Exhibit

Edison International delivered excellent fourth quarter and full-year results, but faced significant challenges in December and into January of this year due to wildfires and the related legal and regulatory framework in California. Governor Brown recently referred to a “new normal” with respect to wildfires, and the fundamental risks this poses to our utility are top of mind at all levels of our company. I will discuss our strategy to address wildfire risk, but first, let me make a brief comment on our full-year results.

2017 core earnings were $4.50 per share, which were $0.18 above the mid-point of our earnings guidance range and also well above consensus EPS. These results were driven by SCE’s strong operating performance and additional tax benefits during the year. The EIX holding company also had better-than-expected cost performance in the fourth quarter and this contributed to our positive overall results. These results exclude the non-core impact of tax reform and the revised SONGS settlement. Today, the Board of Directors of Edison International declared its first quarter common stock dividend of $0.605 per share. Prior to declaring the dividend, the Board evaluated the information available, including information pertaining to the wildfires in December 2017 and mudslides in Montecito in January 2018, and determined that the California law requirements for the declaration were met.

Wildfires pose a risk statewide, impacting the entire economy. Communities across California have been tragically affected as climate change has increased the severity and frequency of wildfires in recent years. Long-term drought in California and forest management policies have resulted in the build-up of unmanaged vegetation. The state has nearly 130 million dead trees on approximately 9 million acres due to prolonged drought conditions and bark beetle infestation. The combination of these conditions, along with decades of more buildings being permitted and constructed in higher fire risk areas, have contributed to catastrophic wildfires, with eight of the state’s 20 most destructive wildfires having occurred in the last three years.

This is a statewide crisis that needs a statewide solution. We are engaged with state leaders including the Governor’s office, legislative leaders and stakeholders across the economy on the solutions we believe are needed. First and foremost is the prevention and mitigation of catastrophic wildfires with sufficient fire suppression resources, and effective policies around vegetation management, hazardous fuels reduction, and zoning regulations for residential and commercial development in high fire risk areas. Second, our state’s infrastructure must be hardened, with stronger building codes in high fire risk areas. Utilities and other operators of critical infrastructure must also partner with state agencies on improved standards for climate resilient infrastructure. As we think about how we design and operate the system, we should consider that roughly a quarter of our service territory is in designated high-fire risk areas. We should evaluate the safety impacts, along with the reliability and cost tradeoffs, of steps like undergrounding more of the distribution network in selected areas, installing steel or composite poles instead of wood ones in specific locations, and using further preventive public safety shutoffs of power under high-risk conditions such as red flag warnings, which we have done selectively in the past. Third, when a catastrophic event occurs in spite of all these efforts, we need thoughtful policies around how financial risks are allocated, including fire suppression costs and damages.

As a reminder, California’s courts have held investor-owned utilities strictly liable -regardless of fault - for property damages and attorney’s fees if utility equipment is found to be a substantial cause of a wildfire. This means that the utility can do everything right in the operation and maintenance of its equipment, but still be on the hook for these costs. The California courts have held utilities liable regardless of fault by applying the principle of inverse condemnation, a principle typically applicable to government, not private entities. The assumption is that like a government entity that can pass along to its taxpayers costs and risks incurred for the public good, IOUs can socialize wildfire costs among their customers in rates. However, as many of you know, the CPUC recently denied San Diego Gas & Electric’s application for cost recovery of about $380 million of costs above their insurance coverage.

We see legal, regulatory and legislative policy pathways to resolve these issues. We recently filed a motion in our Round Fire case - a 2015 fire near Bishop, California - challenging the application of inverse condemnation. Yesterday, we filed a motion for leave to file an amicus in the PG&E Butte fire case also challenging the application of inverse. In the regulatory arena, we filed a joint application with PG&E for rehearing of the CPUC's decision in SDG&E’s

On legislative policy changes, in addition to the priorities I mentioned on fire prevention and suppression and improved standards for climate resiliency, we believe that the allocation of costs and financial risk must be addressed. That starts with exploring ways to reform the application of inverse condemnation with strict liability to utilities. It also includes addressing the high cost of fire suppression, which typically exceeds state budget levels each year. In addition, increasingly high premiums for wildfire insurance coverage should be a part of the discussion, as they affect parties far beyond the utility sector.

I would like to note that, despite our best efforts and sense of urgency, all of this will take time and creates uncertainty. However, we also believe that the state will ultimately address the risks and issues surrounding wildfires and other climate change impacts because California’s ambitious environmental policies require strong, healthy utilities. On that note, I would like to touch on a few key trends that continue to provide a strong growth engine at the utility for the foreseeable future.

Last October, SCE released a white paper that outlines our blueprint for California to reduce greenhouse gas emissions and air pollution by its ambitious 2030 goal. The clean power and electrification pathway has received a great response and support from community organizations, customers, environmentalists and labor unions. As you have seen in the white paper, we estimate that, to meet the 2030 goals, California must have a robust, modern electric grid supplied by 80 percent carbon-free energy. We believe California will need more than 7 million electric vehicles, and the electrification of one-third of space and water heaters in increasingly energy-efficient buildings. We continue to engage in significant outreach to key stakeholders and pursue initiatives to help the state meet California’s 2030 goals.

A related initiative is the transportation electrification application that was filed in January 2017 that included $574 million of potential capital spending in two groupings - fast track projects and larger, longer-term projects which will require more detailed consideration. Last month, the Commission approved five of the six fast track priority projects we proposed totaling $10 million in capital spend. The Commission process continues with respect to the longer term review projects, and we are still expecting a proposed decision in the second quarter.

Energy storage is a big component of the electric grid in our analysis. Legislation is beginning to reflect this as well, and Assembly Bill 2868, signed in 2016, added opportunities for programs and investments of an additional 500 MW of distribution-level energy storage systems, distributed equally among the IOUs. SCE’s share is 166 MW. On March 1^st, we will file our Energy Storage Procurement and Investment Plan application, which will include AB 2868 proposals for Energy Storage Programs and Investments, in addition to the usual procurement of energy storage through other RFOs.

With respect to the 2018 general rate case, we filed updated testimony on February 16^th to reflect the impacts of tax reform. We have a hearing date set for March 19^th to discuss this updated testimony and any comments provided by intervenors. Once that hearing is completed, we will see if the Administrative Law Judges require any other briefings before issuing a proposed decision. We cannot speculate on the timing for a proposed decision and subsequent Commission decision, but given where we are today, we would expect a final decision before year-end.

Turning to SONGS, we announced a revised settlement that was the result of multiple mediation sessions in 2017 and January 2018 with a diverse set of parties. We weighed the reasonable range of potential outcomes and determined that this outcome is in the best interest of our customers and our shareholders. If approved by the CPUC, this settlement will eliminate further uncertainty and bring closure to what otherwise could have turned into very lengthy litigation after factoring in likely appeals in the absence of settlement. The revised settlement will resolve all issues under consideration in the OII and will also result in the dismissal of a federal lawsuit currently pending in the 9th Circuit Court of Appeals challenging the CPUC’s authority to permit rate recovery of San Onofre costs. Maria will provide additional information in her remarks, but in summary, our 2017 financial statements reflect the impacts of the revised settlement on our company. We will work with the other parties to complete the steps in this proceeding and are hoping for a swift Commission decision given that all the parties involved in the mediation joined the settlement.

Operational and service excellence starts with safety for our workers and our public. This has been a major priority across our company and is at the top of our core values. Our 2017 performance did not meet our expectations; for example, our rate of injuries leading to days away, on restricted duty, or transferred - known as the “DART” rate - remains worse than industry norms. We have dedicated additional senior leadership in this area, and are focused not just on tools and processes, but more importantly on growing the safety focus of our organization’s culture.

We continued to improve in our customer service goals with residential customers, with SCE ranking in the upper second quartile among peer utilities in the most recent J.D. Power survey. We have narrowed the gap with our top quartile peers, and first quartile appears achievable for SCE. On the business customer side, our peers continued to raise their performance, and we have dipped into the upper third quartile. Kevin, his leadership team and our employees will continue to target top-quartile satisfaction for both our residential and business customers.

While SCE did not meet its 2017 reliability goals, SCE began implementing a three-year improvement roadmap in 2017, and the benefits realized in the second half of 2017 exceeded our expectations. We expect reliability to continue to improve in 2018, with a goal of achieving top-quartile performance over the next few years.

SCE achieved improved cost performance in 2017. One way we measure SCE cost efficiency is controllable O&M per customer. We also track system average rates. SCE continues to reduce O&M costs and maintain the lowest system average rate among California IOUs, and is on track to achieve top quartile performance. We have plans that should help us achieve this objective over the next couple of years.

As we continue to pursue top-quartile performance, we know that the bar will continue to be raised as we and our peer utilities take advantage of technological and analytical advances to improve outcomes. So while we have plans to achieve top-quartile performance based on current benchmarks, we know that we will need to work to push past those levels in order to keep pace.

As I look ahead to the changes that will take place in California, our utility’s investment will be needed to operate a safe, reliable grid, achieve environmental policy outcomes, and mitigate climate change impacts. Our customers, regulators, legislators, and shareholders can rely on our employees to deliver solutions to the many challenges facing our community, and to do that from a strong foundation of operational and service excellence.

My comments today will cover fourth quarter and full-year results for 2017 compared to the same period a year ago, our updated capital expenditure and rate base forecasts, updates on SCE’s FERC Formula Rate filing, and other financial updates for SCE and EIX. Our fourth quarter and full-year 2017 results include certain non-core charges related to the recent tax reform legislation as well as the revised SONGS settlement. I will walk through both of these in a minute but let’s begin with a look at our core earnings drivers.

For the fourth quarter 2017, Edison International reported core earnings of $1.10 per share, an increase of 13 cents from the same period last year. On the right side of slide 2, you will see that SCE had a positive 14 cent core variance for the quarter versus the prior year. This was mainly attributable to 11 cents per share of increased revenue related to the attrition mechanism in SCE’s 2015 general rate case.

There were a number of changes on the expense-side as well, although these were largely offsetting. SCE’s operations and maintenance costs were slightly higher due to the timing of maintenance activities. Net financing costs increased a penny per share over last year and was mainly due to 4 cents of higher interest expense, partially offset by increased AFUDC earnings. Income tax benefits were 5 cents per share higher than last year and related to increased cost of removal benefits. Finally, other costs related to property taxes and corporate expenses were 3 cents higher.

EIX Parent and Other had $1.29 per share of non-core charges in the fourth quarter largely related to tax reform. Specifically, the re-measurement of deferred taxes resulted in a $433 million expense, or $1.33 per share. We will continue to utilize our net operating losses and credits and, based on our current analysis, EIX expects to become a cash taxpayer in 2025.

Overall, for the full year, Edison International core earnings increased 53 cents per share over prior year. This includes 44 cents per share of increased revenue related to the attrition mechanism in SCE’s 2015 general rate case. Many of the earnings drivers for full-year 2017 are similar to the fourth quarter, so I will only highlight two items. At SCE, lower operation and maintenance costs contributed 7 cents per share to overall performance over prior year. Also, as we have communicated in previous quarters, EIX Parent and Other realized significant tax benefits in 2017 and the 17 cents per share increase in core earnings over the prior year is largely a result of these.

For the year ended 2017, we have not recorded a liability associated with the December wildfires. Given the preliminary stages of the investigations and the uncertainty as to the causes and potential damages associated with the fires, we cannot determine that a liability is probable or a reasonable range of possible losses that could be incurred. We will continue to update you as we have more information.

Overall, core earnings of $4.50 per share are 18 cents per share higher than the mid-point of guidance. SCE earnings are 15 cents per share higher due primarily to increased O&M savings and financing benefits and higher income tax benefits. Edison International Parent and Other losses of 8 cents per share are 3 cents per share better than guidance, largely from better operating cost performance at the holding company and our competitive businesses.

up its capital spending program over the three-year GRC period, that is 2018 through 2020, to meet what is ultimately authorized in the decision while minimizing the associated risk of unauthorized spending. As part of this, we will focus initial grid mod spending on capital that provides safety and reliability benefits while deferring most spending that is primarily focused on integration of distributed energy resources. While we continue to present our 2019 and 2020 capital forecast at our current GRC request level, we adjusted CPUC capital expenditures in 2018 to $3.6 billion to reflect our latest planning for the year. Additionally, we made updates throughout the forecast period for changes in FERC projects. Our total 2018 CPUC and FERC capital expenditure plan is $4.2 billion.

While we wait for the outcome related to the 2018 GRC, over the long-term, we continue to see SCE investing at least $4 billion per year and adding at least $2 billion per year of rate base for the foreseeable future as SCE focuses on investments in the grid and continues to be a key enabler of California’s ambitious climate change policies.

Page 5 of the deck provides our rate base forecast. The CPUC rate base forecast is based on the weighted average rate base that we requested in the GRC for the forward-looking three year period, that is, it reflects our 2018 - 2020 request level capital expenditures. Once SCE receives a final decision in the 2018 GRC, our rate base forecast will be updated to reflect the authorized levels. At that time, we will also update our capital expenditures for 2019 and 2020. We have, however, updated our rate base forecast to reflect the impact of tax reform, changes in the latest FERC capital forecast and additional incentive CWIP treatment for certain FERC projects.

Please turn to slide 6 where we provide our current rate base forecast along with the impact of changes since our November update. As you can see, tax reform has little impact on our 2018 rate base, but by 2020, it increases our rate base by $400 million. This increase is mainly related to the elimination of bonus depreciation.

During the fourth quarter of 2017, FERC approved incentive CWIP treatment for three additional transmission projects - Alberhill, Mesa, and Eldorado-Lugo-Mohave. This incentive treatment means that we can add capital expenditures related to those projects to rate base in the year they are spent rather than waiting for the project to be placed into service. As a result, rate base is approximately $500 million higher by 2020. However, this increase is offset by reduced

capital spending as a result of improved cost efficiency and revisions of project scope and schedule related to our FERC capital projects and programs. Cost efficiencies and reduced scope account for approximately one-third of the change in capital spending. The remaining two-thirds represents a timing shift that will be added to rate base outside the forecast window. The majority of these changes are captured in the major transmission project update on slide 7.

On the subject of FERC, I would also like to provide a brief update on our current FERC Formula Rate proceeding. A key matter in that proceeding is the determination of our authorized ROE. In December 2017, the FERC ruled that the requested Formula Rate would go into effect January 1, 2018, subject to refund. This means that while we are collecting our requested ROE for FERC-related revenues during 2018, these dollars will be adjusted and refunded depending upon the final decision in our proceeding. Our ROE request is comprised of a base return on equity of 10.3 percent plus the 50 basis point CAISO participation adder for a total ROE of 10.8 percent, before individual project incentives. The weighted average of individual project incentives increases the requested ROE to the equivalent of about 11.5 percent based on our current capital expenditure plan. In the December ruling, FERC also approved the 50 basis point CAISO participation adder although I should note that the CPUC has intervened in our FERC Rate proceeding and has requested an application for rehearing on the approval of this adder. The FERC also directed the parties to commence settlement discussions and the parties are scheduled to reconvene at FERC on May 15^th. Hearings will be held if the parties do not ultimately settle. We cannot speculate on the outcome of this proceeding or the timeline and will keep you updated as new information is presented.

As I noted on our third quarter earnings call, we will not be providing 2018 earnings guidance until we receive a final decision on the general rate case. However, we have laid out a few key items on this page that you should consider as you model 2018 and beyond. I have already discussed the majority of information on this page. However, please note under “Other Items,” we list some key considerations outside of the simplified rate base model. First, as Pedro touched on briefly in his comments, the market for wildfire insurance for California IOUs is becoming more strained. Availability is declining while simultaneously premiums are going up. In late December, we notified the Commission that SCE secured $300 million of wildfire insurance for the 2018 calendar year and requested the Commission approve recovery of the

associated premium of approximately $121 million. Although we believe we have a strong case for recovery, until the CPUC addresses our request, you should assume an additional 29 cent per share drag on earnings in 2018. There may also be additional insurance costs that are in excess of what we have requested in our GRC. We do not yet have information regarding the overall cost however. Second, while we are not providing guidance for SCE, we do expect EIX Parent and Other to be an earnings drag of $0.25 to $0.30 per share for 2018. The increase in EIX Parent and Other is related to a lower tax shield as a result of the lower corporate tax rate and higher interest expense. Also included is the EPS of Edison Energy which is expected to improve in 2018 over prior year results as we continue to work towards our goal of a run-rate breakeven level of earnings by year-end 2019. Finally, we have not included any tax benefits related to share based compensation which was a significant factor in 2017 performance.

On February 16^th, we filed updated testimony in our GRC proceeding to include the impacts of tax reform legislation on our CPUC-jurisdictional revenue requirement. We are now requesting a 2018 revenue requirement of $5.534 billion, a $106 million decrease from the 2017 revenue requirement. Post-test year revenue requirements have also decreased from our prior request. Overall, we estimate this latest update will result in an approximately 3 percent CAGR in total rates between 2017 and 2020. We will remain focused on ways to mitigate customer rate impacts while continuing to invest in our electric grid infrastructure.

EIX and SCE continue to maintain a strong balance sheet and significant financial flexibility. At EIX, we issued a $500 million, one-year term loan in January to partially pay down our commercial paper program. At SCE, our average common equity component of total capitalization was 50 percent as of December 31^st, including the charge from the revised SONGS settlement. If approved by the CPUC, the revised settlement allows SCE to exclude the $448 million after-tax charge from its equity capitalization ratio. As we have already discussed, tax reform results in a lower revenue requirement and lower customer rates although rate base will increase as a result of the elimination of bonus depreciation. Considering these items and given the potential for a large capital program based on our GRC request as well as other potential investments in support of the state’s clean energy objectives, we will likely see increased financing needs in the future as higher capital spending is followed by related growth in authorized rate base and earnings. We will continually assess the most cost-effective approach to