framework established in the Phase 2 Project Development Agreement, Sempra Infrastructure and the other Cameron LNG JV members are investing additional time upfront to reduce construction risk and project costs and better optimize the construction schedule. We expect this process to continue through the end of 2023 and expect to be in a position to make a final investment decision in 2024, subject to executing an EPC contract, securing project financing, and extending the commercial export deadline under the project’s non-FTA approval.

Development of the proposed Cameron LNG Phase 2 project is subject to numerous risks and uncertainties, including securing binding customer commitments; reaching unanimous agreement with our partners to proceed; obtaining, modifying and maintaining permits and regulatory approvals; sufficiently reducing construction risks and project costs; securing certain consents under the existing financing agreements and obtaining sufficient new financing; negotiating, completing and maintaining suitable commercial agreements, including definitive EPC, tolling and governance agreements; reaching a positive final investment decision; and other factors associated with this potential investment. For a discussion of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.

ECA LNG Phase 1 Project. SI Partners owns an 83.4% interest in ECA LNG Phase 1, and an affiliate of TotalEnergies SE owns the remaining 16.6% interest. ECA LNG Phase 1 is constructing a one-train natural gas liquefaction facility at the site of Sempra Infrastructure’s existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa. We do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility. We expect the ECA LNG Phase 1 project to commence commercial operations in the summer of 2025.

We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the ECA LNG Phase 1 project. ECA LNG Phase 1 has definitive 20-year SPAs with an affiliate of TotalEnergies SE for approximately 1.7 Mtpa of LNG and with Mitsui & Co., Ltd. for approximately 0.8 Mtpa of LNG.

In February 2020, we entered into an EPC contract with Technip Energies for the ECA LNG Phase 1 project. Since reaching a positive final investment decision with respect to the project in November 2020, Technip Energies has been working to construct the ECA LNG Phase 1 project. We estimate the total price of the EPC contract to be approximately $1.5 billion, with capital expenditures approximating $2 billion including capitalized interest and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates.

ECA LNG Phase 1 has a five-year loan agreement with a syndicate of seven external lenders that matures in December 2025 for an aggregate principal amount of up to $1.3 billion, of which $782 million was outstanding at September 30, 2023. Proceeds from the loan are being used to finance the cost of construction of the ECA LNG Phase 1 project. We discuss the details of this loan in Note 6 of the Notes to Condensed Consolidated Financial Statements in this report and in Note 7 of the Notes to Consolidated Financial Statements in the Annual Report.

Construction of the ECA LNG Phase 1 project is subject to numerous risks and uncertainties, including maintaining permits and regulatory approvals; construction delays; negotiating, completing and maintaining suitable commercial agreements, including definitive gas supply and transportation agreements; the impact of recent and proposed changes to the law in Mexico; as we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements, an unfavorable decision on certain property disputes and permit challenges that could materially adversely affect construction of this project; and other factors associated with the project and its construction. An unfavorable outcome with respect to any of these factors could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects, including the impairment of all or a substantial portion of the capital costs invested in the project to date. For a discussion of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.

ECA LNG Phase 2 Project. Sempra Infrastructure is developing a second, large-scale natural gas liquefaction project at the site of its existing ECA Regas Facility. We expect the proposed ECA LNG Phase 2 project to be comprised of two trains and one LNG storage tank and produce approximately 12 Mtpa of export capacity. We expect that construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which currently has long-term regasification contracts for 100% of the regasification facility’s capacity through 2028. This makes the decisions on whether, when and how to pursue the proposed ECA LNG Phase 2 project dependent in part on whether the investment in a large-scale liquefaction facility

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would, over the long term, be more beneficial financially than continuing to supply regasification services under our existing contracts.

We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the proposed ECA LNG Phase 2 project.

We have non-binding MOUs and/or HOAs with Mitsui & Co., Ltd., TotalEnergies SE, and ConocoPhillips that provide a framework for their potential offtake of LNG from the proposed ECA LNG Phase 2 project and potential acquisition of an equity interest in ECA LNG Phase 2. The ultimate participation in and offtake by these parties remains subject to negotiation and finalization of definitive agreements, among other factors, and the non-binding MOUs and/or HOAs do not commit any party to enter into definitive agreements with respect to the proposed ECA LNG Phase 2 project.

Development of the proposed ECA LNG Phase 2 project is subject to numerous risks and uncertainties, including securing binding customer commitments; obtaining and maintaining permits and regulatory approvals; obtaining financing; negotiating, completing and maintaining suitable commercial agreements, including definitive EPC, equity acquisition, governance, LNG sales, gas supply and transportation agreements; reaching a positive final investment decision; the impact of recent and proposed changes to the law in Mexico; the property disputes and permit challenges that we reference in the ECA LNG Phase 1 project discussion above; and other factors associated with this potential investment. For a discussion of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.

PA LNG Phase 1 Project. Since making a positive final investment decision in March 2023, 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. We expect the first and second trains of the PA LNG Phase 1 project to commence commercial operations in 2027 and 2028, respectively.

In April 2019, the FERC approved the siting, construction and operation of the PA LNG Phase 1 project facilities, along with certain natural gas pipelines, including the Port Arthur Pipeline Louisiana Connector and Texas Connector, that could be used to supply feed gas to the liquefaction facility when the project is completed. Sempra Infrastructure received authorizations from the DOE in August 2015 and May 2019 that collectively permit the LNG to be produced from the PA LNG Phase 1 project to be exported to all current and future FTA and non-FTA countries. In June 2023, Port Arthur LNG submitted an amendment to its FERC order requesting authorization to increase its work force and implement a 24-hours-per-day construction schedule in order to further enhance construction efficiency while reducing temporal impacts to the community and environment in the vicinity of the project. If approved, the amendment would also provide the EPC contractor with more optionality to meet or exceed the project’s construction schedule, subject to the timing of FERC approval of the amendment. The FERC has published a schedule that anticipates the issuance of an environmental assessment for the project in December 2023.

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 for a 20-year term for approximately 1.4 Mtpa of LNG.

▪ORLEN for a 20-year term for approximately 1 Mtpa of LNG.

▪ENGIE S.A. for a 15-year term for approximately 0.875 Mtpa of LNG.

In February 2020, we entered into an EPC contract, as amended and restated in October 2022, with Bechtel for the PA LNG Phase 1 project. In March 2023, we issued a final notice to proceed under the EPC contract, which has an estimated price of approximately $10.7 billion after change orders. We estimate the capital expenditures for the PA LNG Phase 1 project will be approximately $13 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates.

As we discuss in Note 1 of the Notes to Condensed Consolidated Financial Statements, in March 2023, an indirect subsidiary of SI Partners completed the sale of an indirect 30% NCI in the PA LNG Phase 1 project to an affiliate of ConocoPhillips for aggregate cash consideration of approximately $254 million, subject to customary post-closing adjustments. We used the proceeds from this sale for capital expenditures and other general corporate purposes. In connection with this sale, both SI Partners and ConocoPhillips 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.

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As we discuss in Note 1 of the Notes to Condensed Consolidated Financial Statements, in September 2023, an indirect subsidiary of SI Partners completed the sale of an indirect 42% NCI in the PA LNG Phase 1 project to KKR Denali for aggregate cash consideration of approximately $984 million, including its pro rata equity share of development costs incurred prior to the closing that exceeded $439 million, subject to customary post-closing adjustments. We intend to use the proceeds from this sale for capital expenditures and other general corporate purposes.

Upon closing the sale of NCI to KKR Denali, Sempra holds an indirect interest in the PA LNG Phase 1 project of 19.6%.

As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements, in March 2023, Port Arthur LNG entered into a seven-year term loan facility agreement with a syndicate of lenders for an aggregate principal amount of approximately $6.8 billion and an initial working capital facility agreement for up to $200 million. The facilities mature on March 20, 2030. Proceeds from the loans will be used to finance the cost of construction of the PA LNG Phase 1 project. At September 30, 2023, $243 million of borrowings were outstanding under the term loan facility agreement.

Construction of the PA LNG Phase 1 project is subject to numerous risks and uncertainties, including maintaining and modifying permits and regulatory approvals; construction delays; negotiating, completing and maintaining suitable commercial agreements, including definitive gas supply and transportation agreements; and other factors associated with the project and its construction. An unfavorable outcome with respect to any of these factors could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects, including the impairment of all or a substantial portion of the capital costs invested in the project to date. For a discussion of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.

PA LNG Phase 2 Project. Sempra Infrastructure is developing a second phase of the natural gas liquefaction project that we expect will be a similar size to the PA LNG Phase 1 project. We are progressing the development of the proposed PA LNG Phase 2 project, while continuing to evaluate overall opportunities to develop the entirety of the Port Arthur site as well as potential design changes that could reduce overall emissions, including a facility design utilizing renewable power sourcing and other technological solutions.

In September 2023, the FERC approved the siting, construction and operation of the proposed PA LNG Phase 2 project, including the potential addition of up to two liquefaction trains. In February 2020, Sempra Infrastructure filed an application with the DOE to permit LNG produced from the proposed PA LNG Phase 2 project to be exported to all current and future FTA and non-FTA countries.

Sempra Infrastructure has entered into a non-binding HOA for the negotiation and potential finalization of a definitive SPA with INEOS for approximately 0.2 Mtpa of LNG offtake from the proposed PA LNG Phase 2 project. The ultimate participation in and offtake from the proposed project remains subject to negotiation and finalization of a definitive agreement, among other factors, and the non-binding HOA does not commit any party to enter into a definitive agreement with respect to the proposed project.

Development of the proposed PA LNG Phase 2 project is subject to numerous risks and uncertainties, including securing binding customer commitments; identifying suitable project and equity partners; obtaining and maintaining permits and regulatory approvals; obtaining financing; negotiating, completing and maintaining suitable commercial agreements, including definitive EPC, equity acquisition, governance, LNG sales, gas supply and transportation agreements; reaching a positive final investment decision; and other factors associated with this potential investment. For a discussion of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.

Vista Pacifico LNG Liquefaction Project. Sempra Infrastructure is developing the Vista Pacifico LNG project, a potential natural gas liquefaction, storage, and mid-scale export facility proposed to be located in the vicinity of Topolobampo in Sinaloa, Mexico, under a non-binding MOU with the CFE that contemplates the negotiation of definitive agreements that would cover development of the Vista Pacifico LNG project. The proposed LNG export terminal would be supplied with U.S. natural gas and would use excess natural gas and pipeline capacity on existing pipelines in Mexico with the intent of helping to meet growing demand for natural gas and LNG in the Mexican and Pacific markets.

Sempra Infrastructure received authorization from the DOE to permit the export of U.S.-produced natural gas to Mexico and for LNG produced from the proposed Vista Pacifico LNG facility to be re-exported to all current and future FTA countries 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.

The ultimate participation in and offtake from the proposed project remain subject to negotiation and finalization of definitive agreements, among other factors, and the non-binding MOUs do not commit any party to enter into definitive agreements with respect to the project.

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Development of the proposed Vista Pacifico LNG project is subject to numerous risks and uncertainties, including securing binding customer commitments; identifying suitable project and equity partners; obtaining and maintaining permits and regulatory approvals; obtaining financing; negotiating, completing and maintaining suitable commercial agreements, including definitive EPC, equity acquisition, governance, LNG sales, gas supply and transportation agreements; reaching a positive final investment decision; the impact of recent and proposed changes to the law in Mexico; and other factors associated with this potential investment. For a discussion of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.

Hackberry Carbon Sequestration Project. Sempra Infrastructure is developing the potential Hackberry Carbon Sequestration project near Hackberry, Louisiana. This proposed project under development is designed to permanently sequester carbon dioxide from the Cameron LNG Phase 1 facility and the proposed Cameron LNG Phase 2 project. In the third quarter of 2021, Sempra Infrastructure filed an application with the EPA for a Class VI carbon injection well to advance this project.

In May 2022, Sempra Infrastructure, TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation signed a Participation Agreement for the development of the proposed Hackberry Carbon Sequestration project. In May 2023, the Participation Agreement was amended and restated in connection with ongoing progress of the work program and budget for the proposed project. The Participation Agreement contemplates that the combined Cameron LNG Phase 1 facility and proposed Cameron LNG Phase 2 project would potentially serve as the anchor source for the capture and sequestration of carbon dioxide by the proposed project. It also provides the basis for the parties to acquire an equity interest by entering into a JV with Sempra Infrastructure for the Hackberry Carbon Sequestration project. In addition to the amended and restated Participation Agreement, in May 2023, Sempra Infrastructure and Cameron LNG JV entered into a non-binding HOA, which sets forth a framework for further development of the Hackberry Carbon Sequestration project.

Development of the proposed Hackberry Carbon Sequestration project is subject to numerous risks and uncertainties, including securing binding customer commitments; obtaining required consents from the Cameron LNG JV members; identifying suitable project and equity partners; obtaining and maintaining permits and regulatory approvals; obtaining financing; negotiating, completing and maintaining suitable commercial agreements, including definitive EPC, equity acquisition and governance agreements; reaching a positive final investment decision; and other factors associated with this potential investment. For a discussion of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.

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 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 5 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, 5 and 8 of the Notes to Condensed Consolidated Financial Statements.

Energy Networks

Sonora Pipeline. Sempra Infrastructure’s Sonora natural gas pipeline consists of two segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE.

A portion of the Guaymas-El Oro segment of the Sonora natural gas pipeline crosses into territory owned by the Yaqui tribe who, with the exception of some members living in the Bácum community, granted its consent and a right-of-way easement agreement for the pipeline in its territory. 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. Legal challenges raised by representatives of the Bácum community, which we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements, have prevented Sempra Infrastructure from making repairs to put the pipeline back in service. Such legal challenges were definitively resolved in March 2023 based on the agreement by the CFE and Sempra Infrastructure to re-route the portion of the pipeline that is in the Yaqui territory.

Discussions with the CFE regarding the future of the pipeline are ongoing in accordance with a non-binding MOU announced in January 2022 that, among other matters, addresses efforts to proceed with re-routing a portion of the pipeline, which will require either an extension of the service start date, as discussed below, or a separate definitive arrangement between Sempra Infrastructure and the CFE concerning the restarting of service on the pipeline. In July 2022, Sempra Infrastructure and the CFE entered into a Shareholders’ Agreement that establishes a framework for a JV between the parties to work on restarting service on

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the pipeline, including the potential re-routing of a portion of the pipeline. This agreement is subject to a number of conditions to be satisfied before it becomes effective, including regulatory and corporate authorizations.

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. If the parties do not agree on a definitive arrangement to re-route a portion of the pipeline or the parties do not agree on a new service start date by November 30, 2023, Sempra Infrastructure retains the right to terminate the contract and seek to recover its reasonable and documented costs and lost profits.

At September 30, 2023, Sempra Infrastructure had $411 million in PP&E, net, related to the Guaymas-El Oro segment of the Sonora pipeline, which could be subject to impairment if Sempra Infrastructure is unable to re-route a portion of the pipeline (which has not been agreed to by the parties, but is subject to negotiation pursuant to a non-binding MOU and a Shareholders’ Agreement, as described above) and resume operations or if Sempra Infrastructure terminates the contract and is unable to obtain recovery, which in each case could have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.

Refined Products Terminals. In May 2022, Sempra Infrastructure substantially completed construction of a terminal for the receipt, storage, and delivery of refined products in Topolobampo, at which time commissioning activities commenced. We expect the Topolobampo terminal will commence commercial operations in the first half of 2024, subject to receipt of the CRE’s approval of the regulated rates.

Sempra Infrastructure is also developing terminals for the receipt, storage, and delivery of refined products in the vicinity of Manzanillo and Ensenada.

Development and construction of refined products terminals is subject to a number of risks and uncertainties. For a discussion of these risks and uncertainties, see “Part I – Item 1A. Risk Factors” in the Annual Report.

Port Arthur Pipeline Louisiana Connector. Sempra Infrastructure has begun the procurement and engineering activities related to the construction of 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. In July 2023, Sempra Infrastructure filed a limited amendment application with the FERC 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. The FERC has published a schedule that anticipates the issuance of an environmental assessment for the project in February 2024. 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.

Development and construction of the Port Arthur Pipeline Louisiana Connector is subject to a number of risks and uncertainties. For a discussion of these risks and uncertainties, see “Part I – Item 1A. Risk Factors” in the Annual Report.

Louisiana (LA) Storage. Sempra Infrastructure has begun the procurement and engineering activities related to the construction of LA 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 LA 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 $300 million, including capitalized interest at the project level and project contingency. The actual amount of these capital expenditures may differ substantially from our estimates.

Development and construction of LA Storage is subject to a number of risks and uncertainties. For a discussion of these risks and uncertainties, see “Part I – Item 1A. Risk Factors” in the Annual Report.

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Legal and Regulatory Matters

See Note 10 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:

Energía Costa Azul

▪Land Disputes

▪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

▪Amendments to Mexico’s Hydrocarbons Law

▪Amendments to Mexico’s Electricity Industry Law

Sempra Infrastructure and other parties affected by these amendments to Mexican law have challenged them by filing amparo and other claims, some of which remain pending. An unfavorable decision on one or more of these amparo or other challenges, the impact of the amendments that have become effective (due to unsuccessful amparo challenges or otherwise), or the possibility of future reforms to the energy industry through additional amendments to Mexican laws, regulations or rules (including through amendments to the constitution) may impact our ability to operate our facilities at existing levels or at all, may result in increased costs for Sempra Infrastructure and its customers, may adversely affect our ability to develop new projects, may result in decreased revenues and cash flows, and may negatively impact our ability to recover the carrying values of our investments in Mexico, any of which may have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.

SOURCES AND USES OF CASH

The following tables include only significant changes in cash flow activities for each of our registrants.


CASH FLOWS FROM OPERATING ACTIVITIES
(Dollars in millions)
Nine months ended September 30,	Sempra		SDG&E		SoCalGas
2023	$	5,129	$	1,484	$	1,264
2022	1,455		1,368		(762)
Change	$	3,674	$	116	$	2,026

Lower net decrease in Reserve for Aliso Canyon costs, current and noncurrent, due to $2,089 lower payments offset by $258 lower accruals	$	1,831			$	1,831
Change in net margin posted	1,201		$	(62)
Change in income taxes receivable/payable, net	371		70
Higher net income, adjusted for noncash items included in earnings	338				466
Change in accounts receivable	315		(179)		242
Change in net regulatory assets/liabilities, current and noncurrent	260		314		(51)
Change in deferred revenue	111
Higher GHG emission obligations	77				68
Change in collateral held in lieu of a customer’s letters of credit	(76)
Proceeds received in 2022 from insurance receivable for Aliso Canyon costs	(350)				(350)
Change in accounts payable	(583)		(89)		(291)
Change in prepaid expenses			23
Change in interest payable			22
Change in amounts due to/from unconsolidated affiliates			(91)		50
Other	179		108		61
	$	3,674	$	116	$	2,026

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CASH FLOWS FROM INVESTING ACTIVITIES
(Dollars in millions)
Nine months ended September 30,	Sempra		SDG&E		SoCalGas
2023	$	(6,304)	$	(1,838)	$	(1,451)
2022	(3,183)		(1,643)		(1,394)
Change	$	(3,121)	$	(195)	$	(57)

Increase in capital expenditures	$	(2,534)	$	(242)	$	(57)
Repayment in 2022 of note receivable from IMG	(626)
Other	39		47
	$	(3,121)	$	(195)	$	(57)


CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
Nine months ended September 30,	Sempra		SDG&E		SoCalGas
2023	$	2,198	$	593	$	192
2022	1,936		469		2,172
Change	$	262	$	124	$	(1,980)

Change in borrowings and repayments of short-term debt, net	$	2,067	$	196	$	278
Higher contributions from NCI	1,021
Lower repurchases of common stock	446
Higher (lower) issuances of short-term debt with maturities greater than 90 days	205				(800)
Higher common dividends paid	(39)
Settlement of cross-currency swaps	(99)
Higher distributions to NCI	(143)
Lower proceeds from sales of NCI	(494)
Higher payments on long-term debt and finance leases	(725)		(438)		(305)
(Higher) lower payments for commercial paper and other short-term debt with maturities greater than 90 days	(1,928)		375		(800)
Equity contribution from Sempra in 2022					(650)
Higher issuances of long-term debt					300
Other	(49)		(9)		(3)
	$	262	$	124	$	(1,980)

Capital Expenditures and Investments


CAPITAL EXPENDITURES AND INVESTMENTS
(Dollars in millions)
	Nine months ended September 30,
	2023		2022
SDG&E	$	1,893	$	1,651
SoCalGas	1,451		1,394
Sempra Texas Utilities	270		256
Sempra Infrastructure	2,736		508
Parent and other	5		6
Total	$	6,355	$	3,815

Having reached a positive final investment decision for the PA LNG Phase 1 project and Oncor having received a final order from the PUCT in its comprehensive base rate review, we have updated our expected capital expenditures and investments from what we disclosed in “Part II – Item 7. MD&A – Capital Resources and Liquidity” in the Annual Report. From 2023 through 2027, we expect to make aggregate capital expenditures and investments of approximately $38.6 billion, subject to the factors described below, which could cause these estimates to vary substantially. Capital expenditure amounts include capitalized interest and AFUDC related to debt.

When (i) including Sempra’s proportionate ownership interest in expected capital expenditures at unconsolidated equity method investees while excluding Sempra’s expected capital contributions to those unconsolidated equity method investees and (ii)

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excluding NCI’s proportionate ownership interest in expected capital expenditures at Sempra and at unconsolidated equity method investees, we expect capital expenditures from 2023 through 2027 to total $40 billion. This $40 billion expectation reflects an increase compared to the aggregate capital expenditures, calculated in the same manner, that we forecasted in 2017 for the period from 2017 through 2021, which was $15 billion. We further expect a 10% to 20% utility-focused increase above this $40 billion amount when we update our capital expenditures plan for 2024 through 2028.

Our utilities represent approximately 90% of this $40 billion capital expenditures plan. We expect this significant capital investment in transmission and distribution improvements at our regulated public utilities to increase our utilities’ rate base, which has grown approximately 3.2 times from 2017 to 2022, based on a rate base of $8.5 billion and $5.5 billion at SDG&E and SoCalGas, respectively, in 2017 compared to $13.8 billion, $10.5 billion, $20.7 billion, and $256 million at SDG&E, SoCalGas, Oncor, and Sharyland Utilities, L.L.C., respectively, in 2022. For SDG&E and SoCalGas, rate base is the value of assets on which SDG&E and SoCalGas are permitted to earn a specified rate of return in accordance with rules set by regulatory agencies, including the CPUC and, for SDG&E, the FERC, which is calculated using a 13-month weighted average in accordance with CPUC methodology as adopted in rate-setting proceedings. For Oncor and Sharyland Utilities, L.L.C., rate base represents the total estimated invested capital, as adjusted in accordance with PUCT rules, at the end of the previous calendar year as reported in the Earnings Monitoring Report filed with the PUCT on an annual basis.

In 2023, we expect to make capital expenditures and investments of approximately $9.4 billion, which is an increase from the $5.7 billion projected in “Part II – Item 7. MD&A – Capital Resources and Liquidity” in the Annual Report. The increase is primarily attributable to an increase of $3.4 billion at Sempra Infrastructure primarily related to the PA LNG Phase 1 project, an increase of $200 million at SDG&E related to energy storage projects and an increase of $100 million at Sempra Texas Utilities. We expect the majority of our capital expenditures and investments in 2023 will relate to construction of the PA LNG Phase 1 project, ECA LNG Phase 1 project and natural gas pipelines at Sempra Infrastructure, and transmission and distribution improvements at our regulated public utilities.

Our level of capital expenditures and investments in the next few years may vary substantially and will depend on, among other things, the cost and availability of financing, regulatory approvals, changes in tax law and business opportunities providing desirable rates of return. See “Part I – Item 1A. Risk Factors” in the Annual Report for a discussion of these and other factors that could affect future levels of our capital expenditures and investments. We intend to finance our capital expenditures in a manner that will maintain our investment-grade credit ratings and capital structure, but there is no guarantee that we will be able to do so.

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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