Edison International (EIX) Q3 2013 Earnings Report, Transcript and Summary

Good afternoon. My name is Angela, and I will be your conference operator today. At this time, I would like to welcome everyone to the Edison International Third Quarter 2013 Financial Teleconference. [Operator Instructions] Today's call is being recorded. I would now like to turn over the call to Mr. Scott Cunningham, Vice President of Investor Relations. Thank you. Mr. Cunningham, you may begin your conference.

Thanks, Angela, 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. We will be using the presentation in a more complete business update that will be posted tomorrow on our website. 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 substantially 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. [Operator Instructions] With that, I'll turn the call over to Ted Craver.

Thanks, Scott, and good afternoon, everyone. Today, Edison International reported solid third quarter core earnings of $1.42 per share, up from $1 per share last year. Keep in mind that year-over-year quarterly comparisons are somewhat skewed, principally because of the delay in receiving the General Rate Case decision from the CPUC, which dampened earnings last year. That said, third quarter core earnings for this year reflect the benefits of our continued cost management efforts and favorable tax benefits not anticipated in our original earnings guidance. Importantly, we are raising Edison International's 2013 core earnings guidance to $3.60 to $3.70 per share. This replaces our previous guidance of $3.25 to $3.45 per share. Jim will comment more fully on the quarter-over-quarter differences and guidance changes. As I have said in previous earnings calls, creating long-term value at Edison International involves 3 major efforts: Resolving uncertainties relating to our San Onofre nuclear plant and Edison Mission energy; growing our earnings and dividends; and preparing for transformative change in our industry. I will comment on each of these in the remainder of my remarks. In September, the Nuclear Regulatory Commission, or NRC, finalized its inspection report, which evaluated SCE's response to the NRC's Confirmatory Action Letter and address the remaining open items from the NRC Augmented Inspection Team report for the SONGS outage. In its report, the NRC pointed to flaws in the computer code and Mitsubishi Heavy Industries proprietary engineering models used to design the failed steam generators at SONGS. As a result, the NRC issued a Notice of Nonconformance with NRC regulations to Mitsubishi Heavy Industries as the contractor. And a preliminary white finding and apparent violation to SCE as the operator of SONGS. It is not unusual for the NRC to cite the licensed operator even when problems are created by a vendor or contractor. There were no penalties imposed on SCE by the NRC, and SCE has submitted written comments to the NRC on the preliminary white finding. We fully intend to hold Mitsubishi accountable for its failure to provide properly functioning steam generators and for the damage it has inflicted on our customers and our company. On October 16, SCE submitted a request for arbitration to the International Chamber of Commerce for at least $4 billion in claims against Mitsubishi for damages that the SONGS owners have suffered. These claims are consistent with those outlined in the July Notice of Dispute, and include the new steam generators, replacement power to serve our customers, lost revenue and inspection, repair and other related costs. In the meantime, the Order Instituting Investigation related to SONGS is continuing at the Public Utilities Commission. On November 22, we will submit opening briefs for Phase 2, which addresses adjustments to rate base and interim-rate making. The estimated timeline for a Phase 2 decision is the first quarter of 2014. The schedule for Phase 3, which addresses prudency, has not been set. We are hopeful that the SONGS OII can be resolved next year. Let me now turn to EME and the recently announced NRG transaction. The NRG transaction is part of a plan sponsor agreement to which EIX is not a party. The plan sponsor agreement contains term sheets for an EME plan of reorganization, the details of which have not been provided to us or to the bankruptcy court. As we have stated in the 10-Q we filed today, we are reserving our right to support the plan, oppose it and/or seek modifications to it. Under the skeletal plan filed with the bankruptcy court, if the sale to NRG is completed, then a reorganized EME would be wound down but would retain the right to pursue claims against Edison International. Likewise, EIX will retain the right to assert its claims against EME. In other words, matters between EIX on the one hand and EME and the creditors on the other are reserved out of the NRG transaction and left to the plan of reorganization to be submitted and argued in accordance with applicable judicial processes. If the litigation is pursued, then presumably, reorganized EME will need to reserve out of the NRG sale proceeds for our claims, as well as the cost of litigation. Edison International does not know if a complaint against it will ever be filed containing the allegations we saw claimed by the creditors' committee motion in August. It would obviously be beneficial for all concerned if everything were wrapped up at once. But if the complaint containing such allegations or other allegations is served, we will defend ourselves vigorously. We will not be intimidated by claims we don't think have merit. Remember that as a result of the bankruptcy process, the investment in EME was written off last year and EME is no longer included in our operating results. EME was and remains structurally separate from Edison International. We have presented more detail on these developments in our 10-Q filing. Given that this involves matters that are pending in court and that many of the details related to us have not surfaced, we don't intend to comment further at this time. This brings me to how EIX management continues to focus on earnings and dividend growth as the primary means for enhancing the shareholder value for our investors. Our forecast of capital expenditures produces a 7% to 9% compound annual growth rate in SCE's rate base through 2017. This forecast is based on the 2015 General Rate Case Notice of Intent that was submitted in July, along with updates to transmission investments. In mid-November, SCE plans to file the formal application for our 2015 General Rate Case. We do not expect material changes from the Notice of Intent, which demonstrated the need for long-term reliability investments. I would like to emphasize our hope for timely review of the application and a decision to allow for implementation of new rates in January 2015. We are working hard to resolve the key uncertainties facing our business while providing strong growth prospects through continued utility investment. The additional cash flow generated from the past several years of increased investment and rate base is sufficient to support both future growth and dividend increases in steps over time back to our target payout ratio. We believe this is the best formula for achieving shareholder value. I've made the statement several times to investors that shifts in public policy, coupled with advances in technology, are combining to create transformative change in our industry. Along these lines, there have been some interesting developments recently, particularly on the public policy front that I want to highlight. Assembly Bill 327 was signed by the governor last month, which addresses residential rate design, renewable energy standards and net metering for distributed generation in California. The bill starts to address some of the inequities in the current rate design by collapsing the number of residential rate tiers from 4 down to, possibly, 2, and allowing for up to $10 per month fixed charge. The bill also sets the current 33% renewable requirement as a floor rather than as a cap. Another provision directs the CPUC to develop a rate structure for net energy metering customers that considers the costs and benefits to all customers, not just those with rooftop solar systems. These provisions of AB 327 now moved to implementation before the CPUC in a formal rate-setting process. SCE supported these needed changes to customer rates and worked with numerous stakeholders to get this bill passed. SCE will be proposing its phase rate structure recommendations to the CPUC later this year. We are hopeful that the first phase can be implemented next summer. Another policy update is on energy storage. In October, the CPUC established a target for California's investor-owned utilities to install 1,325 megawatts of energy storage by 2020. This policy decision is one of the first in the United States and was created to optimize the grid, better integrate renewable resources and help reduce greenhouse gas emissions. SCE's share is 580 megawatts and the policy allows for up to 50% to be utility owned. The first solicitation under this new requirement will be in December 2014. We expect this will be implemented as a mix of utility-owned and third party investment. In October, the CPUC hosted a meeting to explore future business models of the California investor-owned utilities. I find it encouraging that the Commission is thinking about longer term strategies and regulatory models in our industry. Ron Litzinger presented our perspective, focusing on the need for infrastructure investment to transform the distribution grid from a radio system accommodating one-way flows of electricity to a more advanced and flexible system capable of two-way electrical flows. Such a system is needed to better enable distributed energy resources such as rooftop solar, electric transportation and energy storage. As the utility of the future continues to unfold, we intend to be at the forefront of that change, providing the enabling capital and engineering know-how while working with stakeholders to manage the ratepayer impact of state and federal energy policies. I see all of this as an exciting opportunity to create value for our customers and our shareholders through long-term growth and change. I'll now turn the call over to Jim Scilacci.

Thanks, Ted, and good afternoon. My comments will focus on the following topics: Third quarter earnings, updated capital expenditures and rate base forecast and our increased earnings guidance. Turning to Page 2 of the presentation. As Ted has already said, third quarter 2013 core earnings are $1.42 per share, up $0.42 from last year. SCE contributed $0.35 of the earnings growth. The key drivers are shown at the right side of the slide. As with the first 2 quarters, the largest earnings driver is the delay in the 2012 General Rate Case decision. This timing item creates a quarter-over-quarter revenue difference of $0.29 per share. You will recall that during 2012, before our final GRC decision was received, we recorded revenues at 2011 authorized levels. In addition, as we have indicated in prior quarters, SCE's earnings related to rate base growth are largely offset by the lower CPUC return on common equity. To these comparisons, this quarter, the impact from SONGS is grouped into 1 category with a $0.02 net positive impact. There are 2 main drivers here. First, a favorable reduction in O&M as compared to the third quarter of last year, when we incurred inspection and repair costs as part of our efforts to return the station to service. With our June decision to permanently retire SONGS, we obviously did not incur these costs during this quarter. Second pending the outcome of the SONGS investigation at the CPUC, we are no longer recording return on SONGS rate base as we indicated in the June -- in June with the updated guidance. As we transition SONGS to decommissioning, revenues and expenses recorded will be affected and will make period-over-period comparisons more difficult. We have estimated the impacts of the main financial statement line items in this slide footnote. The important point is that we continue to only record revenues for actual costs, which are lower than GRC authorized revenues. Actual costs do not include depreciation, taxes or return. O&M savings, excluding SONGS, contributed $0.02 per share to earnings. These savings include planned cost reductions from the implementation of the Edison SmartConnect digital meter program. We also continue to benefit from O&M savings related to organizational realignments that have taken place over the last several quarters. Depreciation, excluding SONGS, increased $0.07 per share, reflecting the impact of new investments. This quarter, net financing costs are $0.05 higher than last year, primarily from financings that support rate-based growth in accordance with SCE's authorized capital structure. AFUDC earnings are also included in this category. These earnings are lower quarter-over-quarter due to lower AFUDC rate and construction work in process balances. The last item is the $0.13 per share benefit from income taxes. A majority of this relates to continued benefits from the prepared deductions that were highlighted in our guidance. The other tax item is a $0.06 per share benefit of repair deductions from generation assets based on a new IRS guidance received during the third quarter. Year-to-date, we have recognized $0.16 of incremental repair deductions, which is higher than the $0.15 for the year that we included in our original February guidance. This is largely due to an increase in the amount of plant closings that qualifies repair deductions than we originally estimated. I'll come back to this in the discussions of guidance. Edison International parent and other costs produced a positive variance of $0.07 per share. This relates primarily to an increase in consolidated state income taxes last year, as we had to adjust our state apportionment factors based on declining EME revenues. There were no non-core items from continuing operations in the quarter. EME is reported as discontinued operation and is no longer consolidated as part of our results. During the third quarter of 2013, we did record an $0.08 per share charge reflecting changes in our estimate of income taxes related to EME. Together, the core earnings and discontinued operations tie to the basic and diluted earnings, up $1.34 per share for the quarter. Page 3 summarizes the year-to-date results and core earnings drivers. I will not go into the full reconciliation for year-to-date results because the explanation is similar to the quarter. Turning to Page 4, we've updated our capital expenditure forecast. 2013 capital is expected to be near the bottom end of the original range due to lower costs on 2 transmission projects, Devers-Colorado River and Eldorado-Ivanpah, that are largely completed this year and a slower ramp-up of CPUC infrastructure replacement spending. The revised range for 2013 to 2017 is $18.2 billion to $20.6 billion, which is $300 million to $400 million higher than the August forecast. The increases in the last 2 years is largely due to an updated cost estimates for the Coolwater-Lugo and West of Devers transmission projects. These transmission projects, which are shown on Page 5, have been in our forecast since 2011 when we received CPUC incentive approval for equipment rate base and abandoned plant recovery. In conjunction with the recent CPUC, Certificate of Public Convenience and Necessity applications for both projects, we've updated our capital estimates. Also, on Page 5, note that these costs do not yet reflect projects' scope increases related to FAA requirements related to the Tehachapi Renewable Transmission Project. We will update these costs once a final decision is received from the CPUC. Turning to Page 6. Our rate base forecast remains the same, except for the $200 million increase in 2017 for the previously mentioned transmission projects. Rate base growth continues to be 7% to 9% compounded annually through 2017. As a reminder, this slide removes SONGS from all of 2013 and future years pending resolution of the OII process. Now let's move to SONGS and the process recovery for the different cost components, please turn to Slide 7. As Ted mentioned, SONGS investigation is well underway and we are currently in Phase 2. Over the summer, testimony was submitted on the treatment of rate base and materials and supplies, as shown on Slide 8. SCE's decision is that the used and useful portion of rate base, or $425 million, should receive a full return on the investment at our currently authorized 7.9% cost of capital. The remainder, or $733 million, shall receive a reduced return of 5.54% for the weighted authorized cost of debt and preferred stock. A final decision on this phase is expected in the first quarter of 2014. Although the schedule has not yet been set for Phase 3, we continue to believe the SONGS OII can be completed by the end of 2014. Additional slides covering the various cost categories and sources of recovery of costs are included in the appendix. Please turn it to Slide 9. We received the CPUC proposed decision on the 2013 forecast Energy Resource Recovery Account or ERRA. This is the balancing account for fuel and purchase power. I wanted to give an update on this because even though it does not impact earnings, it does affect liquidity. The utility is under collecting this year as we have not yet received decision on our 2013 ERRA application. Currently, we are $719 million under collected in this account and project to be about $1 billion under collected by year end. The reason for the under collection is that current rates are set at 2012 levels and do not include increased market purchases to cover SONGS and higher power, natural gas and greenhouse gas costs. The proposed decision, if approved, would increase rates about $200 million. It would also move $321 million originally estimated for SONGS replacement power to the SONGS balancing account for consideration without making a determination on rates movements. In the 2014 filing, we have recommended a 2-year amortization of the 2013 under collection to moderate the impact on customer rates. A decision on the 2014 ERRA filing is expected by the first quarter of 2014. Finally, we are financing the under collection with short-term borrowings. Now let's discuss our updated earnings guidance on Slide 10. We have increased our core earnings guidance by $0.30 per share to a new range of $3.60 to $3.70 per share. We have also updated our key guidance assumptions. I think it's easier to walk through how 2013 guidance has evolved. Let's turn to Page 11. When we gave 2013 guidance in late February, we used our simplified earnings model for SCE and identified the potential for $0.31 of upside from repair deductions, O&M savings and energy efficiency. Concurrent with the SONGS shutdown announcement in June, we lowered core guidance by $0.20 per share. This action incorporated lower debt, preferred and common equity and AFUDC earnings and other transition costs. All those elements remain in effect. Today's guidance increases -- increase reflects 2 items. First, our operating expenses and other miscellaneous items. With continued strong cost management, we forecast an additional $0.10 per share benefit, bringing the total to $0.23 for the full year. As we said in February, the cost savings will flow through the customers and are embedded in our 2015 General Rate Case. Second, our tax benefits. Tax benefits relate primarily to property-related deductions including updated estimates of completed projects that qualify for repairs for tax purposes and cost of removal deductions and new tax guidance for generation-related repairs, as I previously mentioned. Together, we see this increasing our full year benefit by $0.30 per share on a core earnings basis. We have reaffirmed our parent company and other costs at $0.15 per share for the year, yielding an updated core EPS guidance in the midpoint of $3.65 per share, which we have ranged to $3.60 to $3.70 per share in our formal guidance. We anticipate providing 2014 earnings guidance when we report full year results in late February of next year. Thanks. And now, I'll turn the call over to the operator to take questions.

[Operator Instructions] First question comes from Dan Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Jim, I -- just following up on that -- the O&M question or the O&M trajectory. Can you talk a little bit about how the better savings are coming together, where you guys are finding the benefits? What carry-through that -- should have into the ‘14 expectations as you kind of look at maybe some run rate savings, and then, how the GRC is recalibrated, if you guys remain successful in doing better than planned as you've done this year?

Okay. So just taking ‘14 -- I'll do it in reverse order. We said all along, you should look to our rate base growth, so I used the simplified model. And there will be O&M and tax benefits that flow into ‘14, but we haven't made any projections of what those numbers will be. And I think we've said that the tax benefits will be less in ‘14. And we'll have to update those based on what we're seeing as we flow through ‘13. And again, we won't make any estimates of what our guidance will be for ‘14 until February. But I think it's the best model you can use, is the simplified approach using the rate base model. Especially as you push out to ‘15, which all the tax benefits and the O&M reductions should flow back to customers and be picked up as part of the rate case process. So using that simplified approach is the soundest way to project earnings beyond ‘14. Going back to ‘13, now we've said there's $0.23 of operating expense savings as you can see in the key assumptions in our guidance page. And what's driving this, clearly, we're seeing some benefits flowing through from some of the cost reductions we have undertaken through the course, the first 3 quarters of this year. Some of that has been masked, too, because we've had a number -- amounts -- a significant amount of severance-related expenditures that as you work through the reductions have slowed now as you get into the third quarter, we have fewer anticipated for the fourth quarter. So now you'll see the benefit of the cost reductions coming through. And I'll pause and look at Linda or Ron if they want to add anything to the answer. Anything?

I mean, our O&M cost reductions, largely 3 areas. SmartConnect flowed through this year, reduction in meter readers and field service reps. The bulk of it has been reductions in our overhead or staff functions and then, there's been the San Onofre reductions as well. We continue to benchmark ourselves against the industry on an O&M dollar per customer benchmark. We continue to identify potential savings but known savings, as Jim said, are reflected in our 2015 rate case filing.

Do you want to follow-up, Dan? Dan Eggers - Crédit Suisse AG, Research Division: Yes. And I guess, just on the CapEx program and the kind of the mix of transmission and distribution with the higher level of distribution and the forward plan now, how visible is the distribution spending as you look out to ‘15, ‘16 and ‘17? And how do you guys plan to manage that with the Commission to make sure you get as good of a yield on CapEx as you have in the last rate case?

Yes, I'll take that first and I'll let Ron and Linda provide a little bit more detail. So distribution is ramping up and it's primarily in 2 areas. It's infrastructure replacement and pole loading. So we're doing more based on the age of the infrastructure. And in our General Rate Case proceeding, the rationale or the reasoning for this is all laid out in the testimony. And the challenge is to ramp-up, and part of what we said for ‘13 is because of the increased spending in distribution and a number of items we have to do is having the manpower in order to achieve these capital expenditures increases. So I'll pause there and let Ron and Linda add anything to that.

The bulk of the increase from our past infrastructure replacement levels is the pole loading program that Jim noted. In addition to the normal pole deterioration we see with the large influx of additional telecom attachments, we need to replace poles to address the loading on the poles. And so we have ramped that up to a level that's consistent with our long-range replacement target for poles, the level that we feel we need to be at to stay in equilibrium. So it's the first asset that we've ramped up and achieved that on in this rate case. And we're just going to continue ramping up our infrastructure replacements to be more consistent with the age of our assets.

Dan, this is Scott. Just one other comment, everything that Jim and Ron have spoken about were factors that were included in our presentation for CapEx. Previously, the changes that Jim alluded to this quarter were largely related to updated transmission project cost estimates for 2 specific projects.

Yes. We had put in preliminary estimates for West of Devers and Coolwater-Lugo from several years ago. And now that we're going formally into the licensing phase, we've updated those costs.

Next question comes from Jonathan Arnold with Deutsche Bank.

On SONGS and timing and the OII, I think it was your comment, Jim, you were confident you could wrap like the whole thing up during 2014. And then you were speaking to being in Phase 2 but I think the really broader comment was about the whole OII.

Yes, I think I've been indicating consistently that we hope to get it through by the end of 2014, so essentially leave the bulk of the proceedings, which is the Phase 3, for the balance of 2014. So that's just a hope or an expectation.

And what are your hopes of being able to maybe get to accelerated resolution?

I can't go there, but we're just going to go through the process and keep on track in terms of what the Commission has established for the proceeding.

Okay. And then on a -- to a different topic. Could you just -- I have no chance to see all the filings but where do you stand on equity ratio, currently? And should we think of these benefits that you're having in, some of which will flow through and then others weren't, as something that's going to just help to build a little equity cushion?

It can, it does have that effect. We're at 49.5 as of September 30. And so that's the 13 month basis, obviously. And we do use short-term debt at times to moderate the impact. And so, again, just kind of hidden in your question is we have no plans to issue equity, if that's what you're alluding to. So we're going to manage this based on what we know and we'll watch our capital expenditures and we'll use short-term debt and we'll take that all into consideration and how we're trying to moderate the need for potential capital financing.

Again, my question probably was more accurately on how much headroom do you think you have?

We do have some. And again, this is all we're looking out well into the next couple of years as we look at that number. So we'll bounce around based on how we do long-term financings, how we use short-term debt and what the earnings will be going forward.

So, some is the answer?

Yes, it has an impact.

Next question comes from Julien Dumoulin-Smith with UBS.

So you alluded to on the call earlier some of the energy storage possibilities that are, I suppose, coming to fruition perhaps next year. If you could talk about what the rate base potential is. You talked about, I suppose, 500 and change megawatts, 50% rate baseable, what kind of an investment could that translate to ultimately?

Just let me start here because we haven't put out anything in our -- in the General Rate Case proceeding. It does not include anything at this time related to the storage potential. So we're going to evaluate it and consider what's there but it's premature, I would say. And I'll let Ron fill in here to suggest what the earnings potential might be from that.

No, that's right, Jim. We're taking a look at the decision. We're primarily interested on the distribution side, that would go through the rate case process. And on the transmission side for energy storage, we haven't made a decision. We're still evaluating and estimating what, if any, capital we would look out on the transmission side.

Got you. And then just looking at the rates in here in the discussion ongoing, I mean, when do you look for something out of the CPUC as far as addressing and reconciling the issue?

Is that related to the storage? I missed those.

Sorry, with regards to the DG and the legislation in the quarter.

Oh, the 327. The Commission right now is working on a schedule. And then I don't know if it's public. Ron, could you comment?

I don't think so. I don't think there's a schedule out yet.

From what we're hearing, it's going to be sooner rather than later. So they're trying to move it along as rapidly as possible so we could hopefully incorporate it in rates. It could go into effect in ‘14.

So, summer of ‘15 -- summer of ‘14.

Summer of ‘14.

Next question comes from Ali Agha with SunTrust.

First question, just -- can you remind us again, you -- every call you alluded to us that one of the key drivers for you is ramping up the dividend. You've also told us your range for payout and you're below that. When I look at the different things going on, your CapEx ramps, I think, 2016 is the peak year, according to your schedule. You got the GRC case, most of next year, and, of course, the SONGS issue. Can you just again prioritize to us how you look at these issues in terms of how that will influence the dividend? And when, at the earliest, should we think of you getting into that range that we've been seeing for the last several years?

Well, Ali, they've dubbed me the one to answer that question. This as Ted, how are you? I don't think we will attempt to provide any kind of a schedule for when we would get back into the 45% to 55% payout ratio. What we have said is that we believe we'll be able to move our way back to that 45% to 55% target in steps over time. And in order to do that, that means you have to have a dividend rate increase that's greater than your earnings rate increase. So I think that gives you some sense of how we would, at least, see the trajectory to get there. But we won't provide a specific target date for getting back into that target zone.

Ted, fair enough. But just to prioritize, or at least, the way you think about it between the CapEx timing, SONGS resolution, GRC, can you just give us a sense of how you think about what's more important than the other, as you're thinking through this conceptually?

I don't know that I could say what thing is more important than the other. I mean, frankly, a lot will depend on how these things evolve. But I think you put your finger on some of the key considerations. The part that I think is most important to reemphasize is because of the substantial investments that we've made over the last several years, we have a much larger rate base, which is producing much larger cash flows. And now, we really see our CapEx kind of leveling out albeit at a high rate, but leveling out, not continuing to increase. So we're kind of in this roughly $4-billion-or-so zone per year in CapEx. So with the growing rate base and a level annual CapEx that produces substantially more cash, which allows us to get back to our target payout ratio on dividends. Yes.

I was just going to say my second question, you've talked about and you've shown that your rate base numbers in the back end have actually gone up slightly because of the transmission CapEx. Are there any scenarios in which any of those projects could be in jeopardy because of the cost overruns? I mean, is there a scenario where we may have to actually reduce the rate base numbers as we look out the next year through ‘17?

Well, again, it kind of gets into the specifics of each one. If you could take Tehachapi as an example. A big chunk of that increase, of course, came from a Commission order on Chino Hills to underground the 3.5-mile section. So, I think we look at that as, that's what's been ordered by the Commission, it certainty will be important from a FERC approval standpoint. So it's a host of things that affect the costs. In some cases, we've actually come in on budget, indeed a little bit below budget and on time on some of these transmission projects, the ones that were just completed here. So it's a mix and that's kind of what you would expect. Some things will be a little bit higher, some things will be a little bit lower but I think, in general, we're in the zone of what we have projected previously.

Next question comes from Michael Lapides with Goldman Sachs.

A couple of items, and I'll touch on them in order and then I'll be quiet. One, can you talk about the potential investment on the transmission side related to either the SONGS retirement or the retirement of the 6-plus gigawatts of gas generation capacity in California that must meet some of the cooling water regulation? That's question one. Question two, right after you announced the SONGS retirement, the commissioners put out a release basically implying their desire for an expedited resolution settlement, et cetera. Have the commissioners themselves, either in ex-partake talks or in other, done any follow-up in a similar vein related to that initial release? I think, it came out by the commissioners literally within a week or so after your retirement announcement.

Okay, let me take the first question. There is a potential for capital expenditures based on the retirement of SONGS and once-through cooling plants. We are looking at that but I think it's premature, Michael, to try to put some numbers out there. So I would feel uncomfortable should you not -- just throwing some numbers out. We've got some large transmission projects that we're working on at Coolwater-Lugo and the West of Devers projects that are primarily for renewable support. But we are looking, as part of the SONGS shutdown and how we're going to replace SONGS, what the steps might be to replace that. And it's going to be a host of different things. It's going to be energy efficiency, it's going to be DG, there could be additional transmission upgrades. So we're looking at the gamut along with a large group of folks from the ISO and the CPUC and other stakeholders, determining what's appropriate. And clearly, we're looking at it as a package, you don't look at it as -- in isolation. You have to take a look at all these things so you can plan accordingly. I'll pause there and look back to Ron before I answer the second question.

In the state agencies, the Energy Commission, PUC, they put a strong emphasis on what they call preferred resources in Orange County, which are distributed generation energy efficiency and the like that Jim had mentioned. So we have a strong focus on how do we facilitate that through distribution investment would be the primary area there. What it comes down to with the once-through cooling and the SONGS retirement is where does the replacement generation get located. If the bulk of it were to be in the Los Angeles basin, the amount of transmission upgrades would be fairly minimal. If a significant portion is located out of the basin, the transmission needs would go up. As part of the review process, there's been several potential projects thrown about but none of those have been formally incorporated into the Cal ISO planning process as of yet.

Going back to the second question, Michael. We have obviously heard the commission's comments and we've read about similar comments and various analyst reports that have been out over the last couple of months. And I'll stay, we won't go beyond just acknowledging that we've read that.

Okay. One thing on the transmission, your neighbor in San Diego has actually put out a slide deck for the Cal ISO. They outlined 4 projects, the smallest of which was $1.6 billion or so, the largest of which was close to $4.5 billion, $5 billion. I was under the impression that SoCalEd would have to make similar type of high-level disclosures to the ISO for transmission, is that correct? And if so, when would you likely have to start putting kind of more firm estimates around potential alternatives that the ISO could evaluate?

It would be in the next ISO formal planning process which I think is about to begin shortly. I don't remember the precise date but it's coming up and we'll have to outline our potential projects as well.

Our next question comes from Paul Fremont with Jefferies.

It looks as if a level of short-term debt is -- has been accelerating, so it looks like it's about $1,350,000,000. Is that primarily due to the purchase power under recovery or what other reasons might there be for the short-term debt to be going up?

Good question, Paul. The short-term debt will ebb and flow on a variety of different reasons. Partly, the balances we were carrying before had to do with the under collections in our fuel and purchase power. However, we're also over collected in other accounts. Also, we did a large financing recently with $1.6 billion and the proceeds, some of it was to refinance some upcoming maturities and some of it was new money. So the short-term debt will ebb and flow based on the timing of financings and what we're seeing for our under collections and over collections. So you can't -- it's not all tied directly to the fuel and purchase power situation that we've got right now.

And you've estimated sort of an under collected position this year for fuel and purchase power of $1 billion yet. At the current rates that are in place, would there be sort of a similar under collected amount next year?

Well, it depends on the timing of the rate proceedings because there's 2 separate ones. There's a 2013 ERRA proceedings that would increase rates and then there's the 2014 proceeding, which would increase rates. And the timing of those would impact the ramp-up of potential short-term borrowings. But we'd expect the Commission to render decisions in this because they know the importance of getting these done in a timely basis. The hang up has been the crossover with the SONGS proceeding. So the short-term debt and the under collected balance that doesn't relate directly to short-term debt is going up about $100 million a month based on current rates. And then, you have to look at all the other factors to see what the short-term borrowing implications might be.

Next question comes from Hugh Wynne with Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: My question was around AB 327. The legislation seems to create a lot of latitude for the Commission to revise the tiering structure of the rates, to revise the tariff for net energy metering. My question was what are your objectives vis-à-vis, the Commission for the rate structure, for net energy metering and why are those objectives important to the company?

Okay, Ted's going to take that one, Hugh.

I think in the broadest sense, the objective is to try to have a rate structure that eliminates some of the inequalities that the current rate structure has. So for instance, in the current tiering, you have higher use customers really picking up the bulk of increased infrastructure investments and other policy-related increases in costs, while the lower-use customers are largely immune from those cost pressures. As a result, we now have a good $0.20 or more separating the low-use customers from the high-use customers. And really, the bulk of the burden landing on the high-use customers. We estimate roughly speaking that about $650 million a year is being shifted from low-use customers onto the high-use customers, or said differently, the high-use customers are subsidizing the low-use customers to about $650 million a year. So that's one of the things that the AB 327 seeks to address, is providing the opportunity for the tiers to be reduced in number and the differential between the tiers also potentially reduced. Second part is, I think, equally or more important than that is increasingly, as distributed energy resources find their way into the distribution system, you have more and more of the fixed cost of the system really being avoided, and that needs to be addressed. So -- and that's one of the inequalities. We really feel that everybody that makes use of the grid, whether they are pulling electricity directly from it or whether they are using it as a backup resource or what have you, that, that's an important resource that needs to be -- the costs needs to be shared by all users. Said a little differently, the distribution system really enables the distributed energy resources, and so that's a cost that everybody should participate in. So that's what the fixed cost seeks to address. I think those are the principal issues that drew us to support the legislation. And certainly the author, Henry Perea, biggest issue he had was really this cost shifting. And a lot of that ends up impacting the lower income customers.

Just -- Hugh, to follow-on the net energy metering, there's a subsequent work that needs to be done on that. The legislation really didn't directly affect that and the Commission's doing some work now to try to determine the impact of net energy metering. And there could be some subsequent work by the Commission that follows up on that.

They need a new tariff by 2017, and the direction they gave for the new tariff was to look at how the benefits and costs are shared amongst all customers rather than just the distributed generation customers. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Right. Could I trouble you just to comment quickly on what are the mileposts that we can use to monitor the progress on the MHI arbitration, if any, and similarly, on the NEIL insurance collections?

Hugh, really, on the EME stuff, we're really going to stay...

MHI.

MHI, Excuse me. On MHI stuff, we're really going to -- thinking litigation and arbitration here, sorry about that. We're going to really stay away from trying to speculate on exactly what goes, what those time tables or milestones would be. I mean, right now, as we said in the comments, we just have issued our arbitration notice and so we've got that to get through and then we'll see where that takes us from there.

Next question comes from Ashar Khan with Visium Asset Management.

My questions have been answered.

Next question comes from Kit Konolige with BGC.

Most of my questions have been answered. Just wanted to refresh my memory. I think in the past, you've talked about -- in the OII for SONGS, about Phase 3 being really the most critical of those phases. Is that -- am I remembering correctly?

You got it right, Kit.

Okay, good. That's simple enough. And Jim, what -- do you have some idea when Phase 3 might be started, when there could be filings in that? Is it sequential after Phase 2 is done, then Phase 3 starts?

That's how they did Phase 2, but they've been going on, well, almost concurrently to a certain degree. So they haven't put out anything, Kit. We would expect it would occur sometime in 2014 and we'd hope they get through it by the end of 2014. So that's what we've been consistently saying, so let's see what the Commission actually does.

Next question comes from Angie Storozynski with Macquarie.

So as we're approaching December, and in December, your Board of Directors usually reevaluates your dividends. And as you say that you have plenty of flexibility on the debt side to finance any carrying cost of the underfunded replacement power costs, what should we expect for the dividend increase?

Ted's going to take it, tackle that one, again.

Angie, we really can't speculate on that at this point.

; That's it? Not even an attempt to answer the question?

If you could just be in the room, you'd see my nice smile. I really -- we really can't discuss it at this point.

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

Thank you, everyone, for participating today, and don't hesitate to contact us if you have any follow-up questions. Thank you.

Thank you for your participation in today's conference. Please disconnect at this time.