SAN DIEGO GAS & ELECTRIC CO

OVERVIEW

Sempra

Capital Recycling Program

We regularly review our portfolio of assets with a view toward allocating capital to the businesses we believe can further enhance shareholder value. In September 2025, we entered into an agreement to sell a 45% equity interest in SI Partners to the KKR Partners for $9.99 billion, subject to adjustments. We expect to complete the sale in the third quarter of 2026, subject to closing conditions. SI Partners expects to complete the sale of Ecogas in August 2026 for 9.0 billion Mexican pesos (approximately $500 million in U.S. dollar-equivalent), subject to adjustments. We discuss these sales further in Note 6 of the Notes to Condensed Consolidated Financial Statements and below in “Sempra Infrastructure.”

Liquidity

We expect to meet our cash requirements primarily through:

▪cash flows from operations

▪unrestricted cash and cash equivalents

▪borrowings under or supported by our credit facilities

▪other incurrences of debt which may include issuing debt securities and obtaining term loans

▪selling assets or equity interests in our subsidiaries or development projects, including the planned sale of a portion of our equity interest in SI Partners

▪issuing equity securities under our ATM program or other offerings

▪funding from NCI owners or CRNCI owners

We believe that these cash flow sources, combined with available funds, will be adequate to fund our operations in both the short-term and long-term, including to:

▪finance capital expenditures

▪repay debt

▪fund dividends

▪fund contractual and other obligations and otherwise meet liquidity requirements

▪fund capital contributions

▪fund new business or asset acquisitions

Sempra, SDG&E and SoCalGas currently have reasonable access to the money markets and capital markets and are not currently constrained in their ability to borrow or otherwise raise money at market rates from commercial banks, under existing revolving credit facilities, through public offerings of debt or equity securities (including under our ATM program or other offerings), or through private placements of debt supported by our revolving credit facilities in the case of commercial paper. However, our ability to access these markets or obtain credit from commercial banks outside of our committed revolving credit facilities could become materially constrained if economic conditions worsen or disruptions to or volatility in these markets increase. In addition, our financing activities, actions by credit rating agencies and prevailing interest rates, as well as many other factors, could negatively affect the availability and cost of both short-term and long-term debt and equity financing. Also, cash flows from operations may be impacted by the timing and outcomes of regulatory proceedings, commencement and completion of, and potential cost overruns for, large projects and other material events. If cash flows from operations were to be significantly reduced or we were unable to borrow or obtain other financing under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety or reliability) and investments in new businesses. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our goal to maintain our investment-grade credit ratings.

ATM Program and Forward Sale Agreements

In November 2024, we established an ATM program providing for the offer and sale of shares of Sempra common stock having an aggregate gross sales price of up to $3.0 billion through agents acting as our sales agents or as forward sellers or directly to the agents as principals. The shares may be offered and sold in amounts and at times to be determined by us from time to time.

We have entered into two forward sale agreements for the sale of shares of Sempra common stock under the ATM program that remain subject to future settlement. The shares offered pursuant to the forward sale agreements were borrowed by the applicable forward purchaser and therefore were not newly issued shares. We did not initially receive any proceeds from the sale of shares pursuant to the forward sale agreements. These forward sale agreements may be settled on one or more dates specified by us occurring no later than the final settlement date under the applicable agreement. Although we may settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may, subject to certain conditions, elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements. The forward sale agreements are also subject to acceleration by the applicable forward purchaser upon the occurrence of certain events. The principal terms of these forward sale agreements at June 30, 2026 are as follows:

(1) Expected net proceeds assumes full physical settlement, is net of sales commission but does not deduct other equity issuance costs, and is subject to certain adjustments pursuant to the applicable forward sale agreement.

At June 30, 2026, approximately $2.6 billion of common stock remains available for sale under the ATM program. We provide additional information about these forward sale agreements in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

We further discuss these activities, including the intended use of proceeds and effect on diluted EPS, in Note 11 of the Notes to Condensed Consolidated Financial Statements.

Available Funds

Our committed lines of credit provide liquidity and support commercial paper. Sempra, SDG&E and SoCalGas each have a committed line of credit expiring in 2030. Sempra Infrastructure has five committed lines of credit expiring on various dates from 2026 through 2030 and an uncommitted line of credit expiring on August 12, 2026, which are included in the disposal group that is classified as held for sale. These lines of credit remain legally accessible and are sources of available credit to Sempra Infrastructure until completion of the planned sale of a portion of our equity interest in SI Partners, which we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements.

(1) Sempra includes $113 held in foreign jurisdictions, which is included in the $154 that is classified as Assets Held for Sale in the Sempra Condensed Consolidated Balance Sheet. 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 7 of the Notes to Condensed Consolidated Financial Statements. Because our commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding and any letters of credit outstanding as a reduction to the available unused credit.

Short-Term Borrowings

We use short-term debt primarily to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures or acquisitions. SDG&E and SoCalGas use short-term debt primarily to meet working capital needs or to help fund event-specific costs. Commercial paper and lines of credit were our primary sources of short-term debt funding in the first six months of 2026.

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

Long-Term Debt Activities

Significant issuances of and payments on long-term debt in the first six months of 2026 included the following:

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

Credit Ratings

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

The credit ratings of Sempra, SDG&E and SoCalGas remained at investment grade levels in the first six months of 2026.

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

A downgrade of Sempra’s or any of its subsidiaries’ credit ratings or rating outlooks may, depending on the severity, result in the imposition of new financial or other burdensome covenants or a requirement for collateral to be posted in the case of certain financing arrangements and may materially and adversely affect the market prices of their equity and debt securities, the rates at which borrowings are made and commercial paper is issued, and the various fees on their outstanding credit facilities. This could make it more costly for Sempra, SDG&E, SoCalGas and Sempra’s other subsidiaries to issue debt or equity securities, to borrow under credit facilities and to raise certain other types of financing. We provide additional information about our credit ratings at Sempra, SDG&E and SoCalGas in “Part I – Item 1A. Risk Factors” in the Annual Report.

Sempra has agreed that, if the credit rating of Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. Oncor’s senior secured debt is rated A2, A and A at Moody’s, S&P and Fitch, respectively, at June 30, 2026.

Sempra California

SDG&E’s and SoCalGas’ operations have historically provided relatively stable earnings and liquidity. Their future performance and liquidity will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by legislatures, litigation and the changing energy marketplace, as well as other matters described in this report and the Annual Report. SDG&E and SoCalGas expect that the available unused funds from their credit facilities described above, which also supports their commercial paper programs, cash flows from operations, and other incurrences of debt including issuing debt securities and obtaining term loans will continue to be adequate to fund their respective current operations and planned capital expenditures. SDG&E and SoCalGas manage their capital structures and pay dividends as approved by their respective boards of directors.

SDG&E and SoCalGas have regulatory mechanisms to recover credit losses and thus record changes in the allowances for credit losses related to accounts receivable that are probable of recovery in regulatory accounts. Although SDG&E and SoCalGas have regulatory mechanisms to recover credit losses, any delay in payments by customers impacts the timing of their respective cash flows.

As we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements, changes in regulatory balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change between over and undercollected status, may have a significant impact on cash flows. These changes generally represent the difference between when costs are incurred and when they are ultimately recovered or refunded in rates through billings to customers.

CPUC GRC

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

Existing and Anticipated Requests for Recovery of Specified Safety, Maintenance and Reliability Investments. The 2024 GRC provides SDG&E and SoCalGas with numerous mechanisms to seek cost recovery of specified projects and programs. We expect that the requests for cost recovery of these projects and programs, which remain subject to CPUC approval, may result in additional amounts of authorized revenue requirement. These projects and programs include (i) the Track 3 request that we describe below, (ii) the ability to file advice letters to implement the revenue requirements associated with the costs of SDG&E’s Moreno compressor station project and SoCalGas’ Honor Rancho compressor station and customer information system replacement projects, which projects were all approved by the CPUC subject to applicable cost caps, and (iii) the opportunity to file separate applications for cost recovery of mobile home park and gas integrity management programs at both SDG&E and SoCalGas, advanced metering infrastructure replacements at SDG&E, and other projects and programs.

2024 GRC Track 3. In April 2025, SDG&E and SoCalGas each submitted additional requests to the CPUC in the 2024 GRC, known as Track 3 requests. SDG&E submitted a request seeking review and recovery of its WMP costs incurred in 2023 that were in addition to the amounts authorized in the 2019 GRC. In March 2026 and amended in April and May of 2026, SDG&E provided supplemental testimony in its Track 3 request for drone inspection and repair program costs incurred from 2019 through 2022 that were transferred from its Track 2 request as a result of the Track 2 FD. The supplemental testimony seeks review and recovery of $659 million of direct WMP and drone inspection and repair program costs. In June 2026, SDG&E and three of four intervenors filed an offer of settlement with the CPUC addressing recovery of its 2023 WMP costs and 2019-2022 drone inspection and repair program costs. If approved, the settlement would reduce SDG&E’s requested revenue requirement from $766 million to $621 million. The settlement remains subject to CPUC approval, and SDG&E expects to receive an FD in the second half of 2026. Separately, SDG&E and SoCalGas submitted a combined request seeking review and recovery of $240 million of PSEP costs incurred from 2014 through 2019 and $499 million of PSEP costs incurred from 2015 through 2020, respectively. SDG&E and SoCalGas expect to receive an FD for their Track 3 requests related to their PSEP costs in the second half of 2026.

Revenue requirements associated with the Track 3 requests have been recorded in regulatory accounts and any disallowances resulting from Track 3 would be recorded as an expense on the Sempra, SDG&E and SoCalGas Condensed Consolidated Statements of Operations. SDG&E and SoCalGas are authorized interim rate recovery of up to 50% of the recorded PSEP regulatory account balance at the end of each year. Such interim rate recovery is subject to refund, contingent on the reasonableness review decision for their Track 3 requests.

SDG&E

Wildfire Fund and Continuation Account

The 2019 Wildfire Legislation established the Wildfire Fund and the 2025 Wildfire Legislation established the Continuation Account (collectively, the Wildfire Legislation), which offer liquidity to reimburse wildfire-related claims incurred by participating California electric IOUs in excess of $1.0 billion, subject to the coverage of each fund. The Wildfire Fund and the Continuation Account, if it becomes operative, could be materially reduced, exhausted, or terminated due to claims by SDG&E or other participating IOUs related to fires caused by utility conduct or operations, or SDG&E could fail to maintain a valid annual safety certification from the OEIS or meet other requirements, any of which could result in SDG&E losing eligibility for the Wildfire Legislation’s liability cap and the other protections afforded by these funds. As a result, a fire resulting from the conduct or operations of any participating California electric IOU could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects, with potentially material additional exposure if SDG&E’s conduct or operations is determined to be a cause of a fire and SDG&E is found to have acted imprudently.

We further describe the 2019 Wildfire Legislation and SDG&E’s commitment to make annual shareholder contributions to the Wildfire Fund through 2028, as well as the 2025 Wildfire Legislation and related Continuation Account, in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

2019 Wildfire Legislation. SDG&E is exposed to the risk that the participating California electric IOUs may incur third-party wildfire costs for which they will seek recovery from the Wildfire Fund with respect to wildfires that have occurred since enactment of the 2019 Wildfire Legislation in July 2019. In such a situation, SDG&E may recognize a reduction of its Wildfire Fund asset and record accelerated amortization against earnings when available coverage is reduced due to recoverable claims from any of the participating IOUs. The carrying value of SDG&E’s Wildfire Fund asset totaled $248 million at June 30, 2026.

In July 2026, a participating IOU publicly disclosed that it has received, or expects to receive, approximately $1.38 billion in aggregate reimbursements from the Wildfire Fund for eligible claims related to wildfires that occurred in 2019 and 2021. Also in July 2026, another participating IOU publicly disclosed it has received, or expects to receive, approximately $645 million in aggregate reimbursements from the Wildfire Fund for losses incurred and expected to be incurred in connection with one of the LA Fires, which was found by the LACoFD and CAL FIRE investigators to have been caused by such IOU’s equipment. The administrator of the Wildfire Fund has confirmed that this wildfire qualifies as a “covered wildfire” for purposes of accessing the Wildfire Fund, and the scope of potential damages caused by this fire could materially reduce or exhaust the Wildfire Fund. The participating IOU whose equipment was found to have caused this LA Fire stated that it is currently unable to reasonably estimate a range of potential losses associated with this event. Accordingly, SDG&E is unable to estimate a range of potential loss resulting from any reduction in available coverage from the Wildfire Fund. In addition to the risks described above, a material reduction, exhaustion or termination of the Wildfire Fund may require SDG&E to recognize a reduction to its Wildfire Fund asset up to its carrying value.

2025 Wildfire Legislation. In September 2025, the 2025 Wildfire Legislation was signed into law to establish, among other things, the Continuation Account, a new state-administered account with up to $18.0 billion of additional liquidity to reimburse catastrophic wildfire-related claims incurred by participating California electric IOUs, including SDG&E, if certain conditions are met.

FERC Rate Matters

SDG&E files separately with the FERC for its authorized transmission revenue requirement, ROE and capital structure on FERC-regulated electric transmission operations and assets.

TO5 Settlement. SDG&E’s TO5 settlement provided for an ROE of 10.60%, consisting of a base ROE of 10.10% plus the California ISO adder. In December 2024, the FERC issued an order, which SDG&E has appealed, finding that SDG&E is not eligible for the California ISO adder and that the TO5 adder refund provision had been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019.

TO6 Settlement. In June 2026, the FERC issued an order approving the TO6 offer of settlement. The TO6 settlement is retroactively effective as of June 1, 2025, and remains in effect until terminated by a notice provided in March of any year. Among other things, the settlement increases SDG&E’s authorized base ROE from 10.10% to 10.28% and establishes a hypothetical capital structure with 54% common equity. SDG&E recognized the retroactive impact in the second quarter of 2026. The TO6 settlement does not affect SDG&E’s appeal of the FERC’s disallowance of the inclusion of the California ISO adder.

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.

LA Fires

The LA Fires burned in SoCalGas’ service territory. The California Department of Forestry and Fire Protection estimates that the Palisades and Eaton fires destroyed approximately 16,200 structures and damaged approximately 2,000 structures. Although the majority of SoCalGas’ infrastructure in the fire-affected areas is underground, these fires resulted in service disruptions, response costs and damage to some of SoCalGas’ infrastructure and third-party property. SoCalGas is subject to pending litigation with respect to the operation of its system and damage sustained as a result of the fires, which we discuss in Note 13 of the Notes to Condensed Consolidated Financial Statements. We cannot estimate the timing, costs, other impacts or ultimate outcome of these matters, which are inherently uncertain and subject to a number of risks that we discuss in “Part I – Item 1A. Risk Factors” in the Annual Report.

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

Sempra Texas Utilities

Oncor relies on external financing as a significant source of liquidity for its capital requirements. In the event that Oncor is unable to meet its capital requirements, access sufficient capital, or raise capital on favorable terms to finance its ongoing needs, we may elect to make additional capital contributions to Oncor (as our commitments to the PUCT prohibit us from making loans to Oncor), which could be substantial and reduce the cash available to us for other purposes, increase our indebtedness and ultimately materially adversely affect our results of operations, financial condition, cash flows and/or prospects. Oncor’s ability to make distributions may be limited by factors such as its credit ratings, regulatory capital requirements, increases in its capital plan, debt-to-equity ratio approved by the PUCT and other restrictions and considerations. In addition, Oncor will not make distributions if a majority of Oncor’s independent directors or any minority member director determines it is in the best interests of Oncor to retain such amounts to meet expected future requirements.

Oncor

ERCOT Developments. Oncor operates in the ERCOT market. ERCOT is developing plans to address anticipated load growth in Texas, including in Oncor’s service territory. Some of these plans, as well as the increase in data centers and other large load customers throughout the state, have been the subject of heightened engagement from the public and state and local officials regarding costs, timing, alternatives and implementation, including scrutiny and calls by some for modifications, delays or denials of ERCOT’s 765-kV Strategic Transmission Expansion Plan (STEP) and other 765-kV transmission line projects. ERCOT also has implemented a PUCT-approved, system-wide approach to sequence large load customer interconnection requests in a recurring batch interconnection framework, the first stage of which is known as the batch zero process. ERCOT recently indicated it is suspending certain batch zero notifications in response to a directive for the PUCT and ERCOT to conduct a comprehensive audit of all data centers advancing through ERCOT’s interconnection process, resulting in uncertainty about the timing for notifications of project placement in this process.

The outcome of public and legislative focus on ERCOT’s proposed 765-kV transmission line plans and the timing for and determination of the customer projects eligible to advance in the batch zero interconnection process could have various and potentially material financial, operational, legal and other impacts on Oncor as a transmission service provider, including with respect to its capital expenditures and, in turn, Sempra’s capital expenditures and investments. For instance, Oncor’s capital expenditures plan from 2026 through 2030 and announced incremental capital expenditure opportunities within this period include significant amounts attributable to STEP. These and other political, legal and regulatory developments related to anticipated load growth in Oncor’s service territory and large load customers could have a significant impact on Oncor’s business, and the execution of these proposed plans is subject to numerous risks and uncertainties. For a discussion of some of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.

2025 Comprehensive Base Rate Review. In April 2026, the PUCT issued an order in Oncor’s comprehensive base rate review proceeding approving the terms of an unopposed comprehensive rate case settlement among the parties to the proceeding. The order provides for an annual revenue requirement of approximately $6.97 billion, an increase of approximately $560 million, or 8.7%, over Oncor’s adjusted annualized revenues as provided in the rate application. The order also provides for a revised regulatory capital structure ratio of 56.5% debt to 43.5% equity, an authorized ROE of 9.75%, and an authorized cost of debt of 4.94%. This represents an improvement from Oncor’s previously authorized regulatory capital structure ratio of 57.5% debt to 42.5% equity, return on equity of 9.70%, and cost of debt of 4.39%. The new base rates took effect on June 1, 2026.

Under a prior settlement regarding interim rates, Oncor is permitted to surcharge the difference between the new billing rates and its rates that had been in effect for the period from January 1, 2026 to June 1, 2026. Oncor filed the surcharge in a separate compliance filing in June 2026, and the requested surcharge took effect on August 1, 2026. In the second quarter of 2026, Oncor recognized the impact of the surcharge, including amounts related to the first quarter of 2026. As a result, our second-quarter equity earnings include a favorable impact of approximately $50 million, net of income tax, attributable to the first quarter.

Unified Tracker Mechanism. In June 2025, Texas House Bill 5247 was signed into law and became effective. The bill established the UTM, which allows qualifying electric utilities to apply for a single interim rate update annually through 2035 for cost recovery of certain transmission and distribution capital investments. Since the June 2025 effective date of the bill, Oncor has recognized and expects to continue recognizing revenues and corresponding regulatory assets for recoverable costs related to UTM-eligible transmission and distribution capital investments, including depreciation expense, carrying costs on unrecovered balances and related taxes.

In April 2026, Oncor filed its first annual UTM application with the PUCT seeking to include in rates approximately $4.4 billion of eligible transmission and distribution net capital investment costs incurred from January 1, 2025 to December 31, 2025. The UTM application is subject to PUCT review and approval. Oncor anticipates an order and updated rates in the second half of 2026.

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 expects to fund capital expenditures, investments and operations in part with available funds, including existing credit facilities, and cash flows from operations from the Sempra Infrastructure businesses. We expect Sempra Infrastructure will require additional funding for the development and expansion of its portfolio of projects, which may be financed through a combination of funding from the parent and NCI owners, bank financing, issuances of debt, project financing, partnering in JVs and asset sales.

In the six months ended June 30, 2026 and 2025, Sempra Infrastructure distributed $135 million and $91 million, respectively, to its NCI owners, and NCI owners contributed $74 million and $83 million, respectively, to Sempra Infrastructure.

Sempra Infrastructure is in various stages of development or construction of natural gas liquefaction projects, pipeline and terminal projects, and renewable power generation and sequestration projects, which we describe below. The successful development and/or construction of these projects is subject to numerous risks and uncertainties.

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

▪secure binding customer commitments

▪identify suitable project and equity partners

▪obtain sufficient financing

▪reach agreement with project partners or other applicable parties to proceed

▪obtain, modify, and/or maintain permits and regulatory approvals, including LNG export applications to non-FTA countries and any applicable approvals in Mexico

▪negotiate, complete and maintain suitable commercial agreements, which may include EPC, tolling, equity acquisition, governance, LNG sales, gas supply and transportation contracts

▪reach a positive FID

With respect to projects under construction, these risks and uncertainties include, in addition to the risks described above as applicable to each project, construction delays, unforeseen design flaws, cost overruns, stakeholder relations issues and other construction-related issues.

An unfavorable outcome with respect to any of these factors could have a material adverse effect on (i) the development and construction of the applicable project, including a potential impairment of all or a substantial portion of the capital costs invested in the project to date, which could be material, and (ii) for any project that has reached a positive FID, Sempra’s results of operations, financial condition, cash flows and/or prospects. For a further discussion of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.

The descriptions below discuss several HOAs, MOUs and other non-binding development agreements with respect to Sempra Infrastructure’s various development projects. These arrangements do not commit any party to enter into definitive agreements or otherwise participate in the applicable project, and the ultimate participation by the parties remains subject to negotiation and finalization of definitive agreements, among other factors. The descriptions below also discuss certain financing arrangements for several of Sempra Infrastructure’s projects in development and under construction; we discuss these and other financing arrangements related to these projects in more detail in Note 7 of the Notes to Condensed Consolidated Financial Statements in this report and the Notes to Consolidated Financial Statements in the Annual Report.

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

SI Partners

As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements, in September 2025, we entered into an agreement to sell a 45% equity interest in SI Partners to the KKR Partners for $9.99 billion, subject to adjustments. We expect this sale to close in the third quarter of 2026, subject to certain conditions, including receipt of consents or waivers from certain lenders, partners and others; the absence of a material adverse effect on SI Partners; the absence of specific downgrade events under certain financing arrangements; and other customary closing conditions. As a result of satisfying all applicable criteria in September 2025, we classified SI Partners’ assets and liabilities as held for sale and ceased recording depreciation and amortization.

The agreement provides that, subject to adjustments and the closing date, the purchase price will be paid to Sempra as follows:

▪$4.65 billion in cash at closing;

▪$4.14 billion plus interest compounded quarterly at 7.5% per annum through maturity on December 31, 2027 (totaling $4.6 billion with principal and interest based on an assumed closing date in the third quarter of 2026) under instruments backed by equity commitment letters; and

▪$1.2 billion plus interest compounded quarterly at 8.5% per annum before January 1, 2031 and then 10.0% per annum through maturity seven years and 91 days after closing (totaling $2.3 billion with principal and interest if held to maturity, which would be less if prepaid, subject to a make-whole provision for interest through December 31, 2027) under promissory notes.

The purchase price is subject to adjustments for changes in net debt, net working capital and capital expenditures as of December 31, 2025, among others, and is subject to further adjustments for certain capital contributions by and distributions to Sempra in 2026 before the closing. In addition, $338 million of transaction fees incurred by the KKR Partners will be deducted from the purchase price at closing, and Sempra will pay a $340 million development credit for the KKR Partners’ share of development costs through 2027. There may also be post-closing purchase price adjustments based on the performance through 2028 of certain wind power facilities, which could be affected by recent Mexican regulatory changes that impact the transmission rate methodology for these facilities, and adjustments to reflect any capital expenditure overruns or underruns associated with the ECA LNG Phase 1 project under construction and potential costs associated with third party consents or waivers.

Subject to closing, the KKR Partners will own 65% of SI Partners, Sempra will retain a 25% interest and ADIA will retain a 10% interest. As a result of Sempra’s loss of a controlling financial interest in SI Partners, we will deconsolidate SI Partners and account for our 25% interest in SI Partners under the equity method within the existing Sempra Infrastructure segment.

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

LNG

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

Cameron LNG JV has received major permits and FTA and non-FTA approvals associated with the potential expansion. In November 2025, we received approval from the FERC to extend the deadline for construction authorization until March 2033. The non-FTA approval for the proposed Cameron LNG Phase 2 project includes, among other things, a May 2026 deadline to commence commercial exports. In April 2026, the DOE extended that deadline to March 2033.

SI Partners and the other Cameron LNG JV members, namely affiliates of TotalEnergies SE, Mitsui & Co., Ltd. and Japan LNG Investment, LLC, have entered into a non-binding HOA for the potential development of the Cameron LNG Phase 2 project. The non-binding HOA provides a commercial framework for the proposed project, including the contemplated allocation to SI Partners of 50.2% of the fourth train production capacity and 25% of the debottlenecking capacity from the project under tolling agreements. The non-binding HOA contemplates the remaining capacity to be allocated equally to the existing Cameron LNG Phase 1 facility customers.

Entergy Louisiana, LLC, a subsidiary of Entergy Corporation, and Cameron LNG JV have an electricity service agreement (and related ancillary agreements) for the supply to Cameron LNG JV of up to 950 MW of power from renewable sources in Louisiana.

Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the members, including with respect to the equity investment obligation of each member. Expansion of the Cameron LNG Phase 1 facility beyond the first three trains is also subject to certain restrictions and conditions under the JV project financing agreements, including, among others, scope restrictions on expansion of the project unless appropriate prior consent is obtained from the existing project lenders. An FID remains subject to, among other things, securing these consents of the members and project lenders, satisfactory conclusion on certain ongoing engineering processes and selection of an EPC contractor, negotiation and finalization of definitive offtake agreements and completion of all related financing and permitting activities.

ECA LNG Phase 1 Project. ECA LNG Phase 1 is constructing a one-train natural gas liquefaction facility at the site of SI Partners’ existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa. We do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility.

We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the ECA LNG Phase 1 project. In March 2026, the DOE extended the construction deadline associated with the project to September 2026.

We have an EPC contract with TP Oil & Gas Mexico, S. De R.L. De C.V., an affiliate of Technip Energies N.V., to construct the ECA LNG Phase 1 project. We estimate the total price of the EPC contract to be approximately $1.6 billion, with capital expenditures of approximately $2.5 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. The ECA LNG Phase 1 project achieved mechanical completion in December 2025 and introduced gas into the facility in April 2026. As part of the commissioning process, the project completed loading and exported its first LNG cargo on July 7, 2026. Following the export of its first cargo, the facility was shut down for planned inspections, during which time damage was discovered in the project’s refrigerant compressors. Subject to completion of a root cause investigation and the execution of the remediation workstreams being consistent with management expectations, we expect the project to reach substantial completion in the fourth quarter of 2026, with sales under long-term SPAs commencing shortly thereafter. Prior to substantial completion, net proceeds from LNG sales are recognized as an offset to total project capital expenditures. Reaching substantial completion under the EPC contract is subject to various milestones, including achieving certain performance tests and functionality.

ECA LNG Phase 1’s customers have a termination right under their SPAs if the ECA LNG Phase 1 project does not commence commercial operations under the SPAs by February 24, 2026, subject to certain additional conditions. As of August 3, 2026, no customers have given notice of their intent to terminate the SPAs.

ECA LNG Phase 1 has a loan agreement with a borrowing capacity of $1.5 billion that matures in December 2027. At June 30, 2026 and December 31, 2025, $1.4 billion and $1.3 billion, respectively, of borrowings are outstanding under the loan agreement. IEnova and TotalEnergies SE have provided guarantees for repayment of the loan of up to $1,226 million and $305 million, respectively, plus accrued and unpaid interest. Proceeds from the loan are being used to finance the cost of construction of the ECA LNG Phase 1 project.

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

We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the proposed ECA LNG Phase 2 project. In February 2026, the DOE extended the construction deadline associated with the project to December 2029.

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

PA LNG Phase 1 Project. SI Partners is constructing a natural gas liquefaction project on a greenfield site that it owns in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. The PA LNG Phase 1 project will consist of two liquefaction trains, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services with a nameplate capacity of approximately 13 Mtpa and an initial offtake capacity of approximately 10.5 Mtpa.

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

We have an EPC contract with Bechtel to construct the PA LNG Phase 1 project, which has an estimated price of approximately $10.8 billion, with capital expenditures for the project of approximately $13 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. The first train of the Port Arthur LNG liquefaction project remains on schedule, and we continue to expect the first and second trains to commence commercial operations at or near the end of 2027 and in 2028, respectively.

As we discuss in Note 7 of the Notes to Condensed Consolidated Financial Statements, Port Arthur LNG I has a seven-year term loan facility for an aggregate principal amount of approximately $6.8 billion and an initial working capital facility for up to $200 million, each of which matures in March 2030. At June 30, 2026 and December 31, 2025, $2.4 billion and $3.2 billion, respectively, of borrowings are outstanding, and previous borrowings totaling $3.0 billion have been repaid and cannot be reborrowed under the term loan facility agreement. Proceeds from the loan are being used to finance the cost of construction of the PA LNG Phase 1 project.

SI Partners and ConocoPhillips have provided guarantees relating to their respective affiliate’s commitment to make its pro rata equity share of capital contributions to fund 110% of the development budget of the PA LNG Phase 1 project, in an aggregate amount of up to $9.0 billion. SI Partners’ guarantee covers 70% of this amount plus enforcement costs of its guarantee. As of June 30, 2026, an aggregate amount of $2.7 billion has been paid by SI Partners’ subsidiary in satisfaction of its commitment to fund its portion of the development budget of the PA LNG Phase 1 project.

PA LNG Phase 2 Project. Since reaching a positive FID in September 2025, SI Partners has commenced construction of a second phase of the Port Arthur LNG liquefaction project that we expect will be a similar size to the PA LNG Phase 1 project. The PA LNG Phase 2 project will consist of two liquefaction trains, one LNG storage tank, and associated facilities with a nameplate capacity of approximately 13 Mtpa.

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

We have an EPC contract with Bechtel to construct the PA LNG Phase 2 project, which has an estimated price of approximately $9.2 billion, with capital expenditures of approximately $14 billion, including, among other items, project contingency and a $1.9 billion true-up payment to the PA LNG Phase 1 project to acquire a 50% interest in the shared common facilities. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. We expect the third and fourth trains of the Port Arthur LNG liquefaction project to commence commercial operations in 2030 and 2031, respectively.

As we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements, in September 2025, PA2 JVCo issued 49.9% of its equity interests to Blackstone for $3.4 billion in cash at closing and a commitment to fund an additional $3.6 billion of capital contributions on a pre-determined funding schedule whereby Blackstone’s capital contributions are scheduled prior to SI Partners’ capital contributions. SI Partners holds the remaining 50.1% of equity interests in PA2 JVCo, and has committed to fund up to $7.8 billion to PA2 JVCo to support its share of the budgeted PA LNG Phase 2 project construction costs. SI Partners will continue to consolidate PA2 JVCo and direct the activities related to the construction and future operation and maintenance of the PA LNG Phase 2 project. Blackstone’s equity interest is subject to redemption and exit rights that are outside the control of SI Partners and Blackstone. As a result, we account for Blackstone’s NCI as being contingently redeemable, which is presented as CRNCI on Sempra’s Condensed Consolidated Balance Sheets.

To secure gas supply for the PA LNG Phase 2 project, SI Partners entered into a natural gas transportation agreement with a third-party pipeline developer. The transportation capacity commitment is subject to completion of pipeline construction by a third-party developer that is expected to occur by early 2029. SI Partners holds a contractual option to acquire the third party’s interest in the pipeline if certain construction milestones are not met, which acquisition would release SI Partners from the associated capacity commitment.

Asset and Supply Optimization. As we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in the Annual Report, SI Partners enters into hedging transactions to help mitigate commodity price risk and optimize the value of its LNG, natural gas pipelines and storage, and power-generating assets. Some of these derivatives that we use as economic hedges do not meet the requirements for hedge accounting, or hedge accounting is not elected, and as a result, the changes in fair value of these derivatives are recorded in earnings. Consequently, significant changes in commodity prices have in the past and could in the future result in earnings volatility, which may be material, as the economic offset of these derivatives may not be recorded at fair value.

Off-Balance Sheet Arrangements. Our investment in Cameron LNG JV is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to 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 from the SDSRA. We discuss this guarantee in Note 13 of the Notes to Condensed Consolidated Financial Statements.

In July 2020, Sempra entered into the Support Agreement, which contains a guarantee and represents a variable interest, for the benefit of CFIN with a maximum exposure to loss of $979 million. The guarantee will terminate upon full repayment of the guaranteed debt by 2039, including repayment following an event in which the guaranteed debt is put to Sempra. We discuss this guarantee in Notes 1, 9 and 13 of the Notes to Condensed Consolidated Financial Statements.

Energy Networks

Ecogas. As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements, in December 2025, we entered into an agreement to sell Ecogas for 9.0 billion Mexican pesos (approximately $500 million in U.S. dollar-equivalent at June 30, 2026), subject to adjustments. SI Partners entered into contingent foreign currency hedges, which we discuss in Note 8 of the Notes to Condensed Consolidated Financial Statements, that are designed to fix the exchange rate associated with the anticipated after-tax net proceeds. SI Partners expects to complete the sale in August 2026.

As a result of satisfying all applicable criteria in June 2025, we classified Ecogas’ assets and liabilities as held for sale and ceased recording depreciation and amortization.

Louisiana Storage. SI Partners is constructing Louisiana Storage, a 12.5-billion-cubic-feet salt dome natural gas storage facility to support the PA LNG Phase 1 project. The construction includes an 11-mile pipeline that will connect to the Port Arthur Pipeline Louisiana Connector. We estimate the capital expenditures for the project will be approximately $400 million, including capitalized interest at the project level and project contingency. The actual amount of capital expenditures may differ substantially from our estimates. We expect Louisiana Storage to be ready for service in time to support the needs of the PA LNG Phase 1 project.

Port Arthur Pipeline Louisiana Connector. SI Partners owns and operates the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana, which will be used to supply feed gas to the PA LNG Phase 1 project. The Port Arthur Pipeline Louisiana Connector achieved mechanical completion in January 2026 and was placed into service in June 2026.

Sonora Pipeline. Sempra Infrastructure’s Sonora natural gas pipeline consists of two pipeline segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. Following the start of commercial operations of the Guaymas-El Oro segment, Sempra Infrastructure reported damage to the pipeline in the Yaqui territory that has made that section inoperable since August 2017 because it was not able to be repaired due to legal challenges, which were resolved in March 2023, by some members of the Yaqui tribe.

In September 2019, Sempra Infrastructure and the CFE reached an agreement to modify the tariff structure and extend the term of the contract by 10 years. Under the revised agreement, the CFE will resume making payments only when the damaged section of the Guaymas-El Oro segment of the Sonora pipeline is back in service.

In December 2025, Sempra Infrastructure and the CFE further amended their transportation services agreement to re-route the portion of the pipeline that is in the Yaqui territory, whereby the CFE has agreed to reimburse Sempra Infrastructure for the re-routing costs with a new tariff and requires the pipeline to be back in service no later than July 2029. This amendment will terminate if certain conditions are not met, and Sempra Infrastructure retains the right to terminate the transportation services agreement and seek to recover its reasonable and documented costs and lost profit. Execution of the re-routing project is ongoing. Additionally, in December 2025, Sempra Infrastructure and the CFE entered into an agreement for the CFE’s potential equity participation in the Guaymas-El Oro segment of the Sonora pipeline.

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

The Guaymas-El Oro segment of the Sonora pipeline, including the re-routed portion, currently constitutes a Sole Risk Project under the terms of the SI Partners limited partnership agreement, which means that Sempra Infrastructure holds a 100% interest in this Sole Risk Project. Sole Risk Projects are separated from other SI Partners projects and are conducted at Sempra’s sole cost, expense and liability and Sempra Infrastructure receives, through the acquisition of Sole Risk Interests, any economic and other benefits from such projects. The Guaymas-El Oro segment of the Sonora pipeline will continue to be owned by and a Sole Risk Project of Sempra after closing the planned sale of a portion of our equity interest in SI Partners, which we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements. Any proceeds from a sale of the Guaymas-El Oro segment of the Sonora pipeline would be split between Sempra (90%) and ADIA (10%), subject to adjustments.

Low Carbon Solutions

Cimarrón Wind. SI Partners owns and operates the Cimarrón Wind project, an approximately 320 MW wind generation facility in Baja California, Mexico, that commenced commercial operations in March 2026.

Hackberry Carbon Sequestration Project. SI Partners is developing the potential Hackberry Carbon Sequestration project near Hackberry, Louisiana, together with TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation. This proposed project is designed to permanently sequester carbon dioxide from the Cameron LNG Phase 1 facility, the proposed Cameron LNG Phase 2 project and potentially other sources.

Legal and Regulatory Matters

With respect to the ECA Regas Facility, ECA LNG Phase 1 project and ECA LNG Phase 2 project that we discuss above, an unfavorable resolution of a land dispute could have a material adverse effect on the natural gas regasification operations at the ECA Regas Facility and the development and construction of the ECA LNG projects. With respect to the PA LNG Phase 1 project that we discuss above, lawsuits are pending related to the deaths of three Bechtel employees and injuries to two others, for which Bechtel is providing indemnity under Port Arthur LNG I’s EPC contract. We discuss these legal matters in “Legal Proceedings – Other Sempra” in Note 13 of the Notes to Condensed Consolidated Financial Statements.

We discuss regulatory matters affecting our operations in Mexico and risks associated with Mexican laws, policies and government influence in “Part I – Item 1A. Risk Factors – Risks Related to Sempra Infrastructure – Legal and Regulatory Risks” in the Annual Report. Regulatory and other actions by the Mexican government could 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 the Registrants.

Capital Expenditures for PP&E and Investments

(1)Includes capital expenditures for PP&E of $934 and $1,270 at SDG&E and $967 and $1,045 at SoCalGas for 2026 and 2025, respectively.

We expect capital expenditures for PP&E and investments in 2026 to total approximately $11.3 billion, an increase from the $8.6 billion estimate included in “Item 7. MD&A – Capital Resources and Liquidity” in the Annual Report. The increase is primarily due to a $2.4 billion increase at Sempra Infrastructure, driven by the later expected closing of the sale of a 45% equity interest in SI Partners. Upon closing, the sale would reduce Sempra’s ownership interest in SI Partners from 70% to 25%. We now expect the sale to close near the end of the third quarter of 2026, compared to our previous assumption that it would close as early as the beginning of the second quarter of 2026, resulting in Sempra retaining a greater share of SI Partners’ capital expenditures for PP&E and investments for a longer portion of 2026.

Our level of capital expenditures for PP&E and investments will depend on, among other things, the cost and availability of financing, regulatory approvals, changes in tax law and business opportunities providing desirable rates of return, among various other factors described in this MD&A and in “Part I – Item 1A. Risk Factors” in the Annual Report. We aim to finance our capital expenditures for PP&E and investments in a manner that will maintain our investment-grade credit ratings and capital structure, but we may not be able to do so.