愛迪生國際 (EIX) 2014 Q2 法說會逐字稿

Good afternoon, and welcome to the Edison International second-quarter 2014 financial teleconference. My name is Brian and I'll be the operator today. (Operator Instructions). Today's call is being recorded.

I would now like to turn the call over to Mr. Scott Cunningham, Vice President of Investor Relations. Thank you, you may begin.

Thanks, Brian, 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 with us 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. After the call, we will be posting Ted's and Jim's prepared remarks. Tomorrow, we will file and distribute our regular business update presentation, which has additional information on current topics.

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 reconciliation 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 will turn the call over to Ted Craver.

Thanks, Scott, and good afternoon, everyone. Before we begin the call, I'd like to welcome Maria Rigatti, who joined us this week as Senior Vice President and Chief Financial Officer of Southern California Edison. Many of you know Maria from her prior role as Chief Financial Officer of Edison Mission Energy. We are pleased to have Maria's depth of experience and leadership. I'd also like to welcome Connie Erickson to her first earnings call. Connie is Southern California Edison's new Controller, and joined us in May from a utility in the Southeast.

Okay, so let's go ahead and get down to the business at hand. Edison International today reported second-quarter core earnings per share of $1.08. This is a 37% increase over core earnings per share in last year's second quarter. This strong performance reflects continued earnings growth from investing and modernizing and expanding our core wires infrastructure, managing our costs, and benefiting from favorable tax items. Based on our year-to-date result, we expect full-year earnings for EIX to be well above the high end of our core earnings guidance range, that is, above $3.80 core earnings per share.

There are several components driving this expectation, which Jim will discuss in his remarks. Obviously, this effectively moots our current earnings guidance. We're not providing new earnings guidance at this time. We want to at least get through the summer, since our earnings are weighted most heavily to the third quarter, and may provide new guidance when we release third-quarter earnings.

Of course, we are also focused on completing the remaining steps for getting the SONGS OII settlement approved. The record of the proceeding is now complete. We are currently awaiting a Proposed Decision from the Administrative Law Judge. As we previously reported, the settlement has a diverse group of signatories representing all the major groups of intervenors in the SONGS OII proceeding: that is utilities, consumer groups, labor, and environmentalists.

Beyond the direct signatories, several other groups express support for the settlement and testimony, with relatively little opposition. The next step is to receive a Proposed Decision from the ALJ, which we hope to see shortly. We are also moving ahead on the decommissioning planning process. SCE anticipates filing an initial decommissioning plan with the Nuclear Regulatory Commission later this year, outlining the scope, schedule, and budget for decommissioning.

Based on our recently completed site-specific study, we now forecast SCE's share of SONGS decommissioning costs to be $3.3 billion in 2014 dollars. When we take that number and escalate costs over the decommissioning period and then present-value it, SCE's share of cost is $2.9 billion. On the other side of the equation, the current market value of SCE's decommissioning trust funds for SONGS Unit 2 and 3 total $3.1 billion after estimated taxes as of June 30, 2014.

So the bottom line is that we have $2.9 billion in present value cost versus $3.1 billion in present value of the trust funds, which leads us to conclude that San Onofre decommissioning is now fully funded, and future contributions are not needed. We are awaiting approval from the PUC to use decommissioning trust monies to pay for the early decommissioning planning work we have been doing, as well as ongoing operating costs since the plant was shut down in June of last year.

On a related item, on May 1, the CPUC approved SCE's 2014 forecast for fuel and purchased power, or what we call the ERRA account. SCE incorporated this decision in customer rates in June. SCE also filed its 2015 ERRA forecast application in June. These are important steps in reducing the under-collection in the ERRA account.

Turning to the General Rate Case, we made our supplemental filing on safety and reliability risk, as required by the assigned commissioner ruling. The Administrative Law Judge issued a revised GRC schedule for testimony, hearings, and briefs. Hearings begin in late September, representing approximately a two-month delay. The schedule does not have a target date for a proposed decision, but it clearly will not be issued until sometime into 2015.

The Commission has already approved making the final GRC decision, whenever that may occur, retroactive in rates to January 1 of next year. While we have to accept the realities of this delay, we continue to support the separate efforts Commissioner Picker is leading to streamline decision processes at the Commission, which is needed.

The last regulatory topic I want to touch on is rate design. We and the other investor-owned utilities continue to work with the CPUC on their efforts to implement the constructive changes in residential rate design authorized under Assembly Bill 327, signed into law last October. We are well into the procedural schedule for the phase dealing with fixed charges and compressing rate tiers to bring the rate structure closer to true costs. A decision on this is scheduled in the spring of next year.

On July 10, the CPUC established a separate docket and approved the procedural schedule for the last phase. This phase includes creating a new net energy metering tariff to better reflect the cost effects of net metered, customer-installed solar on the system. This is to be finalized by the fall of next year.

I'll close with a few comments on our longer-term growth potential and dividend policy. As I've met with investors over the past few months, I've made clear that we see sustained growth opportunities at SCE, even beyond the current 2015 to 2017 forecast period. On our last earnings call, I talked about the need for annual capital expenditures and electric infrastructure at similar levels to those proposed in the current rate case.

We continue to believe that for the foreseeable future the electric grid is critical to facilitating public policy goals, including those to reduce greenhouse gases. That said, the distribution grid needs additional capital expenditure to support two-way flows of electricity created by distribution, distributed generation, as well as new technologies such as electric vehicles and energy storage. This is, by far, the largest additional future investment in the grid not currently contemplated by the General Rate Case process.

We will submit our Distribution Resource Plan outlining these investments in 2015, as required by Assembly Bill 327. We have three large transmission projects that are part of the approved California ISO transmission plant that are expected to go into service between 2018 and 2020. We are also interested in the Delaney-Colorado River transmission project, which was recently approved by the California ISO as an economic, and, therefore, a competitive project. We feel our competitive position is enhanced from SCE owning an existing corridor.

Together with electric vehicle infrastructure and energy storage, all these potential projects will complement SCE's continued focus on growth in electric infrastructure investment. We are not prepared at this time to attach specific numbers to these categories, but we believe it is important for investors to understand why we are bullish about our long-term growth opportunities for some time to come. And importantly, none of this growth relies on additional investments in new generation.

Regarding our dividend policy, we fully recognize that our dividend is well below the industry. I have reiterated several times in these calls that we intend to address this situation by taking more meaningful steps in returning our dividend to our target payout ratio of 45% to 55% of SCE's earnings, in steps over time. I consider delivering on this as job number one for our investors, just as delivering on providing on safe, reliable, and affordable electric service is job number one for our customers.

With that, I will now turn the call over to Jim Scilacci.

Thanks, Ted, and good afternoon everyone. I'd like to add my congratulations to Maria and Connie on their new roles, too. I would also like to thank Stu Hemphill for being the acting CFO, bridging the time period between Linda Sullivan's departure and Maria's arrival. Thanks a lot, Stu.

My comments will cover the following topics: second-quarter earnings, capital spending and rate base forecast, the regulatory calendar, and earnings guidance.

Please turn to page 3 of the presentation. As Ted already mentioned, EIX's core earnings for the second quarter of 2014 are $1.08 per share, or $0.29 ahead of last year. Higher revenues include $0.17 per share in authorized CPUC and FERC revenue increases that support rate base growth as well as higher costs. $0.03 of this increase is from a revision to estimated revenue under the FERC formula rate mechanism, and the 2008 FERC construction work-in-process proceeding. These $0.03 were not included in our original guidance.

The net SONGS impact is a positive $0.03 per share compared to last year, mainly related to severance costs that impacted earnings in the second quarter of last year, and a small property tax refund this quarter. O&M costs increased $0.02 per share, and include $0.01 non-SONGS severance compared to $0.02 in the second quarter of last year. Most of this O&M variance is timing-related. Higher depreciation and financing costs reflect the growth in rate base, and the capital structure supporting that rate base.

Income tax benefits are a significant contributor to earnings during the quarter. We recorded a $0.09 per share tax benefit from changes in estimates of the uncertain tax positions. This primarily relates to progress made by the Company in the IRS appeals in settling the 2003 through 2006 audit cycle. This also had a spillover effect in subsequent years. This $0.09 benefit was not included in our 2014 earnings guidance.

In our original guidance, we assumed that full-year tax benefits would amount to $0.14 per share. Through June 30, we are $0.08 of additional tax benefits that were not included in our original guidance, mainly related to higher repairs and cost removal deductions.

Also included in other income are $0.03 for California energy crisis litigation settlements with generators that were finalized this quarter. You may recall that we have a CPUC-approved incentive-sharing mechanism for resolution of these claims. Taken together, this accounts for the $0.27 increase in SEC's core earnings, as shown in the slide.

For the Edison International holding company, costs are $0.02 per share lower than last year, largely due to consolidated state tax, income tax benefits this year. Included in discontinued operations and non-core earnings is a $0.56 per share benefit related to the EME settlement. The settlement and the sale of EME assets closed on April 1, as previously disclosed, and was accounted for as a second-quarter transaction. The amount recorded in discontinued operations for the second quarter was $184 million, slightly higher than our prior estimate of $152 million. We expect to finalize the EME tax attributes and the amount of EME payments by the end of this year.

In addition to our earnings discussion, let me summarize a couple items that impacted EIX's liquidity in the quarter. First, Edison International made the first payment of $225 million to the EME creditors in April, drawing from its credit line, as we planned. Second, Edison international made deposits with the IRS of $189 million, related to federal income tax disputes related to EME. You may recall that EIX agreed to accept this liability as part of the EME bankruptcy settlement.

These items, together with timing differences between the dividend received from SCE and paid to the common shareholders, increased EIX's short-term borrowings to $666 million on June 30. Also during the quarter, both SCE and EIX extended their credit facilities for an additional year, through July 2019. There were no changes to terms and conditions.

Page 4 of the presentation has the year-to-date financial story, which I won't review, but the earnings analysis is consistent with the second-quarter story.

Turning to page 5, SCE's capital spending forecasts through 2017 continues to be the same. For the first six months of the year, total SCE capital expenditures are $1.6 billion compared to our full-year forecast of $3.6 billion to $4.1 billion.

On page 6 of the presentation, we continue to forecast compound annual growth rates of 7% to 9% for a rate base through 2017.

Page 7 highlights the points on longer-term growth drivers that Ted mentioned in his comments.

Turning to page 8, based on investor feedback, we have reintroduced a key regulatory calendar that we will update quarterly with the most important proceedings impacting the utility. More detailed slides on each of the topics, and appropriate updates, are included in the appendix.

The final topic is guidance. Please turn to page 9. Ted has already updated you on our plans for guidance. We have added into the chart a total of $0.23 per share of core items not included in original guidance. To recap, they are the $0.09 of income tax benefits from uncertain tax positions; $0.08 of additional tax benefits -- repairs and cost of removal; $0.03 from additional FERC revenue; and $0.03 from generator refunds.

I'll finish with slide 10, which we continue to use to frame the investment story for Edison International. We are looking to close the final chapters on the SONGS regulatory review, and the last steps in implementing the EME bankruptcy in the coming months. As we've noted at the lower left of the slide, being able to monetize EME tax benefits is dependent on federal income tax policy.

We're aware of the potential for extension of bonus depreciation. On balance, we would see such an extension as net positive for Edison International, with important cash flow benefits from lower cash taxes at SCE, although it would admittedly delay monetization of EME tax benefits. Our strategy remains focused on reducing uncertainties, delivering on the current and longer-term earnings in dividend growth opportunities as we see, and positioning the Company for transformative change that we are seeing unfold around us.

Thank you. And now I'll turn the call over to the operator to moderate the Q&A.

(Operator Instructions). Dan Eggers, Credit Suisse.

Jim, on slide 9, can you just re-run through those numbers of all the additional benefits that weren't in the original guidance, just to make sure -- they went pretty fast -- to make sure I have the right accounting for them?

Okay. Four items: $0.09 for uncertain tax positions, release of reserves; $0.08 of additional repair and cost of removal deductions; $0.03 for generator refunds; and $0.03 for FERC revenue, additional FERC revenue.

Okay, and then (multiple speakers). And then the -- and are those the core pieces that are going to get you well above the high end of the range? Or are there other things you are seeing in addition to those that would be additive to those expectations?

Those are the core things.

Okay. And then when we think about with the GRC coming through, the upside or the benefit from the taxes and the cost savings that are adding this year, we should calibrate those back because those are unique to this period and not to the next GRC period, is that still correct?

Yes.

Okay. What tax rate should we be assuming beyond this year?

Well, that's a good question. Tell me what's going to happen with tax policy. That's the real hard one to pin down. So we still are carrying some NOLs. So even if they didn't extend bonus depreciation, there could be an impact in future years. But we haven't put a forecast out. We don't forecast tax policy or tax rates. So it's going to be somewhere between the maximum rate and slightly lower, if they don't extend bonus. And I can't tell you where it will go if they do extend bonus.

Okay. And I guess one last question. Sorry, I didn't mean to rapid-fire all those, but just one last question.

Yes, go ahead.

Pinnacle raised today the idea of -- or talked about on their call today -- utility-owned rooftop solar as a way of trying to allocate or get that resource into the hands of people who probably couldn't otherwise afford it, or couldn't qualify for it. Is that an opportunity you would see working in California to try and bridge the gap as to where some of the disproportionate subsidies or benefits are going within the California rate design system?

There are a number of things we are considering. I think Ted's comments touched on some of the things that we are important -- we are thinking about from an investment perspective. And our principal focus is looking at the grid, and how we can better make investments around the grid to allow greater penetrations of distributed generation. And we think there are meaningful investments that could be made to support more distributed generations.

I'll pause there and look at Ted. Or Ron, did you want to add on to that?

Yes, maybe just a little bit on it, Dan. I think really our focus has been primarily on the wire side, as opposed to the generation side. We have, in SCE, something like 90 megawatts of rooftop solar already, something like 35 different commercial roofs. But we have not really been adding to that portfolio. Frankly, it's a good, competitive environment. There are plenty of opportunities for lots of third parties to engage in this. Most of the time, they can do it more efficiently than we can in the utility.

And where we have, I think, a unique contribution to make is in facilitating all of these technologies -- whether it's rooftop solar, whether it's potential electrification of transportation, energy storage, et cetera. Really all of that fundamentally relies on the distribution system in particular to really work effectively and efficiently. We are uniquely positioned to provide that investment. That's where we're focused.

So I don't think you'll see us rush to get into the generation side of this, within the utility, so much as you'll really see the utility focus its investment on the wire side.

Very good, thank you.

Yes, and just one last thing, too. Of course, we have a small investment in a company by the name of SoCore that focuses on commercial and industrial customers. We have avoided the residential side because the commercial industrial area, we think, is more economic, and there's a lot of potential there. Operator?

Julien Dumoulin-Smith, UBS.

Sorry to nitpick a little bit further; could you elaborate a little bit, with regard to whether the FERC side of the equation there could persist, when you call it out in that $0.23 -- so, specifically, the FERC revenue of $0.03?

When you say persists --?

Is it strictly a one-time item here, or should we think about this as continuing on for a certain period of time?

Yes, it's more one-time, Julien. What we're doing is updating our formula rate for actuals. And for the 2008, we're seeing around our construction work-in-process proceeding; that case was ongoing for a long time, and it was resolved. So it's mostly one-time.

Got you. And then when it comes to the energy settlements, obviously these things come in -- are somewhat lumpy. Are there others that are pending to be settled at one go, here? Is there anything else on that front we should be expecting?

There's not much left on the energy settlement side. We've been litigating those for over 10 years, so we're getting to the end of those.

Got you. So ultimately, if you could summarize -- and I don't want to put words in your mouth, so I will let you talk -- how would you think about the guidance in the context of year-to-date earnings, just to be clear? If you can provide any comment -- is it as simple as saying, well, $0.23 on top of your guidance year-to-date? Does that begin to approximate how you would think about it?

Well, I think I'll go back to the statement we used. And I don't want to go beyond that, or try to expand. So we see earnings being well above the high end of the range, and the $0.23 we tried to list for you that occurred in the first half alone. And we projected other tax benefits and O&M savings to occur during the course of the year, the balance of the year. So that's -- by putting all these factors together, we see it well above.

Excellent. Moving on to more substantive issues, when it comes to the ROE, I'd be curious, how are you thinking about positioning yourself within the context of your future ROE case at FERC, given the New England case and the resolution we recently got -- or at least the clarity we've gotten?

Well, we got some clarity. Again, we have a settlement in place until mid-2015, under the settlement we entered into over a year ago. And at that point in time, later next year, we'll take a look at it, run all the models, and see what they yield; and take into consideration what the FERC has provided, as in terms of its recent guidance. And we'll have to see if that implies an upward bias.

It's going to come down to interest rates, and where dividend growth rates are, in terms of using the FERC model and cranking it through. So there potentially could be some upside there, but you have to moderate it because it's really only 20% of our total rate base. It's the CPUC side that really drives things overall.

Right, absolutely. Thank you.

Gregg Orrill, Barclays.

Two quick ones. First, a point of clarification on whether this year you've pulled forward any benefits of repair tax accounting, or maybe if you can provide an update on what you are looking for in 2015 there. And then at this point on the SONGS OII, are you still working to bring any more parties on board? Or do you see any gaps in groups on the settlement?

Well, why don't we handle that in reverse order? Ted?

Yes, just on the second one. All the intervenors who are going to provide testimony have done so, and that was really what I was capturing there. In terms of the direct signatories, it's the two utilities, the labor group [queue], ORA, TURN, and Friends of the Earth. So those were the direct signatories, representing all four of the main intervener groups. In the testimony, several other groups -- mostly consumer, various forms of consumer-related groups -- also provided positive, supportive testimony of the settlement.

And, as I indicated in my comments, really relatively few came forward with any opposition to the settlement. So, I think basically everyone who has standing that wants to speak, has spoken. And at this point, really all that part is over with. We're really at the stage of waiting for the ALJ Proposed Decision.

Okay, great. Let me cover the first part of it. I think it is the tax benefits you were referring to, and what potential tax benefits that could be going forward into 2015. And as we've said all along, we'll update, with our GRC filing, all the numbers. And we would expect the benefits that we are receiving currently -- the $0.14 referred to before -- would go away, and that's incorporated in our rates starting in 2015.

But what we're trying to point out here in 2014, the $0.09 a share, that's a release of reserves related to our 2003 to 2006 audit cycle. We took essentially the hit in the past; and now, because of the way the negotiations are coming out, we can release those reserves and have benefits earnings.

And I also said, the second item -- remember we said there would be $0.14 in total for the year when we started the year. What I said in my comments, there was an additional $0.08, over and above the $0.14, of additional repair and cost of removal deductions.

So I think that's the full lineup of tax benefits that we see, as of the $0.14 for the full year, and through the first six months of the year.

Thanks.

Kit Konolige, BGC.

Ted, maybe just to focus a little bit on grid readiness, which I think you've described as the biggest single item. I know you don't want to put a number on that, but maybe you can give us a little more color on what you see as likely to be involved here. You've certainly talked about the two-way flows that would be demanded by distributed generation in particular in the past. But now that you are going to have to be presenting a specific plan, maybe you can give us some detail about what would be involved here from the utility's viewpoint.

Yes, I'll make maybe a couple of overarching points, and then I'll give it to Ron, who is really much more directly involved in this part. I'll do it in terms of the buckets. I think there are a number of things on the, as you termed it, grid readiness side. I think of it as modernizing and expanding the grid system; focusing primarily on the distribution system, to make it more flexible and resilient and responsive.

And so, some of that gets into the stuff that you mentioned -- the two-way flows of electricity, today is pretty much designed to handle one-way flows. But the more the new technologies get introduced -- whether that's distributed generation, or storage, or some of the things around electric transportation -- the more that distribution system needs to be flexible and responsive. One of the phrases we've used, it's essentially creating a network system -- a plug-and-play system, if you will -- that can handle a lot of those new technologies and still remain reliable.

The second really big bucket I think is on the transmission side. And there are number of things that we're looking at, both within the utility as well as potentially outside the utility in competitive transmission work, that we see a lot of opportunities, particularly in the West on those activities. So those are probably two of the larger ones.

Beyond that, it's some of the unregulated business. And that's where -- as we refer to it, it's energy services focused on the commercial and industrial customers, which we see as the most price-sensitive; as well as having a large enough energy footprint that a lot of these things will be economic, even without subsidies. Whereas on the residential side, I think continued subsidies will be required to really make those alternatives competitive with the grid. So those are the big buckets.

Ron can cover more on the grid readiness part.

The particulars on grid readiness really comes down to the control systems and the protection systems on the distribution grid. We're going to have to put in much more sophisticated, more dynamic voltage controls. For years, we got away with capacitors that just switched twice per day -- once on-peak and off-peak. We're going to have to put in more sophisticated voltage controls to deal with a lot more voltage fluctuation. As we get into two-way flows, we're going to have to go with much more sophisticated relaying and protection systems that can detect both the distance and the direction of the fault, similar to what we have on the transmission grid.

And then once all that's in place, as Ted mentioned, we can loop many more distribution circuits together and operate it more like a network, which would actually improve reliability. So it's primarily a controls game. What I just described for you was essentially our plans around our urban circuits, which are already suited for this, from the physical infrastructure itself. When you get out to our rural circuits, though, however, we probably are going to have to upgrade some conductor sizes as well.

Okay. And just so I understood it correctly, did I hear you say before that this bucket, this grid readiness area, is the biggest single prospect for growth beyond 2017? Or am I misunderstanding that?

No, that's correct.

Thank you.

Michael Lapides, Goldman Sachs.

Just thinking about the bridge for the next couple of years, am I right to think a little bit that if you just do rate base math on 2015 -- because you are having a great 2014, in a little bit of an unusual 2014 -- that 2015 is kind of a down year before growth reaccelerates in 2016?

Yes, Michael, it's Jim. I think that you're right. We're guiding people to go back to the simplified model starting in 2015, because of the way the regulatory mechanisms work here. We pass back to the ratepayer the O&M savings that we talked about, the $0.35 that are embedded in our guidance, and the tax benefits. Those all go back. And then we're back to the normal -- if you take the rate base, and times the return on common equity, times the 48% common equity ratio, and you're going to get to earnings pretty fast.

Now, there could be some volatility around that to a certain degree, because we'll continue to focus on operational and service excellence. And there's the potential for additional savings, but we're not going to forecast anything here. But we will continue to look for things to optimize around our costs.

Got it. And I want to just focus on the balance sheet a little bit. You talked a little bit about having ramped up short-term debt at the parent. Can you give us some of the puts and takes? Meaning when and how much cash flow do you expect to get this year and next year, related to the ERRA? What are your plans in terms of short-term debt at the parent? Just high-level movers outside of CapEx, and some of the tax issues you've already talked about; and, obviously, net income and D&A.

Now, that's up broad question, so let me just pick at it; then we'll let others chime in. At the utility, in terms of ERRA, we said they were at $1.6 billion, and we had the big rate increase that went in just --.

June 1?

June 1. And we have generator refunds. There's $200 million that will be applied against the $1.6 billion. And as rates have now gone up, we'll start to amortize that down. An important element in terms of where we get at the end of the year is the SONGS settlement. There's a large refund that will come out of there. And there's an advice filing pending before the Nuclear Decommissioning, and if they allow us to go into the decommissioning trust, that balance then will be refunded into the ERRA account.

So, where it ends up? I would say, right now, if they do approve the SONGS settlement and the advice filing, we will be materially reduced from where we are today. There still could be a balance, and that will pick up -- in 2014, will be materially reduced -- and that balance, if any, will be picked up in the 2015 ERRA proceeding, and amortized down if there's anything remaining.

So, any other short-term borrowings -- there's actually fairly small amounts of borrowings at the utility right now. We'll use that as a surge if we have capital requirements or other things, but historically we've kept the balances low. And it will just depend on capital expenditures going forward.

Moving upstairs to the holding company, we said we're up to $660 million of short-term borrowings, and we did that because we made the first payment when we did the tax deposit. And we have additional payments in 2015 and 2016 for the EME settlement. It really is going to come down to what's going to happen with tax policy, which is going to affect the utility, too, obviously, because that will be a source of cash, and there will be less monetization of tax benefits at the holding company if we do see that.

And it would just defer monetization for a period of time. Once you would expect we will get the on bonus depreciation, and the whole EME settlement is designed that it pays off the costs we've incurred in payments to the bondholders, and for the tax payments we took on our side and some of the employee benefits -- it ultimately is a net positive at Edison International.

How all this unfolds is hard to tell at this point in time. And we'll just have to see what tax policy is, especially at the end of the year.

Got it. Thank you, Jim. Just one final question. When you think about -- yes. Ted, you talked a little bit about the dividend policy, and that you may have CapEx levels over time -- meaning after this GRC -- that remain in the elevated range that you had now, and that you expect for the next year or so. But what also should happen is net income should grow, obviously, and D&A should grow as assets go into service. So you wind up with a larger base of cash flow to start from. And CapEx, while remaining elevated, is smaller each year as a percent of the total Company. Does that not give you a little more confidence in the ability to move towards a higher payout ratio?

Yes, definitely. And that's -- I'm kind of running out of new ways to say it. (laughter) But I introduced one new one this time, that job number one is delivering on getting our payout ratio back into the targeted 45% to 55% of SCE's earnings. And that's probably about as close as I can get to saying, everything you just outlined is exactly right; that we see increased capacity to move the dividend along at a higher growth rate than, certainly, what we've been doing in the past. And we have to do that; it has to grow faster than earnings in order to get back into that 45% to 55% payout ratio.

People have been -- investors have been patient. We are aware that. We are appreciative of that. And we think we're getting to that spot now, where it's time to deliver on getting our payout ratio back where it belongs.

Got it. Thanks, Ted. Much appreciated.

Paul Patterson, Glenrock Associates.

A lot of my questions have been answered. Just on the competitive transmission opportunity that you were talking about, and the benefit of having the transmission corridor -- could you give us a flavor, or sort of -- how substantial that advantage is, in terms of cost or timing of whatever the sort -- I mean, whatever you can tell us?

So what you are referring to, just for clarification, is the Delaney-Colorado River transmission line. And remember, going back, and you've followed us long enough, there's already a transmission line that goes through that corridor. That's Devers-Palo Verde transmission line number one. And we tried to do Devers-Palo Verde transmission line number two, and Ron Litzinger can tell you all about how fun that was. And we built up to the Colorado River, and we stopped there. Now it's the adjoining piece that goes out through Arizona.

So I will pause there, and let Ron give some more of the details.

Yes, so we continue to have the entirety of the right-of-way, and we see that as a competitive advantage. And now that it's a competitive game, we've got to seek to maximize that and whatever others we can find.

I just was wondering if there was -- if you had -- in terms of the competitive outlook, is there a value that you can ascribe to that, in terms of how much money that saves you, vis-a-vis other competitive alternatives?

Just what we know historically: getting this route and what the alternatives are. But we're not putting a dollar figure on that.

Yes, Paul, just logically, just thinking out the top of our heads -- if you have a right-of-way that already exists, you know how difficult it is to secure a right-of-way, and going through all the combination process and getting all the approvals that you need. It is not easy to do that. We've got a lot of transmission construction going on, and it's one of the most challenging things for us to do. So that's why I think it's important.

Okay, I just was wondering if there was a -- I mean if there was -- if you could quantify it, but I understand if you don't want to do that.

And then just in terms of financing and what have you, one wonders whether or not infrastructure funds or something might be involved in some of the activity. Do you guys think that there would be -- with these competitive -- these transmission lines for competitive bid -- whether there'd be a change in the capital structure or leverage that might be employed to develop these things? Or do you see it pretty much the same as other transmission investments that you've made?

No, I can't foresee it at this point in time. It would be similar to what the CPUC capital structure would be.

Okay. Thanks so much.

Ali Agha, SunTrust.

Ted, as you alluded to, given the schedule that the GRC is moving under, it's likely to spill into next year. Now, normally, you make your dividend decisions in December. Is it fair to assume that you'd want the GRC behind you before getting aggressive on the dividend -- I guess, point A? And related to that, is there anything to move you from that December timeline? Is that just consistency, or how are you thinking about these issues?

I think you've outlined, certainly, some of the considerations that will go into figuring out where we go from here. But I'm really not prepared at this point to speculate a lot on timing or amount. I've done everything I can to make clear that this is a top priority for us. And we just have to assess the situation as it presents itself, and make the best decision that we can, and then explain our decision to investors.

Okay, we'll keep an eye on that. Jim, can you let us know from the way the regulatory accounting math works, what is the equity ratio at SCE right now? And I know you guys have been very clear that through the 2017 period, you don't need equity. But listening to your CapEx plans beyond that, when at the earliest do you think equity does come into the equation, if at all, for the Company?

Question one: 48.5 at June 30. Question two: we have no plans for equity.

Not just still 2017; it could be well beyond that as well.

Just no plans.

Okay, thank you.

Ashar Khan, Visium.

My question has been answered. Thank you so much.

Neel Mitra, Tudor, Pickering.

I had a question on slide 7, with the infrastructure liability investment past 2017. What's the pace of the drop-off? Obviously, that's the big rate base growth for you guys through 2017. Can you give us maybe the trajectory for it past 2017, and what the drivers are really for rate base growth?

Well, I'll start. Again, we don't have any projections out there, and I think Ted made some comments that were very clear around this -- that our distribution spending, we don't see it drop off. There are certain components that we need to step up the level of replacements to get to the level that we think is appropriate so we don't have reliability concerns.

What could cause our capital spending to go up or down were some of these other things that you see on page 7; that would be transmission expenditures, the grid readiness. Right now, that's not in anything we've shown the Commission. Ted indicated that we will make a filing next year that will detail some of those expenditures. So, drop-off, I don't think would be the appropriate word. I think in our investor materials we've said it's plateaued, and it will go up or down depending upon what happens with some of these other things.

Okay. So, capital spending for the wires business will substantially outpace depreciation for past 2017, in your view? (multiple speakers)

Oh, well past 2017.

Okay, great. Thank you.

Travis Miller, Morningstar.

Quick question. On the decommissioning fund, do you intend to turn that over to a third party ultimately, or manage that yourself in terms of the decommission activities?

Right now, we have managed that as the principal owner. That's obviously an option. We've seen others in the industry have done that, but I won't speculate if we would go down that path.

Okay. And then other topic, those $0.23 of earnings -- how much of that was cash that you are realizing, above and beyond the guidance?

That's a good question. So, the generator refunds were certainly cash. FERC revenues certainly will be cash. Tax benefits, the $0.08, it's definitely cash.

Eventually.

Eventually, as it comes around. And I don't know on the $0.09, because you are releasing reserves, and so that's an earnings benefit and not a cash benefit.

Okay. Great, thanks a lot. Appreciate it.

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