Edison International (EIX) Q3 2015 Earnings Report, Transcript and Summary

Good afternoon, and welcome to the Edison International third quarter 2015 financial teleconference. My name is Brandon. I will be your operator today. [Operator Instructions] I would now like to turn the call over to Mr. Scott Cunningham, Vice President of Investor Relations. Mr. Cunningham, you may begin your conference.

Thanks, Brandon, and welcome, everyone. Our principal speakers 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. Materials supporting today's call are available at www.edisoninvestor.com. The key items are Form 10-Q, Ted and Jim's prepared remarks and the presentation that accompanies Ted's comments, Jim's comments. Tomorrow afternoon we will distribute our regular business update presentation. 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'll now turn the call over to Ted.

Thank you, Scott, and good afternoon, everyone. Today we reported core earnings of $1.16 per share. While this is well below last year's third quarter core earnings of $1.52 per share, year-over-year third quarter earnings comparisons, as was the case with the first two quarters of the year, are not very useful. This is because of the way we have had to recognize revenue with the delay in SCE's 2015 General Rate Case and how we are accounting for the recently released proposed decision. We have said in the past that we would provide 2015 earnings guidance when we received a final GRC decision. However, with the noise in our quarterly earnings numbers, we thought it a disservice to investors to have them guessing about 2015 earnings. Therefore, we decided it was best to provide 2015 guidance at this time today. So today we introduced core earnings guidance for 2015 of $3.77 to $3.87 per share. This guidance has some key assumptions that Jim will review in his comments. Of course, should the final GRC decision differ substantially from the proposed decision, we may have to revisit our guidance. We plan to return to our normal practice of providing annual earnings guidance for 2016, when we report full year 2015 results in late February. One more comment on the General Rate Case. While we feel the GRC proposed decision is overall generally constructive, SCE identified several important issues in its October 8 comments to the CPUC. Jim will cover most of these, but I want to touch on one in particular. The proposed decision attempts to recover certain tax repair benefits that were reflected in earnings in 2012 to 2014 through a permanent reduction to rate base of $344 million. We consider this retroactive ratemaking and a potential violation of Internal Revenue Service rules. We are hopeful that the CPUC will correct their legal error. If the Commission were to adopt the proposed decision's retroactive treatment of repair deductions, then SCE would be forced to write-off some or all of the $380 million regulatory asset related to future recovery of taxes. The final decision on SCE's General Rate Case is currently scheduled for the November 5 CPUC meeting. I assume most, if not all of you, are aware of the Administrative Law Judge's proposed decision released yesterday on penalties related to SONGS ex parte communications. In short, the ALJ found in her PD that there were eight communications that were late reported to the Commission, and found two Rule 1.1 violations. The PD proposed a $16.74 million penalty on Southern California Edison. There are additional procedural steps yet to come on this issue, but we are thankful that this appears to be moving towards resolution. This has been a painful episode, including for Edison, and I feel obliged to make several comments on it. First, I want to set the record straight on some misconceptions that are constantly being repeated. Contrary to the many reports, SCE has not engaged in, improper talks or communications with regulators, related to the SONGS OII. The important distinction is that the Judge found that we didn't report in a timely manner permissible communications with regulators. The communications themselves were not found to be improper or illegal under the ex parte rules, as certain parties have repeatedly and wrongly asserted. In our recent filing, we maintained that seven of these eight communications were either not required or outright not allowed to be reported under the ex parte rules. The difference of opinion is a direct result of ambiguity in California's overly complicated ex parte rules. Ambiguous rules require the parties to do their best to interpret them in practice, which creates a risk. We believe the rules need to be clarified and simplified, so that we do not find ourselves underwriting the risk of after-the-fact reviews. It is worth noting that even the ALJ concluded in her PD that the ex parte rules were ambiguous, and cited that as a mitigating factor in calculating the penalty. As I said in an earnings call a few quarters ago, we look forward to working with President Picker to clarify the ex parte rules soon. Many of the matters we deal with in our business involve tough judgment calls in contentious proceedings under ambiguous rules and conditions. We don't particularly like it, but it comes with territory. We expect controversy. We also expect a great deal of ourselves and our employees, because we provide such an essential service to society and we rely on the public trust. That is why it is important to do the right thing. We expect nothing less of ourselves. We want to earn the trust of our customers, the public and the CPUC, based on our conduct. While we aren't perfect and there will be times when we fail to live up to our own expectations and those of others, we must and we do set high standards of conduct for ourselves. We have an obligation to be transparent and open, and we will redouble our efforts to conduct ourselves in this manner. We will also work hard to support President Picker's efforts to clarify and improve the current poorly crafted ex parte rules. Strong efforts on both fronts will go a long way to avoiding a repeat of this in the future. On a brighter note, we were pleased to report last week the settlement reached with Nuclear Electric Insurance Limited, known as NEIL, on insurance claims related to the shutdown of the San Onofre Nuclear Generating Station. The settlement is for $400 million and covers all insurance claims by the three owners of SONGS related to the events leading to the shutdown. All necessary approvals have been received from the owners and NEIL. This is another important step in implementing the SONGS settlement, approved unanimously by the CPUC last November. Consistent with the SONGS settlement, insurance recoveries will first pay associated legal costs, and then 95% will be allocated to customers and 5% to the owners. SCE customers will receive its allocation as a credit to the purchased power balancing account known as ERRA. Assuming payment from NEIL is received in the fourth quarter, then customer benefits should show up in their bills as a reduction in purchased power costs in 2016. The larger claim against Mitsubishi Heavy Industries for the failed design of the replacement steam generators continues to proceed under binding arbitration through the International Chamber of Commerce. We still expect a decision on that case by late 2016. SCE's share of the NEIL recoveries and any MHI recoveries, including recovery of legal costs, will be treated as non-core. That is, they will not be included in our core earnings. There is still much procedurally to be accomplished before the SONGS OII and related matters can be completed. We are hopeful that this is all moving toward a conclusion this year or early next. We continue to believe that no new information has been presented to suggest that the SONGS settlement was anything other than independently-negotiated that warrants continued full support by the CPUC and customers. I'd like to turn to a couple of items that address some of our longer-term growth opportunities, starting with SCE's Distribution Resources Plan or DRP. Since the July 1 filing, we have seen tremendous interest among stakeholders, and some encouraging early support from a number of parties on our conceptual long-term approach. Appropriately, there will be concerns about cost and the pace of implementation of building a flexible 21st Century grid as outlined in our DRP filing. We are awaiting a more definitive schedule for the balance of the proceeding, which the CPUC indicates will be completed next spring. This should give SCE adequate time to incorporate DRP elements into its 2018 to 2020 General Rate Case, which we expect to file in the fall of 2016. Moving on, the California legislature provided its own form of support for Governor Brown's low-carbon goals and the DRP with the passage of Senate Bill 350. The Governor signed this bill into law earlier this month. Senate Bill 350 will move renewables targets to 50% of delivered energy from qualifying renewable resources by 2030. The current renewables target is 33% of delivered power by 2020. The new law provides some valuable implementation flexibility that will help us meet the goals at the lowest reasonable cost to our customers. It also provided legislative support for future utility investment in transportation electrification. This is one of the long-term growth opportunities that we see for Southern California Edison, just as we see similar opportunities around electric vehicle charging infrastructure and energy storage, as complements to SCE's wires-focused investment strategy. One final comment. I continue to believe that we have an attractive multi-year dividend opportunity that complements a strong earnings growth outlook. The GRC proposed decision, the DRP and SB 350 are all data points that underscore SCE's growth potential. This in turn reaffirms the dividend growth opportunity I've discussed on recent earnings calls. We recognize that for a few years now we have been below our targeted payout ratio of 45% to 55% of SCE's earnings. We remain committed to moving well into that target range in steps overtime. Hopefully, we will be well along the way to resolution on both the SONGS OII and the GRC before the Board's usual December consideration of a dividend increase. Even if both are not fully resolved by then, I don't see it impacting our ability to continue to implement our dividend policy. That concludes my comments. Now, Jim will provide his financial report.

Thanks, Ted. Good afternoon, everyone. I plan on covering third quarter and year-to-date results, SCE's 2015 General Rate Case proposed decision, capital spending and rate base forecast, a few other financial topics and guidance. Please turn to Page 2 of the presentation. Let me first address revenue recognition for the first six months and then for the third quarter. For the first two quarters of this year, we recorded revenues largely based on 2014 authorized revenues, which included a revenue deferral of $85 million or $0.16 per share related to incremental flow-through tax repair deductions. Our accounting was based on management judgment that these revenues would likely be refunded to customers. Having received the proposed decision, we updated our estimate of probable refunds to customers, as part of our third quarter reporting. This in turn lowered third quarter revenues. The GRC-related revenue reduction was $0.42 per share. This is comprised of the two elements shown under key earnings drivers at the right of the slide. As Ted noted, earnings comparisons will not be useful, until we receive a final GRC decision and report full year 2015 earnings. Of course, if the final GRC decision is different than the proposed decision, then there could be other related adjustments. With that background, I'd like to walk through the key earnings drivers, starting with SCE. There are two key earnings drivers of the $0.35 per share decline in SCE's earnings. First, as I mentioned before, we recorded revenue largely based on the GRC proposed decision, including a catch-up adjustment. Second, there were favorable cost and tax benefits realized in 2014, which did not recur in 2015. Looking at revenue, I've highlighted the $0.42 per share related to the GRC proposed decision. $0.20 of this revenue reduction is from the flow-through tax repair benefits to customers with a related offset in the form of higher tax repair deductions. The remaining decrease in GRC revenues are $0.22 per share. Also we continue to see revenue increases from a growing FERC rate base and higher operating cost. This is a positive $0.02 per share. Lastly, please note that the revenue variances is a net of SONGS for comparability. The SONGS detail are footnoted. Moving to the O&M. SCE had $0.03 per share in higher costs this quarter versus the third quarter of last year. This includes $0.01 per share of additional severance at SCE. Depreciation is $0.02 per share higher, primarily due to transmission and distribution investments. Net financing cost provided a $0.02 per share benefit, primarily due to higher earnings from AFUDC. Turning to taxes. I've already covered the $0.20 per share for the 2015 repair deductions. Most of the remaining variance relates to the $0.11 per share in earnings from incremental repair deductions recorded last year. In all, SCE's third quarter core earnings are $1.19 per share, down $0.35 from last year. For the holding company, costs are $0.01 per share higher than last year, largely on lower income from Edison Capital. I'll come back to Edison Capital later in my remarks. Non-core earnings in the quarter of $0.13 per share largely relate to EME bankruptcy, tax benefits and insurance recoveries. Please turn to Page 3. We've added this slide to simplify the explanation of third quarter core earnings. As you can see, the difference on this slide versus the prior slide is that we netted out the impact of lower revenues and income tax benefits related to repair deductions in 2015. As indicated on this slide, the two key drivers are the lower revenues based on the GRC proposed decision of $0.22 and the $0.11 of 2014 incremental repair deductions. That gets us to $0.33 of the $0.35 reduction in third quarter SCE quarter earnings. Please turn to Page 4. For year-to-date earnings, GRC-related revenue is $0.58 per share or lower, reflecting the $0.42 for the third quarter and the $0.16 for the first half of the year. Again, this is a mix of lower tax repair revenues $0.36 per share, which is offset in taxes and the third quarter revenue adjustment of $0.22 per share. Most of the costs items continue their trend and for the year-to-date we also have higher depreciation and O&M and lower financing costs from higher AFUDC earnings. You will also see the significant impact in both years related to changes in uncertain tax positions and lower tax benefits in other areas. Last year, we also had the generator settlements and other items that are absent this year. All in, year-to-date SCE core earnings are $3.31 per share, down $0.27 from last year. Page 5 has a similar waterfall chart of year-to-date core earnings. Please turn to Page 6. This slide compares the key revenue and rate base differences between the 2015 GRC proposed decision and SCE's updated request. The revenue adjustments are recorded in the third quarter; largely reflect the three quarters' worth of proposed decision's authorized annual revenue. Please turn to Page 7. This slide summarizes the most important issues identified in SCE's comments on the proposed decision. Ted has already talked about the tax repair deduction issue. Next is the customer deposit issue. Since the 2003 GRC, the CPUC has treated customer deposits as a rate base offset. However, PG&E and San Diego Gas & Electric do not have this adjustment. The third item is a proposed reduction in the pole loading program. The proposed decision did not approve approximately $100 million of capital, which has a 2015 rate base impact of $73 million. Putting aside the rate base adjustment for repair deductions, the proposed decision would adopt 92% of our requested capital. This is higher than previous GRCs, and of course, this percentage could change with a final decision. I will note two other key issues. The principal one is incentive compensation. The proposed decision recommended significant reductions in authorized revenues related to incentive compensation for the entire workforce, even though the jointly sponsored SCE and ORA compensation study concluded SCE's total compensation is on average 5% below market. We are strong believers in a pay-for-performance compensation philosophy and incentive-based compensation for all employees, not just executives, is a fundamental element of that philosophy. This reduction is larger than experienced in prior cases. Lastly, there is a $10 million disallowance for a contract termination payment dating back to SCE's commercial rooftop solar initiative. We believe the termination payment is reasonable and benefited customers substantially. In accounting for the quarter, the revenue adjustments track the proposed decision except for two items, the tax item and the solar program contract cancellation disallowance. I'll pick this up later when I discuss the rate base forecast and earnings guidance. Please turn to Page 8. Pages 8 and 9 update forecasted capital expenditures and rate base for the GRC proposed decision and known FERC-related capital expenditure changes. SCE is experiencing licensing and permitting delays with a few of its transmission projects, notably the West of Devers project. As a result, the timing of expenditures was moved out beyond 2017. Once SCE files its 2018 GRC application and we update our CapEx and rate base forecasts, these delayed expenditures will appear back in the forecast. The FERC adjustments are shown on the right side of the slide. The balance of reduction is related to the GRC proposed decision, largely infrastructure replacement, inspection and maintenance and nonelectric facility capital projects. Historically, we have shown what we call a request level of capital expenditures and rate base, and a lower range level. As you can see on the charts on Pages 8 and 9, we have replaced the word request with the word outlook. For CPUC capital, we now forecast that we will spend all authorized dollars for 2015 through 2017. For FERC capital, we have continued our practice of reducing outlook expenditures by 12% to arrive at the range level of expenditures. Once we file our 2018 general rate case, we will revert back to using both request and range monikers. As a reminder, the CPUC capital expenditures do not include any Distribution Resources Plan expenditures. We have asked the commission to approve a memorandum account, so we can track costs associated with the DRP spending. So if we were to spend all authorized CPUC amounts provided in the GRC proposed decision, then we would need to have the DRP memorandum account in place in order to be allowed to seek cost recovery in the next GRC. Beyond 2017, we still believe that long-term capital spending will continue to run at least $4 billion annually, and spending could be higher depending upon CPUC approval in future rate cases. Please turn to Page 9. Based on our revised capital spending forecast from the prior slide, we have updated our rate base forecast. The updated rate base forecast yields compound annual growth rates of 8% from 2015 through 2017. The prior forecast was 7% to 9% annually. Consistent with our accounting for the proposed decision, we have not factored in the proposed $344 million reduction in rate base related to the disputed tax repair deduction issue in this forecast. If the final GRC decision adopts the rate base adjustment, then each of the years rate base would decline by the adjustment amount. Please turn to Page 10. As expected, the CPUC cost of capital mechanism did not trigger any change in allowed ROE for 2016. Though the spot Moody's Baa Utility Index rate moved quite a bit, the moving average dampened the full-year impact. Starting October 1, we began the new measurement period, starting with the moving average where the spot rate ended at September 30 at 5.45%. We are currently scheduled to file our next cost of capital application in April 2016. Please turn to Page 11. This page covers a handful of other financial topics. SCE's weighted-average common equity component for regulatory purposes was 49.5% at September 30, increasing from 48.9% we reported in the second quarter. This excess equity gives us additional financial flexibility. Next, you will recall that SCE's fuel and purchased power balancing account, or ERRA, had been deeply under collected as recently as yearend 2014. With a previous rate increase, SONGS settlement refunds, lower natural gas costs and the balancing account has moved to an over-collected position of $112 million as of September 30. When SCE receives the NEIL settlement proceeds, expected in the fourth quarter, they will be credited to ERRA. Turning to the holding company, last month we renewed an EIX holding company shelf registration to provide us flexibility to access the capital markets as needed for liquidity and general corporate purposes. EIX commercial paper outstanding was $738 million at September 30, compared to a total EIX credit facility of $1.18 billion. Also, earlier this month we reached an agreement to sell our remaining affordable housing portfolio at Edison Capital. Terms of the transaction have not been disclosed pending final due diligence and negotiations. In any case, the amounts are not material and the transaction will be treated as non-core. For the past few years, Edison Capital's earnings have helped offset holding company costs. Please turn to Page 12. This page provides detail of our 2015 earnings guidance that Ted discussed. We have followed the same approach we have used for the last several years. We start with SCE rate base earnings. We used the $23.1 billion weighted average rate base outlook as shown on Page 10. Based on SCE's authorized capital structure and flat share count, that gets us the $3.56 per share of rate base earnings. We then identify $0.41 per share of SCE items that take earnings higher. The principal item is the $0.31 per share revision to uncertain tax positions recorded in the second quarter. We have also discussed AFUDC being a net positive factor for the year, rather than just offsetting costs not recovered by general rate case revenues. We continue to estimate $0.05 of energy efficiency earnings in the fourth quarter as previously disclosed. We have recorded severance costs of $0.03 year-to-date. The balance of all other items is a positive penny a share, including the ex parte proposed penalty. We have estimated full-year holding company costs at $0.15, getting us to the midpoint of $3.82 per share. To the right we have included key guidance assumptions. We had excluded the shareholder portion of the NEIL settlement proceeds and related litigation costs. We consider these revenues non-core. Our guidance tracks our accounting for the GRC proposed decision, so it excludes the $344 million rate base adjustment for repair deductions and the solar termination payment disallowance. That concludes my comments. I will turn the call over to the operator to moderate the Q&A.

[Operator Instructions] Our first question is from Stephen Byrd with Morgan Stanley.

Just want to follow-up on a couple of things in terms of spending outlook. The memorandum account for the GRP spend that you'd like to effect, could you talk a little bit procedurally just about how we should think about the steps to get approval for the memorandum account?

Well, we have actually already filed for it. It was part of the DRP application that's gone in and procedurally the commission then will have to act, and will look at over the SCE folks, any time frame for that Pedro or Maria?

This is Pedro Pizarro, not just about the memo account, but procedurally in the DRP filing there is public workshops that are scheduled for the November 9 to November 10, and there the PUC is looking at a broad DRP roadmap for how the DRP proceeding will be faced out in the next three to four years. With respect to the memo account itself I don't think we have a specific timing. We'd expect it would be handled as the proceeding moves along next year.

And then just follow-up on just thinking about the tax positions you highlighted in 2015. There are a number of moving parts in terms of uncertain tax positions and lower tax benefits. On a going forward basis in '16 and beyond without being specific numerically, how should we think about those kinds of moving parts? When do they start to settle down and when will they become less material, if you think future years?

That's a good question. And it really depends on ultimately how things turn out. I can tell you, for repair deduction, that's been a challenging one for us to forecast accurately. And I wouldn't expect that going forward that you will see potential shareholder benefits from repairs. But there're other tax benefits we realized, so it really comes to how accurate we are forecasting our cost versus what actually occur, so there could be differences both, for or against us. And the other related piece is O&M benefit, that's the other companion we've been talking about this whole time, where I think in the proposed decision it was clear that, it left open the door that there could be incremental O&M savings that we could realize and we've said repeatedly that we will continue to look for benefits to reduce our cost for our customers.

And as you think about those moving parts, in terms of the magnitude or volatility, I know it's hard to have a crystal ball to think about that. But do you see the same degree of potential volatility in terms of movements in these accounts or are there reasons why that volatility might be reduced in future years?

I think my answer around that was, around repair deductions, where I was talking about specifically, the proposed decision, I think effectively we'll probably capture those benefits. And there is also a balancing account that has been set up for our pole loading program, which a lot of the repair deductions are rising from. That's why these repair benefits have increased so dramatically over the last three years. So with that balancing account, there's not an opportunity for earnings or losses associated with differences from forecast. A lot of complexity there, sorry for all the -- there is still more to be written here until we get a final decision.

Our next question is from Michael Weinstein with UBS.

It's Julien here. So just following up here on the transmission reduction in the rate base, can you elaborate a little bit on nature of the issues in pushing up this CapEx, part one. And perhaps part two there, you talk about a $4 billion number, but is that fair to say that there might be some higher oscillations in that, call it, rounded $4 billion number in the '18 period now that you've pushed out this transmission CapEx. Just trying to get a sense of exactly what's going on in terms of those pieces.

So I'll just point you to Page 8 in the investor deck, which has the capital expenditures, and it provides the detail of the amounts that are changing. In terms of the reasons, what my script falls up on was these are permitting and scheduling delays and the principal the largest one is the West of Devers project. There is some other smaller ones, but West of Devers is a rather large project and we're just seeing it slip out in time. And I'll pause and look over to Pedro and Maria to see if there is anything else to add?

All right.

So that's what you've got. Now as far as the above $4 billion --

Just to clarify, if you will, you guys have historically talked about hitting a $4 billion CapEx pace consistently, does this now mean that you have call it a 2018 number that you're not closing here that would be call it materially above that $4 billion figure to reflect, call it a one-time true up on the CapEx for transmission?

Yes. And this is going to be a difficult one, because we don't have information in the public domain beyond '17. So I'm just going to touch a couple of items that we see that are changing both up and down to be fair. So clearly the DRP is a big element of potential new expenditures. We've provided information at public domain and you can see there is substantial ramp up of expenditures since '17 and as you go into '18, but those expenditures will be subject to review as part of our general rate case process. There are other things that are going up that would include our -- and we have an opportunity through the storage program. We have an opportunity through electric vehicle charging program. And those are still working their way through. And all three of those just to emphasize are not included in the numbers we're seeing here today, so there is some potential upside depending upon how those proceedings progress. On the down side, there is the transmission issue is they're still going to be -- we'll have to see where that goes, as you fit each some of this larger projects and we've ramped up in transmission area, then we ramp back down as they're finished and we'll get to a steady state of capital expenditures. We will just have to see how load growth goes that could be up or down depending upon the health of the service territory and the penetration of distributed generation resources. So I'll leave it there. There is ups and downs. There is probably more of a bias that we see to the upside, because of some of these large projects.

And just to clarify, in the transmission CapEx, just a tad bit more, is there any risk around, obviously you had the competitive project allocated. Is there any other moving piece that we should be aware of in the transmission bucket that could develop one way or another here? Obviously, the permitting was kind of unexpected.

Nothing that would stand out right now, Julien, beside what I told you.

Our next question is from Hugh Wynne with Bernstein.

Jim, I just had some, what I hope are, simple questions on Page7 around the rate case proposed decision. On the left-hand column there, the bottom bullet, the $73 million pole loading capital spending reduction? And then in the parenthetical below that it says $100 million capital expenditure reduction. What is the difference?

To one's capital to one's closings, and they don't always line up exactly. And so really, when you think about rate base, it's what's close to plant. So forecast don't line up exactly.

So they are basically telling you that they want you to spend $73 million more in your spending plan, and that is reflected in closings fulfilling by $100 million.

That was reverse. So they've taken out of the -- in the PD, they've take out $100 million of capital expenditures, which translates into $73 million of rate base. So it's lower, not higher.

And then the second point. What is the bone of contention around the customer deposits?

When you look at our forecast, they take the $180 million of customer deposits and reduce our rate base by that amount. And the bone of contentions is if there is not similarity of treatment among the three utilities, we seem to be treated differently, as a result of whatever reason. And then we've had this -- we keep raising this issue in the last several GRCs, and there is inconsistent treatment. We think that's unfair.

And then, finally, on the first point, I agree with everything you say there in the second bullet that seems like retroactive ratemaking and violation of normalization regulations, et cetera. But presumably the ALJ, who has a law degree, and I don't, has a different view. Could you characterize the different perspectives around this point?

Yes, it would be hard to characterize it completely; there was a number of arguments. But I think the simple argument that was made is that they set rates prospectively, so therefore how could it be retroactive ratemaking. We just fundamentally disagree on that point. And so that's something we'll have to figure out hopefully in the final decision that will address this issue. But we'll have to see.

Our next question is from Daniel Eggers with Credit Suisse.

Just on the $80 million of compensation expense that wanted you to get recovery on. Would you find ways to offset that or do you see opportunities to change your compensation structure like the other utilities to mitigate that drag?

Well, we'll certainly have to look at it. It was obviously a sensitive issue in oral argument in our comments. And we'll have to see what the final decision is. And we'll have to see how it unfolds. Hopefully, they turn it around.

And then, I guess, on the $344 million for this year's guidance, if you didn't get that or if the ALJ found against you, what is your course legally to address that, given the IRS issues and how would that affect the '15 guidance as you laid it out today?

In the course of action here, and I know Pedro talked about in the oral arguments and in our comments in the proposed decision that retroactive ratemaking, then you have a legal recourse. And there is a potential, as Ted said in his script, of a IRS issue, it's a normalization violation. So there is two different paths here that you might pursue. Hopefully, the Commission addresses that as part of the final decision, but we will have to see. So if it were adopted, and I think it was clearly in my prepared remarks, you'd have to take the $344 million off the rate base numbers for '15 through '17 to get back to an adjusted rate base approach.

Our next question is from Shar Pourreza with Guggenheim.

Most my questions were answered. There is a likely delay in the SONGS OII into early 2016, is there any impact to you providing 2016 guidance?

I guess, off the top of my head, and I'll hesitate and look at my collogues here. If we have a GRC decision, I think that's the critical piece we need to move ahead in providing guidance for '16. But I'll look at everybody else, I don't see the SONGS being a factor that would slow us down. And unless if they reject the whole decision, and maybe I have to go back and rethink it, but I think if we had a 2015 GRC final decision, we'd find a way to give guidance for '16.

And then just on MHI, we're obviously reaching some sort of a conclusion by hopefully the end of 2016. Is there any opportunities to give some incremental data points on that or is it just one of those where you get an order, you get a settlement, you'll disclose it at the same time?

So I'll pause here and look over to my friend, Adam Umanoff, our General Counsel. Adam any pros of wisdom?

No. Really we can't provide any additional guidance. We're operating under strict confidentiality rules of the International Chamber of Commerce proceedings. So you'll have to wait for a final decision that's announced publicly.

Our next question is from Jonathan Arnold with Deutsche Bank.

Couple of quick questions on. As we look forward, Jim, with Edison Capital out of the picture now, is it reasonable to assume that that $0.15 drag from the parent company that you are sharing for 2015, is the kind of number we'd be looking at going forward with no offset or are there other things to think about that?

We're a little premature on getting to that point. We'll give you hopefully guidance, when we report full year earnings at the end of February. But clearly what I was trying to indicate in my prepared remarks, that you lose that revenue source and so there might be a little upward pressure at the holding company.

And then, secondly, I think you said you booked the impact of the GRC PD through the first three quarters. Is the fourth quarter impact just negative, because it's lower revenue requirement or is there something else I need to think about?

I'm looking over my accountants that booked the first three quarters. Anything else in the fourth quarter that would be relevant to what Jonathan's brought up?

We'll continue to follow the proposed decision, until we get a final decision. And then we'll look at what the terms are and adjust to the final decision.

So the guidance, obviously, Jonathan is adjusted to reflect what we think, based on the proposed decision the fourth quarter will be.

And I guess, just finally, then should we read into the fact that your booking earnings according to the PD, apart from the tax adjustment item is that your best estimate of whether it shakes out, on your own accounting basis currently that you likely don't improve too much on the PD, but you do when this one issue. Is that how we should think about you giving guidance that way?

I think our view was, we felt it was important to get something out there as a stakeholder, because there is going to be -- if you wait until you get a final decision, it's really not clear that what it's going to be and we wouldn't get yearend earnings out until February. We felt that it was better for investors, as Ted said in his prepared remarks, to give some clarity. And I think we gave through our guidance, you'll have enough pieces of information to make adjustments accordingly. And so we felt that was the clearest and fairest way for everybody to do this.

And then just one other topic. Ted, I think you made the comment that you expect to; no, you hope to have the SONGS issues result this year or at worst early next. I just want to be clear that you are talking about the overall issue, including the settlement, not just the penalty piece when you make that comment?

Yes.

Our next question is from Michael Lapides with Goldman Sachs.

I was just curious, when I look at the data on Page 15 in the 10-Q and kind of the new band for CapEx, and that you've disclosed on the slides. How should we think about how this impacts the timeline to get to a higher payout ratio? And CapEx coming down frees up some cash for the balance sheet in the cash flow statement, by the time you get out to about 2018, 2019 timeframe, you'll have a higher earnings power, you'll have higher cash from operations and at lower CapEx level. Just curious about how you and the Board are thinking about kind of the timeline and the pace prior to get up for the dividend, prior to getting the proposed decision versus going forward?

Yes. It's a good question. I guess I would try to respond to it this way. If you kind of pull up from looking at one year versus the next year, any individual year, with just kind of the larger theme, the larger trends, as you know I tried to strike this theme consistently, we expect somewhere in this $4 billion-plus kind of annual CapEx. We expect pretty significant rate base growth. And we expect that as the base gets larger, as the rate base gets larger, we're going to have more cash flow. So we feel that we're going keep a good balance between solid annual CapEx and related earnings from a growing rate base, but cash to move us back in that 45% to 55%. Any given year, any couple of years, you might run a little harder on CapEx, you might run a little slower on CapEx that may give you on the margin a little more room to move on dividends or slow it down a little bit. But fundamentally, I think rather than try to pick it apart year-by-year that's the teeter totter. It's keeping CapEx in that kind of $4-plus billion range and getting back solidly. I think I use the term well within the range of 45% to 55%. So I wouldn't get too wrapped up on any one year movement. Both of those things are going to be really what we're focused on. And we believe as a result, we'll be able to provide investors with a higher than industry average growth rate in earnings and a higher than industry average growth rate in dividends.

Our next question is from Ali Agha with SunTrust.

Jim, just to be clear on Slide 9, where you've laid out your rate base numbers, new ones '15 through '17. Just to understand the moving parts there once the GRC is finalized, if I am hearing you right, you've already assumed the big tax benefit and $180 million, I believe goes in your favor, if I heard you right. And so if there is going to be any change to these numbers, it's probably to the downside if they stick with the PD or is that further upside that maybe I'm missing here?

So what I said was the $180 million, the customer deposits, is already baked into these numbers. This is net of that. And what also, I said, and I think we have it here on the first pull it on the right, the $344 million rate base reduction for the repair deduction is not included in these numbers, is not. And so to the extent, if the commission were to decide to adopt it, then you need to reduce these numbers by the $344 million.

But also, if they stick with the PD on the customer deposit, that would be another $180 million reduction?

No. I'm sorry. We incorporated the $180 million already.

Are you stuck with the PD on the $180 million?

Yes. So the only things that we haven't adopted from the PD are the tax issue, the $344 million rate base reduction. And the second thing is the SunPower termination payment for the solar panels. Those are the only two items we have not incorporated.

And then secondly on the SONGS process, just to be clear on resolutions, so the PD came out on the ex parte issue and may come up on the December meeting. Should we now expect another PD has to be issued on the petition for modification, and then at some later date that gets picked up by the CPUC or what is exactly the process for dealing with those modification petitions?

Adam, you want to take that?

Sure. And you're right. There are separate petitions for modifications and a request for rehearing, all of which are pending, and for which there has been no decision by the commission. I really can't tell you when to expect a decision. As Ted pointed out, we're hopeful that we'll see a decision later this year or early next year. Once that decision comes out, there will be an opportunity for parties to comment before it is final.

But to be clear, Adam, you need to first have a PD, which will set a 30-day clock on those issues?

Yes, on the petitions for modification, that's right, there will be a PD, a comment period and then a final decision.

Our next question is from Greg Oro with Barclays.

Back to Page 12, just regarding the AFUDC at $0.07 that it is added back, is that a good number going forward, just as an average, is there a timing issue in there, or maybe I need more of a discussion what that is?

Well, we're happy to have a further discussion, but there is a lot of moving parts associated with AFUDC. Historically, the way we've done this over the last several years, we assume that AFUDC earnings offset all the cost that aren't not recovered through the rate making process. There is executive compensation Board related cost, our corporate dues and philanthropy activities. There is a whole bucket of that costs that aren't recovered and we have assumed historically that AFUDC earnings offset those. And what can cause it to go up or down is the balance of what's in the account or the rate. So the rate can go up and down depending upon what's happening at any point in time. So I think for planning purposes, it's probably appropriate to assume that AFUDC will not come out again in the future in terms of providing the benefit and go back to that rate base approach as the core utility source of earnings and a little bit of energy efficiency that we've talked about repeatedly adjusted for the holding company cost to get you to a decent starting point.

Our last question is from Praful Mehta with Citigroup.

So I'll be quick, given it's a long call and the last question. So just quickly on the rate base that you've guided to now, if we had to bridge from the last quarter to this quarter in terms of rate base, is it just the CapEx and these GRC adjustments that you've talked about or is there other stuff that we should be thinking about in terms of reaching from last quarter to this quarter rate base?

So the two principal items are the GRC adjustments and the FERC delays. And you can see the dollar amounts of the FERC delays that's shown on Page 9 -- I'm sorry, Page 8, it has both rate base and capital expenditures and the balance is what the commission did not pick up as part of the rate making process. Scott anything else fits in there?

And probably just remember, as Jim said in his remarks, so the FERC spending is being pushed out, so you would model it later. After the current forecast period, you see it picking up in 2018 and beyond.

And just quickly the final question was on that point itself, which is, you talk about the long-term $4 billion annually. When you say long-term, how long is long-term when you think of it is? Is it a three-year window, five year window, just so we have a sense of what is it?

I don't want to be flip and say it is Wall Street long-term. But, I think it is appropriate to think through the 18 generate case cycle.

That was the last question. I will now turn the call back to the Mr. Cunningham. End of Q&A

Thanks, very much, everyone, for participating and don't hesitate to call us if you have any follow-up questions. Thanks and good afternoon.