Edison International (EIX) Q2 2015 Earnings Report, Transcript and Summary

Welcome to the Edison International Second Quarter 2015 Financial Teleconference. My name is Jaclyn and I will be your operator for today. [Operator Instructions]. I would now like to turn today's call over to Mr. Scott Cunningham, Vice President of Investor Relations. Mr. Cunningham, you may begin your conference.

Thanks, Jaclyn and good afternoon, everyone. Our principal speakers today will be Chairman and Chief Executive Officer, Ted Craver and Executive Vice President and Chief Financial Officer, Jim Scilacci. Also here are other members of the management team. The presentation that accompanies Jim's comments, the earnings press release and our Form 10-Q are available on our website at www.Edisoninvestor.com. Consistent with last quarter, we posted Ted's and Jim's prepared remarks so that you can follow their comments. Tomorrow afternoon we will distribute our regular business of the presentation for use in upcoming investor meetings. During this call we will make forward-looking statements about the future outlook for Edison International and its subsidiaries. Actual results could differ materially from current expectations. Important factors that could cause different results are set forth in our SEC filings. Please read these carefully. The presentation includes certain outlook assumptions as well as reconciliation of non-GAAP measures to the nearest GAAP measures. During Q&A please limit yourself to one question and one follow-up. I will now turn the call over to Ted.

Thank you, Scott and good afternoon, everyone. Second quarter earnings were $1.16 per share, up $0.08 per share from last year. However, until SCE receives a decision on its 2015 general rate case, comparisons of year-over-year results will not be that meaningful. Jim will have the details in his comments. Today I will touch on several policy and growth topics but first a comment on a comment on SONGS. We were disappointed about the renewed uncertainty surrounding the SONGS settlement. Most of the recent procedural moves and various motions have come from individuals and organizations that have consistently opposed the settlement since it was first announced over a year ago. It was more troubling to have one of the six signatories of the settlement, The Utility Reform Network, advise the CPUC in late June that it no longer supported the settlement. Interestingly, in TURN's announcement, it about which acknowledged that the terms of the settlement were good for customers and that the outcome of any litigated reconsideration process may not differ substantially from the terms of the settlement. TURN is an important voice on consumer matters before the CPUC so we must hope that its failure to adhere to its obligations under the SONGS settlement represents an aberration. We have now responded to all requests for information from the CPUC's administrative law judges regarding the challenges to the SONGS settlement. We're hopeful they will rule on the outstanding issues soon. Prolonging this period of uncertainty is not good for anyone. We continue to believe strongly that the settlement met all of the required standards for last November's unanimous commission approval. We believe that the SONGS settlement was the product of good faith arm's-length negotiations that resulted in a fair and reasonable outcome for our customers. Let me turn to some regular toward policy developments. The CPUC recently ruled on a residential rate design reform as required by Assembly Bill 327. Their recent unanimous decision was the product of significant debates and compromise among the commissioners. We didn't get everything we advocated for. We would've liked to have seen more progress in increasing the proportion of revenues collected through fixed charges which would better match our actual cost of residential customers but the minimum bill will be raised from $1.80 to $10 a month. Also, we preserve the opportunity to revisit a more meaningful fixed charge in the future. We achieved rate reform that places approximately 96% of our retail customers' kilowatt hours into a two-tiered rate section structure, very similar to what we recommended. About 4% of our retail customers' kilowatt hours will be subject to a surcharge for high usage. The commissioners invested a tremendous amount of time and effort in this phase of the proceeding and we appreciated the unanimous agreement that getting residential rates closer to the true cost of service was an important tenant in producing fairness amongst customers. Attention will now turn to the portion of the CPUC proceeding on net energy metering which relates to how customers who opt for rooftop solar are credited for their own generation. Parties will be filing their net energy metering proposals next week. Turning to a different subject, we have received broad support for SCE's Charge Ready program. This is the program we announced last October to invest infrastructure to support transportation electrification. On July 9, a settlement with most of the parties was filed with the CPUC on the $22 million pilot phase of the program. Importantly, both TURN and the Office of Ratepayer Advocates are parties to the settlement, as are environmental organizations and electric vehicle charger equipment companies. The principal change to our original application in the settlement is to expense rather than capitalize the rebates that SCE would provide customers for the vehicle chargers installed. While it didn't change the amount recommended for the pilot program, we expect that if this provision is adopted for the full program the rate base opportunity will now be $225 million of the total $342 million estimate for the program. We look forward to commission action on the pilot and subsequently on the full program. The final topic I want to cover is SCE's distribution resources plan or DRP filed with the CPUC on July 1. We consider this plan to be one of our most important filings this year and probably in several years. We endeavored to not simply answer the commission's initial questions about integration of distributed energy resources but also to lay out our vision for how the grid of the future will facilitate customer choice of new technologies and support California's policies to move to a low-carbon economy. The goal of the distribution resources plan is to facilitate the integration of distributed energy resources at optimal locations within the distribution grid and to upgrade the distribution grid to better enable a plug-and-play approach for adding distributed energy resources and new technologies more broadly across our system. These resources include distributed renewable generation such as rooftop and ground mount solar, electric vehicle charging, energy storage, energy efficiency, demand response. California have used these resources as enablers in achieving its low-carbon objectives over the next several decades. At the expected adoption rate for these distributed resources, the electric grid will require substantial investment in modernization and upgrades. As part of its filing, SCE provided an initial view of the range of possible capital investments to achieve the goals of the DRP. Assuming the CPUC support this provides some indication of our view of the investment required for the long-term program which will likely go well into the next decade. Jim will talk about some of the financial details and how we see this working with the GRC process. As I've just indicated, significant capital investment will be required to modernize and upgrade SCE's distribution grid consistent with the DRP recommendations. This is in addition to continued distribution system reliability investment, anticipated electric vehicle charging and storage investments, continued transmission and generation maintenance capital investment and potential improvements in capital spending productivity. All of this is consistent with our lower risk wires-focused investment strategy. Taken together, we expect overall SCE capital spending to be at least $4 billion annually for the foreseeable future. Depending on the state's preferences on the pace of adoption and on approval of DRP-related work in future general rate cases, capital spending could be higher. I will now turn it over to Jim for the financial update.

Thanks, Ted. This afternoon I will cover second quarter and year-to-date results and several other topics. Please turn to Page 2 of the presentation. I will lead off my comments for the general statement about attempting to compare 2015 to 2014 earnings. Because SCE has yet to receive a 2015 general rate case decision, the utility is recording revenues largely based upon 2014 authorized levels. In the quarter SCE receives a final GRC decision, we will record a cumulative adjustment retroactive to January 1, 2015. Earnings comparisons will not be useful until we report full-year 2015 earnings. In the meantime, we believe the simplified rate base approach is the best starting point to model full-year earnings. As Ted said, second quarter core earnings are $1.16 per share. Consistent with our first-quarter approach, we did defer revenues to offset incremental repair deductions, pending the outcome of the 2015 GRC. The amount of deferred revenue this quarter was $0.09 per share with the offsetting benefit in taxes. You can see this in the summary of SCE's driver on this slide. On a year-to-date basis SCE has now deferred your dollar $0.16 of revenue from incremental repair deductions, because of the large delta between expected and forecast repair deductions for 2015, last May SCE made a filing with the CPUC to update its repair deductions for the 2015 through 2017 GRC period. With the May filing, SCE's updated 2015 revenue request would result in a $120 million revenue decrease from authorized revenues. For the two post-test years, the year-over-year revenue change would be an increase of $236 million and $320 million for the 2016 and 2017, respectively. We have no insight as to the timing of the proposed GRC decision. On July 24, SCE did respond to certain questions raised by the ALJ concerning they May filing regarding repair deductions. The questions related to the coordination of ratemaking between CPUC and FERC. The major items impacting second quarter results is a $0.31 per share tax benefit from reducing liabilities from uncertain tax positions. During the quarter, we received an IRS report for tax shares 2010 through 2012. Based on this report, we updated our estimated liabilities for uncertain tax positions which flow directly through to earnings. We had a similar benefit of $0.09 last year related to updating uncertain tax positions for other tax benefit years. Both of these are highlighted in the SCE key earnings drivers. Historically we have classified the change in an estimate of an uncertain tax position both positive and negative as part of core earnings and highlight significant changes that affect period-over-period comparisons. These items are not part of the simplified earnings model that we have discussed in the past and are subject to future revisions based on audits, new information and other developments related to our tax positions. Excluding the $0.31 share per share benefit second quarter core earnings are $0.85 per share with SCE contributing $0.87, offset by $0.02 loss at the EIX holding company. In the core EPS drivers table we netted out SONGS related impact on revenues, O&M and depreciation. On this basis, revenues are lower by $0.03 per share due to the $0.09 per share deferred revenue I mentioned earlier and partially offset by a $0.06 per share benefit from higher FERC-related and other revenues. Looking at costs, O&M has $0.01 per share positive variance which we continue our cost management focus. SCE's second quarter results included $0.02 per share in severance costs this year and $0.01 per share last year. On a year-over-year basis the difference is minimal because of rounding. Depreciation expense increased by $0.06 per share, reflecting SCE's ongoing wires investment. SCE benefited by lower financing costs by $0.03 per share. This relates primarily to higher AFUDC equity earnings. Turning to taxes, I've already discussed most of the major items. These include the uncertain tax positions this year and last year as well as the $0.09 per share of incremental repair deductions, that is the offset to the $0.09 of revenue, so no net earnings impact. The balance is lower tax benefits year over year of $0.12 per share, mainly related to lower flow-through tax benefits than last year, revisions to estimated liabilities of our net operating losses, interest and state income taxes. Remaining $0.07 per share negative variance includes benefit from last year that did not recur in 2015 such as generator settlements and a San Onofre property tax refund. For the EIX holding company losses were $0.01 lower than last year due to lower corporate expenses and higher income from affordable housing projects. We continue to wind down the Edison capital low-income housing portfolio. Please turn to Page 3. I don't plan to review the year to date result -- financial results in detail, but the earnings analysis is consistent with the second quarter results. As I have said previously, comparisons pending a 2015 GRC decision are not meaningful. Please turn to Page 4. You will see that the uptick in interest rates is reflected in the trend of the Moody's Utility Bond Index shown at the green line. The 12-month moving average line shown in blue is moving back towards the 5% base rate. Given the short time period remaining on the 12-month measurement period, it is likely that SCE's CPUC return on common equity will remain at 10.45% during 2016. At FERC, the moratorium on filing and ROE change expired on July 1. I would also like to touch on a few other SCE-related financial matters that are not shown on the slide. First, SEC's weighted average equity component, for regulatory purposes, was 48.9% at June 30 compared to 48.4% at the end of the first quarter. SCE is required to maintain a 48% common equity layer on a rolling 13-month basis. Second, SCE continues to make good progress on reducing its fuel and purchase power under collection. As of June 30 of last year, SCE's ERRA balancing account was under collected by $1.6 billion. As of June 30 this year, the ERRA under collection was $543 million. The billion-dollar reduction was from three primary reasons, SONGS settlement refund credits against the ERRA balancing account, the 2014 ERRA rate increase and lower-than-expected power and natural gas prices. As of July 23 commission conference, the CPUC approved SCE's access to the SONGS 2 and 3 nuclear decommissioning trusts for costs incurred from the June 2013 plant shut down through the end of 2014. These costs amounted $343 million and the amount will be refunded to customers via a credit to the ERRA under collections pursuant to the SONGS settlement. This morning SCE file the settlement agreement and the 2015 ERRA proceeding. As part of this settlement SCE has agreed to forgo any 2015 ERRA rate increase adjustment. We now expect that the ERRA under collection will be fully recovered before year end. Lastly, earlier this month both SCE and EIX extended the terms of their respective credit agreement by a year to July 2020 for $2.6 billion at SCE and $1.18 billion at EIX. The remainder $150 million for SCE and $68 million for EIX will mature in July 2019. There are no material changes to the terms and conditions. Please turn to Page 5. SCE's capital spending forecast is unchanged from the first quarter. Ted has already discussed the long-term growth opportunity around the distribution resources plan, but I want to add a couple of financial specifics. Please turn to Page 6. SCE preliminarily estimated up to $560 million in potential DRP capital expenditures during the 2015 through 2017 forecast period. These proposed expenditures are largely weighted towards 2017. SCE has requested a memorandum account for the 2015 through 2017 revenue requirement of these investments to avoid any retroactive ratemaking issues. DRP investment that are made within authorized levels for the 2015 through 2017 GRC period will not have any incremental earnings impact. If our total investment exceeds the amount authorized due to the DRP spending and if a memorandum account is authorized then we will seek to recover associated revenue requirements as part of SCE's 2018 general rate case. Please turn to Page 7. The rate base forecast for the 2015 through 2017 GRC period is unchanged from the first quarter. Please turn to Page 8. This chart provides 2015 financial assumptions and has been updated for year-to-date results and amounts related to revenue recognition on repair deductions that I covered earlier. Please turn to Page 9. I would like to finish with a recap of our investment thesis. The DRP filing and ongoing grid investments that Ted discussed strengthens the long-term growth thesis for SCE. Future capital spending at the $4 billion level implies, very roughly, a $2 billion per-year increase in rate base. We're planning to grow our dividend meaningfully as we move back to our target payout ratio of 45% to 55% of SCE earnings in steps over time. Lastly, we will prudently manage our capital structure and have no plans for external common equity. Thank you and I will turn to call over to the operator to moderate the Q&A.

[Operator Instructions]. Our first question comes from Michael Weinstein of UBS. Your line is open.

It's Julien here. I suppose first question out of the gate, in terms of the GRC, can you elaborate on the settlement opportunity? And also perhaps just in terms of the potential for a longer than a three-year resolution, is there an opportunity for a fourth year?

I guess it's very difficult for us to speculate on something like that and if there were settlement discussions we would not normally comment on that Julien, so I will just have to if I can duck that question. Three to four years -- we've only filed for three, it makes it challenging to do a fourth unless you had some kind of special arrangement. So as much as we would like to get these things done more quickly and get online and get them approved, it would be a challenge to do something like that.

Got it. But in terms of confidence in the timeline here, perhaps if you can elaborate?

As I said in my prepared remarks, we just don't have a view. We're waiting for a proposed decision and that's all we can say right now.

Fair enough. And then perhaps just terms of the wider CapEx program, obviously you provided it pretty meaningful update intra-quarter here. How are you thinking in the long-term? Is there going to be eventually coming out of this process incremental CapEx? Should we ultimately be continuing to think about 4 to 4.5 throughout the process of having these proposals, ultimately, I suppose ratified or adopted or what have you?

That's what we've been indicating. We've said in fact it was in my remarks and probably in Ted's, too, that we see that 4 to 4.5 range being sustained based on all the things we're seeing now and with the DRP but, again, some of it is subject to a lot of commission approval. Obviously that they are going to go through and review this and give us some indication as far as a time frame and so that's still a lot in their court in terms of how they work through it. But our current view is somewhere in that $4 billion to $4.5 billion range.

And yes we did get the question come back through and it's from Hugh Wynne of Bernstein Research. Your line is open.

I know you can't call the outcome but I was wondering if you might provide a little bit of clarity on the procedural steps that have to be taken by the commission to consider the potential reopening of the SONGS settlement and if so, the steps that you would expect after that.

Hugh, it's Jim. We're going to have to Adam Umanoff, our General Counsel, provide some answers there.

Good afternoon, Hugh. As you know, there is a potential petition for a modification from before the public utility commission. We really can't give you any certainty on the timing of the commission's consideration of that petition. Motions have been filed, responses have been made. There is no specific time period under which the commission is obligated to respond. We're certainly hopeful, as Ted mentioned, that this will be resolved quickly, but we can't give you any definitive timeline for that resolution. There is a companion motion for sanctions before the public utility commission in connection with ex parte communications or allegations of improper ex parte communications. We would hope that that would be resolved concurrently if not in advance of the consideration of the petition for modification.

And if the filing is -- the petition for modification is accepted and the San Onofre rate case is reopened, can you give us any general feel as to what the process for litigation would be and the timeline for that?

Again, first and foremost, we don't believe that the existing commission precedent would support reopening of the SONGS settlement. But we certainly can't advise you with any certainty that it can't happen. If the proceeding is reopened we would return to litigation and litigation of the San Onofre OII would likely take considerable period of time. It would not happen in a matter of weeks or months.

Our next question comes from Michael Lapides from Goldman Sachs. Your line is open.

On SONGS, can you give an update in terms of where you are in the process with NEIL? And also there were lots of headlines over the last couple of days about the arbitration with MHI. Can you just give an update on that as well?

Sure. I would be happy to. Hello, Michael. With respect to NEIL we continue to pursue recovery of our losses from NEIL but really can't speculate as to the timing of concluding that effort. With respect to MHI, I think it's important as a preface to remind everyone that we're subject to a confidentiality order from the arbitration panel who is hearing the MHI claims. We're not in a position to comment on any of the substantive or procedural activity in the MHI arbitration. I can tell you that we believe we're still on track for a spring 2016 hearing and I hope for resolution to that hearing and final order later in 2016.

Can I ask just a procedural question, if any of the parties has issues with the final order that comes out of an ICC arbitration, if they want to litigate, can they? And if so, where?

Generally the arbitral order is expected to be final. There are very limited grounds for appeal. It remains to be seen if a frustrated party chose to appeal where they would take that.

Our next question comes from Steve Fleishman from Wolfe Research. Your line is open.

Could you may be spend a little time going through what the DRP process is from here and what the commission is actually going to decide on the DRP?

Sure. Steve, this is Pedro Pizarro. We filed -- we and the other utilities filed our plans on July 1. From here, the commission is going to go through a traditional process to review the filings and ultimately comment and approve on them. As Jim mentioned in his comments, in addition to the element that the PUC asked for in the filing, they asked for things like an analysis of the capacity of our system to integrate distributed resources, approach that we will follow to provide transparency to the market in terms of what the capacity is and how we will update it. There was also a number of demonstration projects that we propose to do per the PUC order. So they will plan on all of that and ultimately approve a final approach. We also asked for the memorandum account treatment that Jim mentioned. So at this point I don't think we can speculate on final timing but we would expect under a typical timeline -- this is a new process but in a typical PUC timeline we would expect approval sometime in the next year.

And is this a case where there is intervention and people can have their own view on your proposal? Is this something then where maybe there could be a chance to try and settle this case? How does this case proceed from that aspect?

So it is a litigated proceeding so there will be opportunities for interveners to file comments and for different views to be aired at the PUC. Really too early to comment on whether there is a prospect for settlement among parties or the like.

Okay. And then just a question on the memo account treatment. So you wouldn't keep seek recovery of the investment through 2017 until the GRC. But under the memo account would you effectively be able to recover that investment on like a non-cash basis with a return in the meantime?

That's a good question. There's still some speculation in terms of how it actually operates. The memorandum account, as I said, was really just to preserve the opportunity to recover the revenue requirement associated with the expenditure. So you can go back and essentially attempt to justify the reasonableness of the expenditure. Then through the general rate case in 2018, we would hope to seek recovery if in fact all the conditions were met. I wouldn't expect -- I think you are trying to go for some additional earnings in the 2015 through 2017 time frame associated with it. I think it's too early to project that we would, in fact, get anything. I think it's going to be more weighted towards 2018 anyway. And if you look at the charts that show the level of expenditure for the DRP, it's heavily weighted toward 2017 anyway, if the commission will allow us to spend that kind of dough.

Our next question comes from Daniel Eggers from Credit Suisse. Your line is open.

on the long-term CapEx discussion, if you think about kind of the buckets -- the 2015 to 2017 period of CapEx, soft phase-out of transmission, more distribution and maintenance work. If you think about that 2018 and on, what CapEx is getting substituted out? So think about the changing mix of your capital, how do you see it evolving as the DRP money comes in more significantly?

Transmission, we will have to see what happens ultimately with some of the legislation that is pending too. We've been seeing that it's gone up as we have built the renewable lines. Now it's been coming down as we're finishing Tehachapi and a few other renewable projects we've got in the pipeline. We've been saying all along there's not much generation. It's about $100 million of maintenance capital we have for the legacy generation fleet. The rest -- we've been saying as transmissions come down we've been stepping up distribution because we're trying to get our replacement rates up to where they need to be so they support what we're trying to do from an overall reliability perspective. So we're trying to balance us all within the $4 billion range and that's the goal. That's what we're trying to work for and hopefully we can fit all of this in with the DRP accordingly. So I'll look at Maria or Pedro -- anything else to add?

Maybe what I would add Jim, is think about one of the base spending areas is that infrastructure replacement for distribution system that will continue. In the DRP filing we outlined a number of categories of DRP-related investments. I would expect that as we go through future rate case cycles that line between what's called quote-unquote new DRP spending and what's core distribution spending will start to emerge as these technologies of the future really become part of the core mainstream of core distribution system. One other piece there is that some of the DRP spending -- the grid reinforcement piece that we have outlined for both 2015, 2017 and then beyond time frames, some of that is accelerating work that might normally see as distribution infrastructure replacement. It's hardening circuits that might be some of our lower voltage circuits that need to be brought up to more modern higher voltage circuit so they can accommodate greater number of distributed resources. So that's, again, an area where we're taking investments that may have been part of a longer-term infrastructure replacement plan but because of the need to integrate distributed resources it needs to get accelerated forward in order to harden the grill and allow faster adoption of the new technology. So again that's a place where you see that line over the years ahead blurring a little bit between infrastructure replacement and the DRP bucket.

And just on transmission with the Delaney line going away from your Group, how do you guys think about the ability to win bigger transmission projects in California in the future? Is this going to become just a lowest-cost bid type of environment that makes it harder to get the most optimal project on?

So you know the ISO is running their competitive process in the under FERC Order 1000. We had did with partners in the Delaney-Colorado River process. We expect that as other opportunities come up in our service area we will continue to bid on those and put out competitive proposals. I think as we go through this and, frankly, not only ourselves with the entire market continues to learn in terms of what the competitive practices are in terms of designing lines, constructing them, etc. I think we want to be part of the learning process and make sure we're making our proposals more competitive in the future. So, we're still capturing the lessons learned out of the Delaney-Colorado River experience but certainly support the process of the ISO's going through and evaluating proposals and accepting bids based on the parameters they are evaluating.

Our next question comes from Jonathan Arnold from Deutsche Bank. Your line is open.

Firstly, just on the deferral -- the revenue deferral, should we think of that as basically lining your actual expense up with where the revenues are going to be so there's really no earnings impact of this as we get -- once the GRC is done?

Roughly that's what we're trying to do.

So maybe a bit less noise in the numbers? At least from that source.

Well the goal here in the May filing is really what you need to go back to, is that the misalignment between the actual expenditures and the deductions we're taking and the forecast and the reserves are creating first and second quarter, what we're trying to do is get this stuff put together and we recognized that they were misaligned. And that's why we went back in for the supplemental filing. And if they adopt that supplemental filing, obviously that would not flow to earnings. So if that's your initial question, the answer would be yes.

And then just on to this question of the overlap between DRP projects and spending fact that you might otherwise -- things you might otherwise have done. You have a 2017 -- you said it lot of the bulk of the initial DRP is in 2017. You have a rate case filing in. Is there overlap as you see it today or is this just things may evolve as you work through the next year or two?

So it's not in the current GRC forecast. The only way we have contemplated spending some money is if you don't spend all that is authorized, for example, if you have fewer service connections that we have forecast, that creates some delta, some room to spend additional dollars. Now what I said in my prepared remarks, if we spend all this authorized based on our forecast and we would like to make DRP expenditures above that, that's where the memorandum account comes in, why it's important. So you don't get into any retroactive ratemaking issues.

But it would require some other line item to come in below the forecast for this to have to apply in the current rate case period?

In that scenario, yes or a memorandum account and spending above.

Okay. And can I just -- MHI -- it was pretty publicly reported that your claims had increased very substantially versus prior disclosures. Can you shed any light on that in the context of talking about confidentiality, etc.?

Jonathan, I appreciate the question -- would love to tell you more, but in accordance with our confidentially obligations we can't comment.

Our next question comes from Travis Miller from Morningstar. Your line is open.

I was wondering if we can go back to the DRP here, yet again. The 2018, 2020 numbers -- I wonder if you could just qualitatively give us an idea of the difference in how the environment looks at the $1.4 billion low end and the $2.6 million high end. It's obviously a large -- what difference happens there?

This is Pedro again. And I'll keep it at a pretty high level -- one of the reasons that we have the range there is that especially as we start getting out into the 2018 to 2020 time frame a lot of our view on the DRP is colored by our internal forecasting of the pace of adoption of technologies and how that pace of adoption varies across different parts of our system. For example, the capital spending forecast that we included in the DRP filing really focused on urban areas. We're assuming that rural areas would not have as quick a pace of adoption and it might happen in later years. We've taken a stab at what circuits might have a faster level of adoption versus a slower level of adoption. But I think that range in there really is coupled back to where do customers end up choosing to deploy these technologies? How quickly do they do it? And what things do we need to do to ensure that our grid is ready to plug-and-play their choices? I think that's really the range as opposed to more a determinative decision on our part to invest here or there. Some of this we're really changing the mindset here to make sure that we're supporting having a grid that's robust and that can keep pace and be ready for customer choices. But we're taking a bit of a stab at this point as to what those customer choices will be.

Travis, you can see on Page 6 of the investor deck the breakout of the spending. $0.5 billion of it alone is the grid reinforcement. That's what Pedro alluded to, is taking the lower voltage circus circuits and taking up to higher voltage levels to prepare for more distributed generation. And that's just pace. How fast do you want to make those changes? That's a choice that we will have to make and the commission will have to make together.

One other variable that we cited in filing is -- again, we're making forecasts based on our current view and the market's current view of technologies available. For example, communications systems. We know we will need to broaden -- expand the capabilities of our field area network. We're building these capital numbers based on the view of what those technologies will cost today, but we all know that computing communications technologies are on a very fast development curve and so the actual prices, the actual cost for those technologies can vary significantly as we head out a few years out.

Our next question comes from Ali Agha from SunTrust. Your line is open.

Coming back to SONGS for a second and just looking at the key gating items we should be keeping an eye on. You've got that re-hearing request out there and then you've got the ALJ trying to close the OII proceeding that continue to get pushed back and now has that September 27 deadline recently approved. How significant is that in the scheme of things? And if they stick to this final deadline and close the books, does that imply some final resolution on this matter or is that irrelevant to this?

We certainly hope that the CPUC will now conclude its consideration of the application for re-hearing motion for sanctions and the petition for modification of the settlement, all by that September 27 date. But, frankly, there's no guarantee. That deadline for extension of the OII proceeding has been extended previously and it can be extended again.

Okay. But that proceeding is the one sort of gating items to keep an eye on. If they stick to that that could be the resolution date, if you will, of these matters?

It could conceivably be.

Okay. And separate question, Ted, to you, as you think about your dividend plans going through the December period, as you normally do, are those going to be completely independent of these regulatory issues out there? For example, if the GRC decision hasn't come out, if SONGS settlement hasn't yet happened or closed, would you still stick to your dividend plans based on your CapEx and cash flow programs or do these things influence how you are thinking about the dividend?

I think I would probably want to leave investors with the emphasis being on we've stated numerous times what our objective is. We've also stated numerous times -- and that's the return to the 45% to 55% payout ratio for SCE earnings. And we've also stated that it will take -- it's not going to happen all in one shot. We've made a very large kind of move last year. We want to continue to make solid moves in order to get back to that payout ratio. So that's where I would want to put the emphasis. To say that we will do that come hell or high water -- you never can say that. You have to take into consideration capital requirements, take into consideration all of these other proceedings. But at least as we see it today they all look like they are manageable within the context of continuing to make progress and deliver on one of our core objectives of getting back to the payout ratio of 45% to 55%.

Our last question comes from Paul Patterson of Glenrock Associates. Your line is open.

Just a follow-up on Dan Eggers's question on the Delaney transmission project. I guess what I'm sort of wondering is can you give us a feeling as to what -- you guys had the rights-of-way advantage, you're local. And Abengoa and Starwood come in and win, not only over you guys but others. What was their cost? What was their revenue requirement advantage that you think was instrumental in them getting the deal?

I don't believe that the Cal ISO has published the cost estimate, their revenue requirement for that project. The goal we have at this point is a statement from the ISO that in their view the proposed cost for that Abengoa team were significantly less than those of the next competitor and I don't think the ISO has publicized to the next competitor was. So it's tough to speculate on what some of the key drivers would have been. But when you think about around cost of transmission project, key elements would include everything from the upstream design of the project, what kind of powers, what kind of conductors to rights-of-way, as you suggested, to environmental impact and mitigating those impacts depending on what route you choose to the cost of the actual construction labor you are using to build. Very difficult for us to speculate on what it would have been, but, again, we note that the ISO said that the choice was based on the lower revenue requirement and also binding caps on capital costs and as well as the return on equity.

Okay. Do you know when they are going to provide more information? Cal ISO, I mean

I don't think we're aware of that.

Okay. And then just finally you mentioned the cost of capital in 2016. When do you guys think that that might be revisited? It's been deferred in the past in terms of -- you guys had that separate cost of capital proceedings. What's your expectation or what should we be thinking in terms of when the CPUC may go for this? And is there any potential that they may delay it?

Okay. Paul, this is Jim. Right now, procedurally we would file in April 2016 for cost of capital effective 1/1/2017. And that's cost of capital, that would be return on common equity, capital structure and the like. That wouldn't preclude an extension like we've done before, but the current policy or the current procedural path would be filing in April.

Okay. Is there any thought that there -- or any discussion -- maybe it's early -- it's July, I guess. But is there any preliminary idea as to whether or not you might be able to defer that?

It's a possibility. We've deferred it once already. This is the first time -- we've done it in the past and so generally the California utilities when I have talked with my compatriots at PG&E and Sempro, we like the procedure. We like the trigger mechanism. It's transparent. You can see it, you can see what's happening with it. So there's a strong desire on our part to continue to use it. If we can get an extension that would be great. If we had to go there in litigated process, we will just have to see where interest rates are. And it seems like it's coming right back to where we started three years ago -- well now four, if we get further on here. So the mechanism has worked well, given what we're trying to do.

Okay. But do you get the feeling that your counterparties on the other side might be willing to do that as well?

We've done it once already so we will have to see if they'd do it again.

Okay. And just finally, there is these legislative initiatives regarding the CPUC and other things, but regarding the CPUC and perhaps reforms. And there's been some changes and there are competing bills. Anything in particular -- any particular legislative initiative we think we should focus on or anything in terms of that area that might be coming up? I know there are a few of them. I was just wondering if there's one in particular that you think is more significant than others.

There is a hearing coming up in the middle of August directly related to ex parte governance issues at the CPUC. There have been a number of independent reports that have been prepared for the CPUC. There is a draft of the commissioner code of conduct that's been prepared and we welcome a transparent exercise considering reform to the ex parte and other governance rules of the commission. That might be worthwhile listening in on. Again, I think it's in the middle of August, so in a couple of weeks from now.

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

Thanks for very much, everyone, for participating and please do call us if you have any follow-up questions. Thanks again and have a safe day. Bye, bye.