愛迪生國際 (EIX) 2013 Q4 法說會逐字稿

Good afternoon. My name is Troy Lee, and I will be your conference operator today. At this time I would like to welcome everyone to the Edison International fourth-quarter 2013 financial teleconference. All lines have been placed on mute to prevent background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions)

This call is being recorded, and I would now like to turn the call over to Mr. Scott Cunningham, Vice President of Investor Relations. Thank you, Mr. Cunningham. You may begin.

Thanks, Troy, and good afternoon, everyone. We apologize for the short delay in the start of the call.

Our principal speakers today will be Chairman and Chief Executive Officer Ted Craver; Executive Vice President and Chief Financial Officer Jim Scilacci. Also with us are other members of the management team.

The presentation that accompanies Jim's comments, the earnings press release and our Form 10-K are available on our website at www.edisoninvestor.com.

During this call, we will make forward-looking statements about the financial outlook for Edison International and its subsidiaries and about other future events. Actual results could differ materially from current expectations. Important factors that could cause different results are set forth in our SEC filings. We encourage you to read these carefully.

The presentation includes certain outlook assumptions, as well as reconciliations of non-GAAP measures to the nearest GAAP measure. When we get to Q&A, please limit yourself to one question and one follow-up. If you have further questions, please return to the queue.

With that, I'll now turn the call over to Ted Craver.

Thank you, Scott, and good afternoon, everyone.

Today Edison International reported full year core earnings of $3.80 per share, $0.10 above the high-end of our earnings guidance range. Core earnings for 2013 were down slightly from last year's $3.92 per share, reflecting in part the impact of closing the San Onofre nuclear plant.

We also introduced 2014 earnings guidance, core earnings guidance of $3.60 to $3.80 per share. Jim will provide additional information on all of this shortly.

In the last several investor calls, my remarks have centered on our three key strategic priorities: delivering long-term growth in earnings and dividends, resolving the uncertainties of EME and SONGS, and positioning our Company to capitalize on transformative change in our industry.

Today I will mostly touch on the subjects of our growth prospects and resolving uncertainties where there have been several developments.

For the last several years at Southern California Edison, we've had the twin objectives of stepping up our infrastructure investments to maintain reliability and modernize the grid and providing cost benefits to ratepayers through operational efficiencies. This continued focus on keeping rates affordable and fair for all of our customers while investing in the grid has also provided strong earnings power for our investors.

This is demonstrated by our stronger than forecast core earnings in 2013 and by our decision last December to increase the common stock dividend for the 10th year in a row to an annual rate of $1.42 per share.

SCE continues to target high levels of infrastructure replacement and reliability investments while meeting public policy requirements. In our 2015 general rate case application pending before the CPUC, our testimony reflects a significant increase in infrastructure replacement activity for the 2015 to 2017 rate cycle. This investment is primarily aimed at our distribution system.

The rate case application also forecasts a need for sustained investment at these levels out through 2020 and beyond. Therefore, we continue to anticipate significant rate case growth for the foreseeable future.

Our updated forecasts have not changed materially, and SCE continues to forecast a rate base of between $27 billion and $29 billion by 2017 and a growth rate of 7% to 9% annually through this period. Not yet knowing the outcome of the CPUC proceeding on SONGS, this forecast continues to exclude any rate base contribution from our investment in SONGS.

As for the GRC proceeding itself, the CPUC is in the early procedural stages, and we continue to respond to information requests from interveners. We expect evidentiary hearings to be scheduled for the summer, but the CPUC has yet to set the exact schedule.

A key initiative in 2013 involved the need for reform in customer rate design which was meaningfully advanced with the passage of California's Assembly Bill 327. This law returned authority to the CPUC to adjust rate design, including a fixed charge and simplifying the tiered residential rate structure.

We are in the early stages, but this law provides an opportunity to reduce subsidies and costs shifting amongst residential ratepayers, along with simplifying the rate structure.

All of these actions help provide the regulatory underpinnings to support long-term earnings growth while maintaining the impact of higher rates -- while managing the impact of higher rates on our customers. And in turn, they help support our dividend policy, which is a targeted payout ratio of 45% to 55% of SCE earnings.

We continue to see the opportunity and steps over time to return the dividend payout back to this target ratio. While we are mindful of pending regulatory uncertainties, we believe the opportunity for meaningful dividend growth remains an important element of the Edison International investment thesis.

Let me now turn to our efforts to resolve uncertainties. Last week, of course, we announced a settlement agreement, which we believe will provide the resolution to a key uncertainty for investors, the EME bankruptcy. As you heard during last week's call, the agreement will settle all outstanding matters with EME and its creditors. The agreement provides the opportunity for a cash flow positive outcome and honors our commitment to not put new capital into EME.

On February 19, EME sought approval of the bankruptcy court to amend its plan of reorganization to include the settlement and to give notice to the creditors regarding the planned change. The court approved giving notice to the creditors and rescheduled its confirmation hearing on the plan to March 11. Subject to approval of the bankruptcy court, implementation of the plan of reorganization will allow EME to proceed with the sale of substantially all of its assets to NRG and close on our settlement agreement.

This leaves one major uncertainty to resolve, the recovery of our costs related to SONGS. We continue to express to the CPUC our strong interest in having it complete its four phase regulatory review this year. We are hopeful that our concerns with the Phase I proposed decision will be addressed such that the commission can complete action on this phase and move on to the remaining phases in the not-too-distant future. We anticipate in the first quarter a proposed decision on the second phase, which addresses recovery of investment in SONGS.

We also anticipate a proposed schedule for the third phase, which will cover the broad questions of reasonableness and prudency around our actions and those of the supplier of the faulty steam generators, Mitsubishi Heavy Industries.

We continue to assert that the steam generator tubule that occurred after only 11 months of operating time and the resulting damages represent a total and fundamental failure of performance by Mitsubishi Heavy Industries. We must insist that MHI be held accountable for its failure to provide properly functioning steam generators and for the damage it has inflicted on our customers and our Company. Simply put, they should stand behind their product.

Southern California Edison has filed for significant claims against MHI for damages in the International Chamber of Commerce arbitration process. We will also continue to push aggressively to seek a favorable determination from NEIL, the nuclear industry insurer, for our outage-related power purchase claims. Recent conversations with NEIL lead us to expect their initial determination after their board meets in mid-June.

Along with the resolution of the SONGS OII, we are planning for the replacement resources required to ensure grids reliability without SONGS and for the safe and efficient decommissioning of SONGS. With the assistance of third-party experts, we are developing an updated site-specific decommissioning plan. This plan is expected to be completed by midyear.

Also, we are creating appropriate channels for public participation to ensure an open and transparent decommissioning planning process.

Although it wasn't one of our two critical uncertainties, we are pleased SCE was able to complete the sale of its interest in the Four Corners coal-fired generation facility in late December to Arizona Public Service for $181 million. The transaction benefits our customers and meets an important California requirement to discontinue investments in generation not meeting stringent greenhouse gas emission performance standards. It has no earnings impact on Southern California Edison.

So with that, let me now turn the call over to Jim Scilacci.

Thanks, Ted, and good afternoon, everyone. My comments focus on the following topics: financial results, updates on capital spending, rate base and fuel and purchase power, and 2014 earnings guidance.

Please turn to page 2. For the fourth quarter of 2013, core earnings are $0.81 per share. The comparison to the fourth quarter last year is not particularly helpful because SCE's 2012 CPUC general rate case decision was recorded in the fourth quarter of last year. The quarter over quarter comparison is summarized at the right of the slide. The earnings drivers are the same things we've been discussing all year. For SCE, the year-over-year comparison is more informative.

Before I go there, I want to comment on fourth-quarter results at the holding company. EIX recorded $0.02 per share of earnings, $0.08 better than last year, largely due to $0.06 per share of higher earnings from Edison Capital. As we have previously mentioned, Edison Capital has a small investment portfolio, including affordable housing investments. This portfolio continues to wind down, and periodically we will record income from sales or distributions.

It is difficult to predict the timing and amount of income from the remaining portfolio, and we have not and will not include any income in our guidance numbers. As a reminder, holding company costs generally run a bit more than $0.01 per month.

In addition to the Edison Capital income, the holding company also had $0.02 per share of lower costs in taxes. The non-core item of $0.11 per share in discontinued operations is from Edison Mission Energy for ongoing adjustments to income taxes. As a result, we move the accounting for EME to discontinued operations following its bankruptcy filing in the fourth quarter of 2012. Through the end of 2013, we now have recorded $70 million from adjustments related to the outcome of the EME bankruptcy, including estimated retained tax benefits from a deconsolidation of EME for tax purposes.

As we had reported last week, in our EME settlement conference call, we expect to report an additional $130 million during the first quarter of 2014, assuming the bankruptcy court approves EME's amended plan of reorganization.

Together this adds up to the estimated $200 million of income EME settlement is expected to produce.

I'd also like to note that based on our updated disclosures, we have recorded $290 million of joint tax and $35 million of joint pension liabilities for a total of $325 million as of December 31, 2013. Under the settlement agreement, we would also assume certain executive retirement obligations. In total, we have estimated these liabilities would be approximately $350 million as of the closing.

Please turn to page 3. As Ted has already mentioned, EIX' 2013 core earnings are $3.80 per share. On a year-over-year basis, this is slightly behind last year. SONGS accounts for most of the difference because we stopped recording a full return on investment and related AFUDC earnings since the shutdown decision was made. The other major reason for the decline is a reduction in income tax benefits in 2013 compared to 2012. The increased earnings from rate base growth in 2013 were offset by the lower CPUC authorized return on common equity.

To make it helpful in comparing full-year results, with our updated guidance from the third-quarter call, we've added a slide on page 4 to highlight the changes.

On full-year core results came in -- excuse me, our full-year core results came in $0.15 per share above the midpoint of the guidance that we last updated on October 29. $0.08 per share of the improvement is largely cost savings at SCE.

Holding company results are better by $0.07 per share, largely from Edison Capital earnings that were not included in our guidance and were booked in the fourth quarter.

One last point I'd like to emphasize is the track record of rate base and earnings growth at SCE has achieved over the last several years.

Please turn to page 5 of the deck. Since 2008, the compound annual growth rates of rate base and core earnings are 10% and 12%, respectively. This is a rather remarkable achievement for our industry.

Looking forward, next I will provide updates on capital spending and rate base. Please turn to page 6.

From our prior forecast, the 2014 through 2017 capital forecasts increased $400 million. The increase reflects the catchup of 2013 GRC capital expenditures into 2014, together with updated transmission cost estimates, including FAA requirements for the Tehachapi project.

During 2014, a major focus for us is to ensure that we invest the capital dollars authorized by the CPUC for infrastructure replacement and reliability-related projects. For 2013 SCE's actual capital spending was $3.5 billion or $300 million below our forecast. This was largely due to transmission delays and lower costs on two completed renewable transmission projects in 2013, as well as a slower than planned ramp-up of infrastructure replacement spending, even though we were able to increase reliability infrastructure investments $300 million over 2012. Historical capital expenditures are shown in the appendix to this deck.

Please note that our current capital forecast does not include spending for storage projects, preferred resources to replace San Onofre or transmission projects that are currently included in the Cal-ISO's resource plan. Potential expenditures for projects like these are currently under consideration.

Please turn to page 7. As Ted mentioned, our rate-base forecast reflects only minor changes with a net $100 million decrease by 2017. The growth rate remains at 7% to 9% per year through 2017. Once we get a Phase II decision and a SONGS OII, which is considering if some portion of SONGS is still used and useful, we will then update our forecast accordingly.

On page 8, we've updated the status of our fuel and purchase power or what we refer to as ERRA. We look to get a CPUC approval this spring of our 2014 forecast proceeding. You may recall from last year that CPUC had deferred consideration of a portion of the ERRA costs that relate to SONGS shutdown decision until the overall SONGS regulatory review is completed. We have provided an updated estimate of the 2013 net SONGS cost of $467 million and have agreed to defer collection until consideration of the OII if we receive a timely decision of our 2014 forecast proceeding.

Overall, SCE has under collected by just -- was under collected by just over $1 billion in this account by year-end 2013. While the ERRA situation is important from a near-term liquidity perspective, we believe the SONGS OII will be the key driver for recovering SONGS replacement power costs.

I should also mention that while we focused investor attention on ERRA under collection, we've added to our disclosures and noted at the bottom of the slide that for all regulatory balancing accounts, SCE had a net over-collection of $554 million at year-end 2013.

At the same time, SCE had availability of $2.46 billion under its $2.75 billion credit facility.

On page 9, I've noted a couple of procedural updates on our 2015 general rate case. First, the two assigned ALJs hosted a prehearing conference on February 11 where the schedule for public participation meetings and details on the timeline for hearings and motions were discussed. We anticipate the ALJs will publish a schedule shortly. We continue to press for a timely decision by the end of 2014. However, over the last few years, the investor-owned utilities in California have experienced delays in receiving their final GRC decisions.

Also, with the sale of the Four Corners, we are updating our GRC requests to remove SCE's share of cost related this coal-fired plan. This will lower the requested revenue requirement modestly in each year. The revenue requirement numbers on page 9 incorporate the sale of Four Corners.

Next, I'd like to provide some perspective on key assumptions behind our 2014 earnings guidance. Please turn to page 10. You will recall that when we first gave 2013 earnings guidance, I indicated that we would expect in both 2013 and 2014 earnings would exceed the simplified rate-based earnings model that we've discussed for some time. This was because cost savings and income tax benefits were expected to be realized.

We also indicated that these benefits would be trued up in the 2015 general rate case and would not apply to earnings in 2015 and beyond. We still believe this to be the case.

For 2014, the simplified rate base model would yield earnings per share of $3.40 for SCE. To be clear, we are using a 2014 rate-based forecast of $22.1 billion from page 6. This rate-based number is the midpoint between the request and range cases. We have excluded SONGS rate base pending a decision in Phase II of the SONGS OII proceeding.

The authorized return of common equity for both CPUC and FERC is 10.45%. Our assumptions also include a 48% common equity ratio and a flat share count. We then see a net upside of $0.45 per share at SCE. We deduct $0.07 per share to account for the remaining 52% of the capital structure related to SONGS, cost of debt and preferred stock. There are $0.52 of positive items related to -- primarily related to O&M, additional income tax benefits and energy efficiency.

The 2014 guidance also assumes $0.15 per share in holding company costs. We've assumed no non-core impacts in our guidance. We plan to update our non-core guidance based on the outcome of the EME bankruptcy. The bankruptcy court, as Ted said, is scheduled to consider the EME amended plan of reorganization on March 11.

This gets us to a midpoint of $3.70 per share for both core and basic EPS with a range of $3.60 to $3.80 per share. We've noted the major assumptions on the right side of this slide.

In concluding my remarks, I will make a few additional points. Please turn to page 11.

As Ted said, our main goal is about creating shareholder value. From a financial perspective, that means delivering on rate base and earnings growth objectives while generating sufficient cash flow to support both our capital plans and common dividend growth objectives without the need for additional common equity.

That concludes my comments, and I'd like to turn the call over to the operator for Q&A now.

(Operator Instructions). Dan Eggers.

Just on question number one, just as it relates to the GRC with all of the error balance accounts and then the requested revenues you guys put out there and projections for higher gas prices and renewables, what sort of bill inflation are you guys projecting for kind of 2014, 2015, 2016 for customers based on plan?

Good question. Generally when we talk with investors, it's our goal to target somewhere between 3% and 5% annual increases in the total bill. So you have to take -- you have got different pieces. You've got fuel and purchase power, base rates, transmission and the like, but 3% to 5% is the internal objective that we try to target.

Now for 2014, I'm not sure exactly where that comes in. It may be slightly higher, but we will be working on that as we go through the regulatory process.

Got it. And then I guess just on the OII process, with OII 3 kind of each 1 and 2 seeming to kind of trudge along, are there still expectations that 3 can have some visibility in the second quarter, or does it look like it's going to drift later into summer before there's kind of visibilities to where the commission is headed?

I think the key thing, Dan, is waiting for the scoping memo to come out. And based on Ted's comments, we anticipate that somewhere before the end of the first quarter -- maybe it's slightly later -- we should see something from the commission. And that will be really a good indicator of what the timeframe for all this to be.

Okay. Thank you, guys.

Julien Smith.

Could you follow-up on the last question just given balancing accounts and all that from a cash flow perspective how you think about this year and the use of short-term debt just given prior comments on prior calls?

It's a good question. Right now we have very limited amount that's been used on our lines that was in my script. There is about $175 million of commercial paper that was outstanding at the end of the year, and that will ebb and flow as we go through the course of the year. And it really is going to dictate -- that is dictated by our capital expenditures and the timeliness of decision-making around the ERRA decision and just normal fuel and purchase power fluctuations that occur in any important time.

So it is really hard to predict at the end of the year where we will be because you have so many unknowns that have to be decided here. So I'll pause here and look to Linda or Ron to see if you want to add anything else to the answer?

You captured it.

Okay. Well, as we go through the course of the year, we'll watch that and flag it. The key things are the decisions that need to come from the commission, which will affect on our liquidity.

Got you. Are there any chunky items outside of that that affect cash flow that might not be otherwise intuitive?

The only other thing I didn't mention, it could be one out at the holding company. If you see the approval of the settlement, we could use commercial paper borrowings or drawings on our bank lines at the holding company to make the initial payment to the creditors. That's $225 million at the close. And then we have then long-time tax benefits through the course of the year. September is when we typically file our tax return. So you'll just have to look to see what happens in terms of what we actually receive and we are able to monetize based on the tax positions of the utility and the consolidated entity. And then at the utility, I think I covered it. There's nothing really that jumps out.

We'll do financings once in a while. That's the only bulky thing that occurs at the utility. We typically build up some short-term borrowings and then go out and issue $300 million, $400 million, $500 million of long-term debt, and then that will be used to repay commercial paper borrowings. So that's the normal trend. Ron?

Yes, the greenhouse gas revenues and costs, those can be chunky as well.

Got you. Just a quick clarification from the slides. On the transmission spending, I know you guys revised that upwards. Anything pending there again just left over? Is that all taken care of at this point?

There's always things going on in that area in terms of what's pending. We still have some more work to do on Tehachapi in terms of getting cost approvals. We just recently got one -- Ron, why don't you go ahead and fill in the details around what the recent cost increases were approved for on the projects, and we still have to get Tehachapi going.

Yes, we submitted an advice letter on our Devers, Colorado project to raise the cost cap. That was approved by the commission, and we now feel that project will come within that cost cap, and that positions us well for the ultimate cost recovery at FERC.

Tehachapi, we will submit our revised costs by probably the end of this year to reflect Chino Hills, the FAA and then cost increases that we've experienced over time. That's likely to be an application and a little lengthier process, but, again, ultimate cost recovery is at FERC.

The other item that has come in on our transmission projects is the commission did approve our petition to modify and put the voltage control equipment back into the project which they had previously taken out, which from a schedule perspective was helpful for us.

Great. In aggregate, what is that in total dollars if you could kind of summarize what is pending if there's any sense there?

On the voltage control?

Kind of in aggregate but yes specifically.

It's incorporated in the number that is shown in the Chart. (multiple speakers).

It shown in the number of the chart. Everything's in there.

Great. Thank you very much.

Okay, Julien.

Michael Lapides, Goldman Sachs.

Real quickly, in the prepared remarks, you talked about some of the incremental capital opportunities that actually weren't in the capital spending guidance levels, and one of the things you touched on was the Cal-ISO potential incremental transmission. Can you give a little more color around that both in terms of process for gaining certainty about what that could be if anything and then just size and scale?

Yes, we wanted to give you a sense further. There are some things that are on the I would say the periphery of our capital expenditures forecast because those are a little bit further out in time. And Ron is going to pick up the detail in what we are actually -- there's a particular project, an economic project that we're looking at right now.

Yes, from a reliability perspective, I believe the plan does include our Mesa loop-in, but, as Jim pointed out, that is down the track a ways later in the decade.

The Delaney Colorado River line was also included in the plans. Since that is an economic line, that will be subject to competition, and it terminates in our territory. We have every intention of participating.

Meaning that project is in your current CapEx guidance or it's in the plans submitted by the Cal-ISO but not necessarily included in your outlook?

It's in the plan, just come out by the Cal-ISO. We've not incorporated it into our capital spending plans yet.

Got it. Okay.

Michael, on that and go back, that was the old Devers DPV2 line.

Arizona portion.

The Arizona portion. So it's come back now as an economic line.

And how big of a -- what are we talking in terms of capital and in terms of years to build?

We're still working on it, but that is still yet to be determined.

Got it. Okay. Thanks, guys. Much appreciated.

Gregg Orrill.

Just was wondering if there was an update on San Onofre settlement talks. If there's still a path for that regarding the OIIs?

We really don't have anything that we can talk about on that one. Sorry.

Stephen Byrd, Morgan Stanley.

I wanted to talk actually about the longer-term point you raised about the transformative sector change, and you mentioned legislative efficacy AB 327 (technical difficulty). I wonder if you could just talk broadly to as you see the net metering debate and the key change that need to be made to make sure that as renewables are brought onto the grid, they are done so in a thoughtful way?

Yes, Ted touched on it in my remarks. Basically the AB 327 reinstated the California Public Utilities Authority to do rate design and gave them some general parameters around fixed charge, reducing the number of tiers, what the grandfather -- deciding what the grandfathering period would be for existing distributed generation projects using net metering, net energy metering, and then what the new net energy metering tariff will be and a few other things in there as well. But those are the main parts.

So that's now going to be the subject of a number of proceedings before the California Public Utilities Commission.

I think our general point of view was the legislature clearly made their intentions around this clear. Both the Senate and the assembly passed the legislation with super majorities signed by the governor. So there is a pretty clear indication of what the overall direction should be. The details are going to unfold over the next few years here.

I think we feel that broadly speaking the value of that legislation and the upcoming activity by the PUC is that it should meaningfully address what the -- what we see as subsidies and more importantly cost shifting amongst sectors within the retail or residential rates, and that should be, I think, a net benefit for fairness for all customers.

The other part that we see that is beneficial is it's a good move towards establishing some level of fixed charge. We have large fixed costs associated with maintaining the reliability of the grid, and this just recognizes some of that. So those are kind of the broad policy points that we expect to see implemented through AB 327 and the PUC actions related to that.

Understood. Is there any sense of the timetable over which that deliberation process will take place?

Well, it will probably be over the course of some years. It won't be all this year, but there'll be some important moves even as early as here in 2014.

Great. Thank you very much.

Ali Agha.

Jim, you mentioned in your remarks that your rate base numbers obviously exclude SONGS. Once the Phase II decision comes out, you will relook at those rate base numbers. Would that also be a time for you to relook at your guidance for 2014, you know, depending on what you do with that SONGS rate base?

Yes, I think clearly if the commission came out and allowed some portion of SONGS to be considered used and useful and actually received a return on common equities is the important piece. And for that matter, because we've excluded $0.07 you can see in the guidance for 2014 for debt and preferred stock, surely we would go ahead and adjust guidance for that purpose.

Okay. And second question, can you remind us at the end of the year what was the equity ratio at Edison that's used for ratemaking purposes?

Yes, the weighted average 13-month average was 49.2%, Linda? Okay. She is saying yes.

49.2%. Got it. Thank you.

You're welcome.

Asher Khan.

Jim, I was just trying to understand if I did my math right, you said that though we have a negative on the purchase power but overall if we take everything together, we have over collected by an amount, right? That's what you mentioned in the slide?

Yes, I think I said it was approximately $500 million over collected in all of our balancing accounts.

So that means if the commission came in and if they found some portion of it used or useful on all that, the over collection would be much higher, right? If you get some credit from somewhere or the other, right? Am I correct or wrong?

It's more complicated on that answer. So let's separate fuel and purchase power out from base rates and decommissioning. That's why this thing has gotten so confusing, and it's hard to track each piece.

So you may know that we are continuing to collect in rates at the full authorized rate of base rates for SONGS as if it were continuing to operate, and we're not recognizing earnings. We stopped the depreciation, and so we're collecting all those dollars waiting for an ultimate determination as part of the ratemaking process through the investigation, the OII.

So these are all separate buckets, and frankly, I think it was yesterday or the day before we sent a letter to the commission to say you have all these different proceedings going on simultaneously, here's our roadmap to how we want all these things to come together so you can determine what the rate adjustments need to be because your over collected in some areas, under collected in others. We also have decommissioning that's going on separately. They haven't authorized us to tap into the decommissioning trust, but in theory since June 6, we have been decommissioning San Onofre. So there are dollars that need to come in, and in our disclosures we didn't have a chance to take a look at them. There's at least a couple hundred million dollars of decommissioning funds for 2013 alone, and then we are going to look to 2014 for additional dollars that need to be taken into consideration. So the net net net of all this is it has to be worked out, and it is going to take some time to get there.

And if I could just end up with one thing. Ted mentioned that we should hear from NEIL after their June board meeting. So is that the first time we can hear how much money they will give us? Is that what we should expect to hear some kind of a figure from them, and I would assume that we would get something in the second half of the year?

Well, that's when we are going to hear from NEIL. That will be our first opportunity to hear from them at their board meeting. All we're really signaling there is that's the timeframe for getting the first reaction from NEIL.

Okay. But Ted, once they come to a decision, when do they pay out? Is it pretty soon, or is there some historic I forget now?

I don't think we want to signal a speedy resolution here. I think it's just the nature of the beast tends to be slow.

Okay. Thank you.

Jonathan Arnold, Deutsche Bank.

Quick one. Just on the SONGS decommissioning slide 24, I'm not entirely sure if this is new, but there's a bullet there saying estimated decommissioning period may be accelerated. Could you just explain there what would be the determinants as to whether that would happen and what are you referring to?

Remember the original plan and I'll throw it out to Linda and Ron to give some more details was the decommissioning plan after we shut it down in 2022. That's what the plan had incorporated to begin with.

And so now we're looking at various things that we can do to accelerate the timeframe, and that really has to do with getting the spent fuel out of the pools as quickly as possible and into dry gas storage. So I'll pause there, and Linda or Ron, would you like to fill in some more details?

I'll just add to that that we're going through a very detailed decommissioning cost estimate, and as part of that process, we're looking at optimizing the dollars around decommissioning.

So, Jonathan, I think you should take from us that once we finish that detailed review, we will come out with a new timeframe and a new dollar amount of what we expect the contributions will be if needed going forward. We're at $23 million in total annual contributions right now or in rate recovery from the commission, and so we will be looking at that. And there's a lot of moving parts here, and it's the timeframe for removal of the spent fuel, the rate of return.

There's a whole bunch of issues we are looking at, but there's probably eight or nine key assumptions here. Escalation of costs going forward. So this number is going to change as we go forward here, and the last time we talked about it we had over $3 billion in trust for San Onofre currently, and the cost estimate was slightly over that amount. So we were nearly fully funded. And the final costs studies will give us a better picture of where we are.

Okay. And then just Jim, maybe on a high level, these extra potential capital spending items you talked about, you talked about some of the transmission. I think if I'm not wrong, the storage stuff is part of that too?

Yes.

Can you talk maybe a little bit on that piece, and then as you aggregate all of that together, is this something we should think of sustaining you in the 7% to 9% rate base track over a longer period? Is it something that's going to be incremental over this latter part of the decade? Just how should we think about how we have molded that into everything else you're doing if some of it goes ahead?

That's a good question. I think we need a backup and look at our capital spending in total. What's been happening and you can see it through the charts, the level of distribution spending is definitely not to me the replacement rates that we need to be at. So that's just poles and wires, underground cable. Poles, so that's why that's going up.

And transmission has been coming off as we've been finishing some of the large renewable lines, and we just had a little bit of legacy generations ongoing.

So, as these other things we're looking at and considering, we haven't made any decisions. So it has the potential to maybe add a little bit to the total level of capital expenditures. But it's going to take us a little while to work through these things. The preferred resources and the storage are the first ones on the horizon that we need to decide what we want to do.

On some of the storage-related items, they are in the distribution system, which we feel that we are well-suited for because that's really down to the basic wires of the business that we want to control generally going forward. So I can't give you a number, but we're certainly thinking hard about it, and we are watching that growth rate. And we are trying to balance all the things here, too, in terms of the ultimate level of growth, and we want to grow the dividend so all this plays in together.

Can I just ask one other?

Sure. Go ahead.

It might be a Ted question. Just on the -- as you see the distributed solar move from the gathering pace, obviously it's still relatively small versus the overall base, but I know you've made some investments outside of California. Is there a structure or a sort of market design destination where you can see yourselves competing in that business?

Maybe I will break it into two parts. One, whether it's distributed solar or just let's call it more broadly distributed energy resources, that would include solar, include efficiency programs, include storage, all of those things. We see actually a significant investment that needs to be made in the distribution system here in California to really prepare the system for integrating an increase in distributed energy resources.

Jim alluded to it a little bit in his comments. We're clearly in the best position to do that given our ownership of the distribution system. So that's part one. We see a pretty significant investment opportunity on that side. It's very much in sync with public policy here in California and very much in sync with our own strategy.

The second part is whether we'd be able to participate in distributed energy resources. Again, I'm using a broader definition of that, not just things like rooftop solar but broader distributed energy resources outside of the territory. At this point, we are certainly working on that. We have what we think are some interesting beginnings in that area. I've kind of taken pains in the past to say we're doing this kind of one step at a time. It's not a bet the ranch type of deal. But I think we do see some interesting opportunities there, primarily being the commercial and industrial customers, and would be not just in our territory but outside.

So I would say, you could be inside the territory. It initially sounded like you were talking outside the territory.

It could be either one. Of course, our primary interest initially is understanding what the opportunities are on a broader scale outside of just our constrained 50,000 square mile territory.

Thank you.

Jon Cohen.

I was just wondering if you could give us an update as to what the process is for SONGS replacement capacity procurements? Is there a level that can come from in basin generation versus transmission, and what's the timing around all that?

Jon, Ron is going to handle that.

Yes, the commission has been approving through our long-term procurement plan proceedings the amount of generation that we're going to go out to bid for both ourselves and San Diego. Those numbers are all public and available. I don't remember them quite off the top of my head. They did fold into the TISO's transmission plan. So it is being coordinated in that fashion.

Our procurement teams are getting ready to do that. And then we have also taken on, as Ted alluded to, the preferred resources pilot in South Orange County where we will put together a package of replacement options with preferred resources such as demand response, solar, storage and the like. And that pilot, our team is aggressively putting together to fold in, and that will reduce the amount of generation that we ultimately have to buy through the market.

Okay. Great. Thanks very much.

Travis Miller.

A follow-up on a couple of these questions here on all distributed generation, etc., etc. What do you think is a timing element for that? You guys do move slowly as you characterized it. Are we talking about five years before it's material, 10 years before it's material? When does this become an earnings -- material earnings driver all this other stuff?

This is Ted. We are definitely interested in answering that question as well. I think the honest answer is it's really hard to tell at this early stage. So we think it would be foolish to kind of turn a blind eye to it and not focus on it. This is one of those things that could potentially change how the industry is structured. So it's something we are involved in. We intend to remain involved in it, but the pace with which that could happen, whether it really proves itself out, that's very much an open question.

That's why again we are going to take pains to make the statement that the core value proposition for the Company remains very much centered on the exceptionally strong growth story that we see within Southern California Edison, particularly ensuring that the distribution system is resilient and reliable, and we see a significant investment required there to do that. And we think there are ways to continue to address the cost side of the equation so that we don't have a big impact on rates for customers. That's the core value proposition.

These other activities, they remain things that we are actively involved in and we will continue to be actively involved in. But it's hard to truly hard to predict at this early stage what the pace will be and whether they will be meaningful or when they will be meaningful.

Got it. Okay. Thanks so much.

Michael Lapides.

Just curious with the resolution of Edison Mission, do you see an opportunity to reduce the cost at the parent, kind of that $0.15 level range has kind of been that range for a number of years, but now you don't have the nonregulated subsidiary.

Actually we have been. This is Ted. We have been addressing that. I don't remember the exact numbers, but we had something in the neighborhood of 80 people within the holding company from senior officers to clerical folks. So it's always been a very modest size group.

With the EME difficulties, we started addressing that and have brought that down, actually basically about in-line percentagewise with the reduction in staff that we had occurred at Southern California Edison over the last couple of years. So it has been something we've addressed. These just are not particularly big numbers. Like most of the costs there relate to financing and stuff other than what I'll call overhead costs.

So it's a great question, but it's actually not a particularly meaningful number.

I think Jim actually mentioned we are averaging somewhere, including financing and all the rest of the stuff, we are averaging somewhere around $0.01 per month. So call it $0.12 currently.

Got it. Thank you, Ted. Much appreciated.

That was the last question. I would now like to turn the call back to Mr. Cunningham.

Thanks very much for joining us today, and please don't hesitate to call if you've any questions. Thank you.

This now concludes today's conference. All lines may disconnect at this time.