Edison International (EIX) Q1 2012 Earnings Report, Transcript and Summary

Good afternoon. My name is Sharon, and I will be your conference operator today. At this time, I would like to welcome everyone to the Edison International First Quarter 2012 Financial Teleconference. [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. Mr. Cunningham, you may begin your conference.

Thanks, Sharon, and good afternoon, everyone. Our principal speakers today will be Chairman and CEO, Ted Craver; 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 10-Q filings are available on our website at www.edisoninvestor.com. Tomorrow afternoon, we will issue our regular quarterly business update presentation that will use of these and other slides for our ongoing investor discussions. 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. [Operator Instructions] With that, I'll turn the call over to Ted Craver.

Thanks, Scott, and good morning -- or good afternoon, everyone. Today, we reported GAAP earnings of $0.28 per share. As expected, a decline from the $0.61 per share last year. Core earnings were $0.35 per share compared to $0.65 per share a year ago. There are 2 high-level points I would like to make about our first quarter earnings. Southern California Edison's first quarter results reflect a mismatch of costs and revenues, given the delay in receiving our General Rate Case decision. Once the California Public Utilities Commission issues a final decision, revenues will be recognized retroactively to the beginning of the year. Second, in anticipation of transferring EMG's Homer City plant to the owner-lessors, we reclassified Homer City's $0.03 per share loss last year and this year's $0.07 per share loss into noncore earnings. I would like to update you on a few important matters since our year-end earnings call. Let me start with the cost of capital application Southern California Edison filed with the CPUC on April 20. SCE's application recommended continuing its current capital structure of 48% equity, 43% long-term debt and 9% preferred stock with a recommended ROE of 11.1%, down from the current 11.5%. SCE also recommended continuation of the same automatic trigger mechanism, which has been in place for several years, that uses the Moody's Baa utility bond index. We recommended this mechanism be continued for a 3-year cycle and adjusting the baseline to reflect the 12-month average of the index at September 30 of this year. SCE's proposal would result in a 2013 reduction in customer rates of $128 million, about half associated with the lower ROE and the other half related to the true-up of our embedded cost of debt and preferred stock. Hearings are anticipated in late summer or early fall with a final CPUC decision by year end and effective January 1 of next year. There are summaries of the filing and an illustrative example of the index mechanism in the presentation appendix. Let me now turn to our San Onofre Nuclear Generating Station. SCE is continuing to assess the causes of the steam generator leak discovered January 31 at Unit 3, working together with the NRC, the manufacturer, and other consultants and industry experts. Over the last 3 months, we have been conducting a battery of tests and studying the phenomenon causing the tube wear. We have identified some unusual wear in approximately 1% of the nearly 39,000 steam generator tubes that transfer heat to produce the steam, which drives the turbines and generates the electricity. While tube wear is to be expected, we are taking this very seriously since it is occurring in newly installed steam generators. When we are satisfied that we sufficiently understand the mechanisms and the causes of the wear, we will seek confirmation of our remediation plan with the NRC. The plan will likely follow standard industry practice of plugging, stabilizing and removing from service all affected tubes along with some other operational changes. We are absolutely committed to the safe operation of San Onofre and will not return the units to service until we and the Nuclear Regulatory Commission are completely satisfied it is safe to do so. It is possible the time required to do all this will keep one or both of the units offline into the summer, straining our ability to meet peak electricity demand. Therefore, we have been working with the California Independent System Operator and San Diego Gas & Electric on power supply contingency plans for this summer. Those plans include transmission upgrades, bringing idled plants owned by other companies back into service, conservation and demand response programs to reduce the possibility of service interruptions. I'd like to turn next to EMG and come back to several key points I made on our year-end earnings call. First is our strategic intent. I want to reiterate what I said on the last call, that we continue to believe that a dual platform of regulated and competitive businesses best positions our company for the significant change we expect in the electric power industry. Second, I reaffirm our commitment that we will not invest new funds into EMG, given the challenging market conditions. Finally, given the simultaneous need to retrofit the Midwest Generation fleet and meet future debt maturities at a time when power and capacity prices are at a cyclical low, I stated that a restructuring or reorganization of EME's capital structure may be needed. Further to this point, we take note of reports that EME bondholders may be seeking to organize themselves. We continue to believe this year will be definitive for EMG in terms of making decisions about the path forward. I would like to review some of the important decisions made since our last earnings call and some of those to be made in the months ahead. Let me start with Homer City. EMG continues to work with GE Capital to transfer Homer City to the owner-lessors. On March 29, Homer City and GE Capital signed an agreement that sets forth a road map for completing the transfer. Turning to Midwest Generation. EMG has accelerated the timeline for closure of the Fisk and Crawford facilities to September 2012. EMG has also requested a 1-year extension to December 2014 of the compliance deadline for environmental retrofits at Waukegan Unit 7. The closure of Fisk and Crawford stations and the resulting emissions reductions more than offset any impact of a 1-year extension at Waukegan and give EMG more time to assess capacity market and forward power prices that will affect final retrofit decisions. EMG continues to implement its renewables financing strategies. These will enhance liquidity while allowing EMG to grow its renewables investments through the Capistrano venture announced in February. With those comments, I'll now turn the call over to Jim Scilacci.

Thanks, Ted, and good morning -- I did it too. Good afternoon, everyone. Ted has already touched on the high-level first quarter comparisons, which are summarized on Page 2 of the presentation. Please note that the first quarter holding company costs of $0.02 per share are in line with our normal quarterly trend. Turning to Page 3. The delay in the 2012 CPUC General Rate Case decision that Ted mentioned impacted first quarter earnings by about $0.08 per share. Our first quarter CPUC revenues are largely based on 2011 authorized revenues. As a result, higher costs in the first quarter are not currently being recovered, including higher depreciation and new debt and preferred stock costs. When SCE receives its final GRC decision, it will record the revenue retroactively through January 1. The remaining $0.03 negative variance is lower AFUDC as SCE is utilizing more short-term debt in 2012. In addition, SCE incurred $0.04 per share of unplanned outage inspection and repair cost at San Onofre, reflecting the $20 million pretax figure that Ted mentioned. During the first quarter, inspection and repair costs were largely offset by lower operation and maintenance costs in other areas of the company. Subject to the NRC review under the confirmatory action letter and any new developments that may result from further analysis, testing and inspection, SCE's estimated share of the total incremental inspection and repair costs associated with returning the units to service remains uncertain but is currently projected to be in the range of $55 million to $65 million pretax. Currently, SCE is expensing the SONGS inspection and repair cost as incurred. And such cost will, as appropriate, be offset later to recognize recoveries SCE obtains under the warranty applicable to the steam generators. Replacement power costs are recorded in the fuel and purchased power balancing accounts but are subject to later reasonableness review by the CPUC. As a result of this treatment, there is no impact on 2012 earnings. There were no significant changes to SCE's capital spending or rate case forecast and the details are included in the appendix. EMG results are shown on Page 4 and reflect the treatment of Homer City as noncore for both periods. EMG's first quarter core loss increased by $0.17 per share from lower generation, lower average realized energy and capacity prices along with higher fuel costs at Midwest Gen. Reduced generation resulted from lower economic dispatch, increased planned maintenance outages and thermal discharge limits at 2 stations in March due to unseasonably warm weather. Our regular Midwest Gen operating report summary, hedge position and capacity market summaries are contained in the appendix. There were no significant hedge or coal procurement transactions in the quarter. On Page 5 presents 2011 quarterly and full year EPS results for Homer City that can be used for updating models. With the expected pending transfer of Homer City to the owner-lessors, we are no longer including Homer City-specific information in our presentation and earnings commentary. It remains in the 10-Q disclosures for those that want the information. On March 29, Homer City and GE Capital entered into an implementation agreement and both parties are now working on related agreements for the construction of environmental improvements at Homer City and the transition of the plant to the owner-lessors. GE Capital and certain of the Homer City debt holders have been in discussions regarding the terms of the existing secured lease obligation bonds and funding for the scrubbers. At this time, it is uncertain when Homer City will transition to the owner-lessors. Ted already mentioned that we will close Fisk and Crawford stations in September. When this occurs, EME will record a tax deduction equal to the remaining tax basis of the assets. At March 31, 2012, the tax basis for Fisk was $64 million and the tax basis for Crawford was $87 million. I'd like to turn now to EMG's wind financing and capital raise strategy on Page 6. EMG continues to make progress implementing this strategy, which now includes the Capistrano Wind Partners venture that closed in February. In the first quarter, EMG completed a new $98 million project financing for the 2 wind projects under construction in Nebraska, Broken Bow and Crofton Bluffs. EMG's capital spending plans, which are shown on Page 7, are essentially unchanged from what we discussed last quarter. The scope in the forecast includes basic maintenance capital spending, the large unit environmental retrofit program at Midwest Gen and completion of the 2 Nebraska wind projects this year and the Walnut Creek gas-fired project next year. All of the growth investments now have dedicated construction financings in place which will convert to permanent financings upon completion of construction. Turning to Page 8. At March 31, EME had liquidity of just over $1.3 billion and had recognized $908 million of tax benefits from net operating losses and tax credit carryforwards compared to $520 million at the end of last year. We expect deferred tax benefits to increase based on further operating losses, plant closures and from recognition of ongoing wind production tax credits. Last quarter, we had reported that EME would make a tax allocation payment to EIX of $185 million, but this amount may be substantially offset by tax allocation payments to EME by Edison International. Page 9 covers the same key points as our year-end presentation. As we have previously said, we will not provide earnings guidance for 2012 until after the CPUC GRC is final. We do however anticipate that EMG's full year adjusted EBITDA will be negative. This concludes my comments. And now I'll turn the call back over to the operator for the questions and answers.

[Operator Instructions] Our first question comes from Dan Eggers of Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: I guess, on EMG at this point, with a -- your continuing deterioration in fundamentals, can you just -- if you want to share any more thoughts on how you're evaluating that project and maybe how you could advance the conversation with the bondholders if the capital restructuring is a viable option for the timetable you guys have discussed for coming to a solution?

Dan, this is Ted. I think we're getting to that spot on EMG, particularly as it relates to potential discussions with bondholders, that, just frankly, is not going to be helpful or wise for us to kind of weight in and speculate on how those things might go. So I'm afraid you're going to kind of more likely than not get responses from us on those types of questions. We're just going to have to see how it develops. I think we've tried to lay out -- tried to lay it out in my comments that the fundamental approach is we believe that there needs to be some sort of -- some element of work with the bonds, looking at the capital structure, restructuring the capital. And that's going to most likely lead to a conversation with the bondholders. And that's probably just where we need to leave it at this point. Dan Eggers - Crédit Suisse AG, Research Division: Okay. That's fair. And I guess, just on the outlook for SCE this year. I know you've pulled guidance. But if we thought about how it will work once the GRC gets done, is it fair to assume this year you do still expect to yield or earn your allowed ROE at SCE less the $55 million or $60 million for the SONGS cost, which would presumably get recovered maybe next year once the warranty work gets resolved?

That thing that's -- this is Jim, Dan. I think it's the key we're going to need to get before for us is a General Rate Case decision. And you have all the metrics that we've been using for year-after-year. But the key piece that's missing here is the proposed decision is the first step, and ultimately a final decision. And once we have this -- that in hand, then we'll be able to give you a good assessment of where we think 2012 is going to come out.

Next question comes from Jay Dobson.

Wanted to follow up a little bit, maybe if we could just talk EMG and just what capacity factors we sort of saw in the quarter. I'm not sure if a lot of that information was in the handout, Jim. But just talk about, given coal-to-gas switching and these sort of things, what we saw?

Okay. The information is included in the deck. I'm just going to flip through it and probably tell you what page it's on, and I'll stop for a second. There was some limited coal-to-gas switching that we saw. In fact, in my comments, we talked about 3 areas where we saw reduced generation. And we think it had to do with the coal-to-gas switching for a piece of it, higher planned maintenance quarter-over-quarter and some thermal limits that we encountered because of the unseasonably warm weather in March. So that dropped the generation and some of the capacity factors for the Midwest Gen units. So I'll pause there. Can you see it? Page 33, Jay.

Okay. Perfect. I'll take a look at that. And then going back to San Onofre, I just want to understand your comments. The $55 million to $65 million, you're talking about pretax cost return. That's the total cost, so you're including in that what you've spent in the first quarter?

Yes.

And how...

I just want to sure it's clear. Pretax.

And how would that roll over the year? I mean, obviously, when it comes back is an important element in that. But if we were to assume it wasn't coming back for summertime is what we've seen in the first quarter a reasonable run rate? Or just how should we think about those flowing? And I know it's a difficult question because we don't know or you don't know when it's coming back.

Okay. I'm going to turn this over to Ron. He'll give you some more detail around that.

Yes. The $55 million to $65 million is what we are projecting for repair cost. And I want to keep those distinct from replacement fuel costs. And staying with the repair cost, that's what we're projecting. We still have a long way to go to finalize that. But that's where we think we'll end up, and then we can seek recovery under the warranty. Replacement power, which we had in the disclosures for the first quarter, which is around $30 million, we also disclosed that those costs would be substantially higher in the summertime.

Our next question comes from Jonathan Arnold of Deutsche Bank.

I think my question was pretty much answered. But just to follow up a little bit on SONGS. The process here is that you'll determine what the costs are expected to be and then make a claim under the warranty. So it will be kind of -- or will you need to expense everything and then claim back later?

So this is Jim. And I'll start, then Ron can fill in. So what we've done already, we've expensed all the costs to date, and we gave you numbers for what we think it's going to cost to bring the units back online. That's the $55 million to $65 million pretax, based on the current plan. And so we'll continue to expense them as we incur them, then we will look to seek recovery based on what we believe is appropriate under the warranty. Ron, would you like to add anything more?

Yes. The primary focus now is identifying the root cause so that we can return the units to service at some point. We are working cooperatively with MHI, as Ted stated, and just add that additional fact.

Our next question comes from Michael Lapides of Goldman Sachs.

Just looking through some of the transmission project data in one of the back slides, I noticed that some of the projects that are due on online or operational next year, they're like 16%, 18% done. Devers-Colorado, is 18% complete. Eldorado-Ivanpah is 6% complete. And just wondering how you feel about the schedules and getting them operational and in earnings by year-end 2013.

Ron?

Those particular projects, Devers-Colorado and Eldorado-Ivanpah, we have no indications of them been delayed. That said, it is always possible to run into delays with regards to environmental concerns on those projects. But at least for now, we've got no anticipated change in DCR and Eldorado-Ivanpah.

And Michael, just to add. If you look in the capital expenditures on Page 22, 2012 and 2013 are very heavy construction years. And a big part of that is [indiscernible] DCR, Eldorado-Ivanpah. So those are why that we have such a peak in this year and it drops off a little bit in 2013 but still stays elevated.

Our next question comes from Hugh Wynne from Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: My question goes to SONGS. You mentioned that there may be steps you'll have to take in the summer to ensure adequate power supplies in California, bringing plants owned by others back into service, for example. Are any of those costs likely to be unrecoverable? Or do you anticipate that all of them will be recoverable under the GRC?

It's not -- this is Ron, Hugh. It is not done through the GRC. Our fuel and purchased power costs are reviewed annually through our ERA proceeding. And all of the cost that we incur for SONGS being down will be subject to a reasonableness review, and it's tough to predict at this time where that will go next year. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Is that the point also of your disclosure on 19, that the steam generator replacement cost remains subject to CPUC review? Is that something to remind us that, that's a reasonableness test as well?

That is an additional reasonableness test. We've really got 3 categories here, fuel and purchased power cost, which are the ERA proceeding. We've got the steam generator replacement reasonableness application that we need to make for the capital, and then there's our O&M cost, which we talked about earlier.

Our next question comes from Steve Fleishman of Bank of America Merrill Lynch.

Question on the kind of thinking on dealing with EMG. As you've talked about all the issues that you resolved in the last 6 months, the pieces, I guess, we still have the RPM auction piece left. So it seems like there should be more certainty of the pieces of the company. But there are certain things, such as power prices in the future, also things like what happens with bonus depreciation, that are going to be hard to really know in making this decision. So how, if you're going to try and work this out, do you mitigate the risk to shareholders that you'd make the wrong call on those things? Or how do you deal with -- there's no way you're going to know all these pieces.

Steve, this is Ted. I'm trying to be a little more serious. I think you put your finger on, obviously, one of the big issues. We are looking well into the future. We're looking at what the potential cash flows are going to be. Certainly, if we're engaged in conversations with bondholders and the like, they're going to be doing similar types of things. So there's judgments that have to be made, and there's no way to be assured that those things -- that you can make all those judgments perfectly. The one part that I think is immutable is we are not going to be making additional capital contributions from EIX and EMG. So it is a closed loop as far as we look at the cash flows. Number two, I think we see some ways in which cash can flow through the system more readily, which, presumably, would have value for EMG and for bondholders. And I'm sure that will be a big part of any kind of restructuring conversation with them. Beyond that, it's all the usual stuff. If you could tell me exactly where gas prices are going to be and coal prices, this is a pretty easy equation, but nobody has that. So we have to make those judgments as do the bondholders.

Our next question comes from Paul Fremont of Jefferies. Paul B. Fremont - Jefferies & Company, Inc., Research Division: I guess the first question that I have, I guess, relates to Midwest Gen. Given the much lower level of output that you saw in the first quarter, do you expect that to translate to the remaining 3 quarters? Or would you look at that more as sort of a one-time event in the first quarter?

Paul, this is Jim. I think with the lower prices, and given the economics, I think we've seen some lower generation generally. Now these are the ramping units for ComEd and it really depends on demand within ComEd. And so we've seen it from a high end. I think in years past, we've been as high as in the low 30 terawatt hours, and we've seen it trend down as prices have come down. And it really just depends on what's happening economically throughout ComEd. But I would wager that generation levels would be lower than historical levels that we've seen. Pedro, would you like to add anything?

Yes. The one thing that I would add is that I agree with what Jim said in terms of the perspective relative to prior years. I think your question also went to did we expect that the first quarter gets reflected in terms of how the units generate throughout the later quarters? I think we had that overlay of probably -- more likely than not that it's lower than in prior years. I would say that in the first quarter, as Jim mentioned earlier, we did have fairly unique things going on simultaneously, some higher planned outages. We had to adjust the effects of weather, including the river temperature-related curtailments. So to the extent that some of those things turn around in terms of the summer months, those unique factors won't be there presumably in the summer that were there in the first quarter. So I think the overall trend of lower than last year makes sense. So it would be good to have Fisk and Crawford, you're going to have to factor in the equation, which would lower generation levels from historical levels, certainly for a full year.

Our next question comes from Travis Miller of Morningstar.

I wanted to get to the Joliet 6 and Waukegan retrofit decision. What's the key time variable, I suppose the variable and then the timing of that variable, that you need to see to decide that retrofit? And then I guess along those lines, can you meet the Illinois CPS agreement without those units retrofitted?

I think in one of the pages that we have in the deck, it shows the timeframe, Page 34 for those that are on this call. It shows the timeframe under the CPS agreement, where we need to comply. And the Joliet station is further out. And in our plans and what we've talked about, based on what we believe is going to happen with CSAPR and what we believe is going to happen with MATS, we believe that most of the expenditures has got to be completed by the 2015 timeframe in order to comply with both state and federal requirements. So that's the key time area that we'll have the majority of all the decisions made. Now if you look in our disclosures, we try to divide the numbers between the larger units and the smaller units, so we give you visibility in terms of the cost differences between the 2. And we've added some additional information in the deck this quarter so you can break it down by plant, so you can see what the cost would be.

Is there any reason that you would go forward with retrofits before 2015 on those 2 units?

Pedro?

Yes. I think our approach all along has been in general to make sure that we are complying with the Illinois standard. And within that, frankly, wait as long as reasonable in order to build more time to test the value of the options. So I think as long as we are complying with the requirements, you'd probably expect us to continue to find -- look for ways to extend that runway.

Our next question comes from David Frank of Catapult Capital.

Ted, my question was pretty much in line with Steve's and it was about trying to gauge your comfort level given all the uncertainties that we face in the future for things like natural gas prices. And so I guess, is the strategy here just to maybe pick something really low? And if you can get an agreement on that, you go ahead? And if not, you don't.

Yes. Well, that gets into some of the judgments, which I'd probably -- I would probably prefer at this point not to go into those. I think the one other point that I might leave out there is one that I believe I made at the last call. And that is I don't think we really have a lot of interest in having EMG kind of lurch from quarter-to-quarter here. We need to, I think, really understand, is there a viable plan for EMG that allows us to make the retrofits that are economically sensible to make, reduce the debt in the order of $1 billion and have sufficient cash flow to refinance remaining debt. So it's kind of right-size the leverage and make the capital commitments that we need to make under the CPS agreement. We need to see a credible plan for that, and we need to be able to assure ourselves that EMG is viable and able to meet those objectives. Going quarter-to-quarter makes it increasingly difficult to manage the business, manage it effectively and, frankly, I don't think really helps the value for EIX shareholders. So that's really our objective, is to try to get this thing resolved, see a credible plan, take the approach we've done with other parts of this. We work cooperatively, that's always the way we start, and we work cooperatively to figure out if there is, in fact, a path and then make the decisions and move on from there.

Our next question comes from Angie Storozynski of Macquarie.

I have a question about the utility, believe it or not. Now I'm wondering, given that the rate case decision is getting delayed by so much, how does it impact your CapEx schedule? Because you have ranges of CapEx, even for this year. Should we assume simply that you are spending at the low end of the CapEx range?

Yes. Angie, this is Jim. And I'll let Linda Sullivan jump in here for further detail. We're purposely spending at a lower level because we just don't know what's going to occur. And so that's probably a good assumption. Now historically, when we've gotten delays in receiving GRCs, we watch about capital and O&M. And then so you may see times when you have -- the actual closings can lag with what you would normally expect if you've got the GRC on a timely basis. But it's really over the 3-year period that's important for the plan. And we would have a lower capital spending, and we'd hope to, over time, at least over the 3-year period, catch back up to what we thought was necessary, especially in the distribution area, because that's just spending for reliability. We want to get those dollars spent. That's the care and feeding of the overall system, and you need to get those dollars spent to maintain your overall service reliability levels. Anything else you want to add to it, Linda?

I would add, Angie, on the CPC GRC side for the first quarter, we are spending at the 2011 run rate. And then transmissions were about $75 million above where we were last year. And then the special projects are treated differently from a rate case perspective as well.

Our next question comes from Stephen Byrd of Morgan Stanley.

Just a question on the April 20 cost of capital application. In the application, you proposed an equity ratio of 48%. What was the rationale for not seeking a higher equity ratio, say, in the 52% range? There's been quite a bit of discussion in the state about that level. Just curious as to how you all think about the capital structure question.

Yes. There's a -- it's an art, probably not as much as a science, in terms of how we look at this. Going back just from when we hit the height of the financial crisis, we had access to the capital markets and were able to finance in really the depths of the ugly times. And we feel that given the access to the capital markets that we've enjoyed at the current equity ratio, that's sufficient for current needs. Now that could change dependent upon how we view the overall business. It could change on the amount of debt equivalency that we're facing because of all the contracts we enter into for fuel and purchased power. There could be other factors that I'm not thinking of now. But we have good access to capital markets under reasonable prices. And I think if we were to bump up the equity ratio, that would just add cost per customers that we don't think is a good trade-off.

Our next question comes from Terran Miller of Cantor Fitzgerald.

Two quick questions. Jim, on Page 8, when you talked about the potential offset for the $185 million payment, does that mean that EIX will end up with an IOU from EME going forward? Is that how we're supposed to think about that?

How about N-O? That's not going to happen. So Terran, just...

So it's a forgiveness?

No, no, no. I don't want to be flip on this, because it's real important. You plan and look and see what your taxable income is going to be. And taxable income can change for a lot of different reasons. So you can go up or down at the utility. Edison Capital still has some impact on the overall tax position for the enterprise, so it is constantly and monthly changing. So we gave you a number back at the end of the year. And as a result, as you roll forward in time, some of those numbers now are changing. So we will just give you a view as we see it at the close of every quarter and we'll update it. We won't get into every reason why it changed, but we're just signaling that taxable income can change and can offset some of the actual payment that EMG would normally make.

Our next question comes from Ashar Khan of Visium.

Can I just ask on the slide, why is the AFUDC lower? I thought it would be because CapEx was lower this quarter, but you were saying you're spending at the same level as of last year. Could you just amplify why the $0.03 lower AFUDC is?

Yes, this is Jim. And if I mess it up, I'll give it over to Linda. When you have more short-term debt, the way the calculation works, it lowers your aggregate AFUDC rate, which can lower earnings. I'll have to prove it to you mathematically offline, Ashar, but that's the way it works. We have more short-term debt balances year-over-year that's causing AFUDC earnings to change. So if you want to have a further discussion, why don't we call back later and we can take you through it?

Our next question comes from Kit Konolige of Konolige Research.

Most of my questions have been answered. Quick question. If you have a view on the proposal to allow the inclusion of hydro as a renewable in California, either what you're feeling is about the substance of that proposal or the likelihood of passage.

We'll have Ron Litzinger address that.

If hydro is included as a renewable, that would certainly be a positive for us in meeting the RPS standard and the amount of investment we need to make in transmission. Hydro is also much more flexible and reduces some of the pressure we would have on integration costs. So we would view that as a positive.

So Kit, just your sense for numbers. We were at 21% RPS requirements at the end of 2011 and hydro can go up and down year-after-year because this is probably a low season, last year was a high season. And large hydro was about, what did we say, 6%? In 2010, it was about 6%. So if you have 21% or plus or minus 6%, you're getting up to the high-20s now.

Our next question comes from Ali Agha of SunTrust.

Ted, just to summarize and make sure I'm understanding the message on EMG, and you've laid out a number of data points from your side. But first off, to be clear, you had previously been talking about having your decision by the summertime this year. And I wanted to confirm that is still the timeline. And then secondly, when you talk about EMG not lurching quarter-to-quarter, being viable, et cetera, should we assume that when all of this is done and assuming you get what you want, et cetera, however we get there, that EMG should be a profitable, i.e. positive earnings contributor, for EIX in the current price environment that we are in? Is that what we should be thinking?

I think we've typically made the statement that we need to be able to meet the capital requirements, the retrofit capital requirements under the CPS agreement, and more recently, U.S. EPA rules. Number two, that we can delever EMG. We've typically used this number, around $1 billion of debt. And that the subsequent cash flows in the business would allow credit metrics such that we could refinance the remaining debt when it comes due. So those are kind of the key markers, which are not really earnings-related markers, or if anything probably a little more related to EBITDA. But that to us would really spell a stabilized business that's able to meet its obligations and have positive cash flow, which I think ultimately translates into positive earnings. The exact timing on all of those, that's a little harder to predict at this point. But those are the key markers that we've typically laid out there. The conversations that we would have with all the other stakeholders, they're going to come to the table with things that are important to them. But those are the ones that kind of most on our mind.

Our next question comes from Michael Lapides of Goldman Sachs.

SCE, can you refresh us? What is the base FERC-authorized ROE on transmission? What would you describe as your weighted average concerning the incentive that some of your projects have ROE? And when is the next filing or docket process where the base ROE could be up for revision?

Okay. Michael, I'm going to have Linda Sullivan grapple with all those questions.

Michael, this is Linda. The base ROE that is currently in rates is 9.96%, and then we add to that the Cal ISO incentive of 50 basis points and the project incentives, where we get into a weighted ROE of 11.1%. That's currently in rates that is subject to refund and settlement procedures. And we are in that process right now.

And what's the docket schedule for the next review of -- or what's a likely docket schedule for the next review of the base level ROE?

The next -- well, we're in the current schedule with the settlement procedures, where the next proceeding is expected in the June timeframe.

Your next question comes from Jay Dobson of Wunderlich Securities.

Ted, I wanted to come back to timing a little bit on EMG. And I guess, as we all remember sort of, I guess, just about 9 months ago, you set that 6- to 12-month timeframe. And as I think you just responded, you're going to be pretty much on track there. As we start and turn the page or maybe turn the chapter to what now is going to be a new timeline, and I know there's as much uncertainty now as there was 9 months ago, how do you see this playing out from a time perspective? I imagine the bondholders on the phone may have their own views of that. But how do you see with the idea that the 2013s in June or so create sort of their own ending, if you will, as far as the process?

Well, certainly, the maturity in middle of next year is something of a forcing function. But our intent is not to wait until June of next year. So the 6- to 12-month kind of marker that I put out there last summer, I think, still represents pretty much the right timing. So we've been getting more and more information. And as we've gotten that information, we've made some decisions, such as the Fisk and Crawford decisions, which clarify a little bit what some of the CapEx requirements are going to be. In a few weeks here, we'll hear where we are on the capacity prices, which I think will be important when you look at those in the context of last year's auction. So I think we're pretty much on the schedule that I mentioned, and most of the information that's relevant to making important decisions for us, as well as for the bondholders, other stakeholders, I think most of that information is either on the table or about ready to hit the table.

Our next question comes from Jason Mandel of RBC Capital Markets.

Just 2 quick questions. First off, on Capistrano Wind, just so I understand the dollars in and dollars out, there's some timing issues with when money gets paid and gets spent and whether or not there would potentially be any impact to those dollars from a restructuring event at EME. And the second one, just basically on the capacity auction and plants that are being bid in and process-wise, how that works in the event that the capital spending is either not there or doesn't make any sense in the future and basically can't be met.

Well, let me take it in reverse order. This is Jim. And then I'll look over to the EMG folks for a little help on Capistrano numbers. But we'll anticipate bidding in our plants on a normal course, and we're working down that path now. And I'll stop there because I think we gave you the key message. And Maria and Pedro on Capistrano, the ins and outs.

On Capistrano, the investors paid $230 million for the 3 operating projects that have been now become part of Capistrano. Subsequently, there are 2 construction projects that will at COD and conversion from construction financing to term financing be contributed down into Capistrano. At that point in time, there's another $140 million earmarked, which will reimburse CME for any equity contributions. As Jim noted earlier, those projects have been also project-financed, and the debt on those projects will go towards the balance of the construction costs.

Your next question comes from Angie Storozynski of Macquarie.

I actually had a question about San Onofre. We see some indications that San Onofre 2 is supposed to be back online on June 2 -- well, 1, actually, and then the Unit 3 back on June 12. But I understand that the NRC needs to voice its approval for the units to come back. I mean, could you talk us through the process and how likely this NRC will be comfortable with the solutions that you're presenting them with?

Angie, we're going to have Ron take you through that.

I believe you're looking at what we've posted with the California ISO on the returns to service. And we update that periodically. We are currently, as Ted mentioned, evaluating the causal analysis and where we might go with the -- responding to the Confirmatory Action Letter. But we will likely update those numbers within the next couple of weeks with CAISO that are officially posted.

Our next question comes from Terran Miller of Cantor Fitzgerald.

Second question is, Jim, EM -- Capistrano, does that sit at EMG? Or does that sit at EME? And second question is the $98 million of proceeds from the project financing, is that cash available to EME? Or does that go with the project? It sounds like in the last time, it goes with the project to complete the project.

On the latter one, yes. Maria?

In terms of the ownership structure?

Yes.

So Capistrano is indirectly owned by EME.

Indirectly owned by EME.

Correct.

Our next question comes from [indiscernible] of JPMorgan.

So the 2013 notes mature obviously a year from now, but the Midwest Gen credit facility expires next month. What are your plans with regard to that?

The Midwest Gen revolver, we've said in the disclosures that, in fact, there is hardly any usage on it, and it will likely just expire on time. And so we have plenty of cash currently at this time at EME, and we'll use that cash really to take care of our working capital requirements. And we don't at this point in time have a plan in place to put any kind of replacement revolver. And part of the big picture here is working to figure out how we're to work with the bondholders before we have the maturity that coming up. Now the disclosures do show that we have -- thank you, Scott -- an LC facility in place, a cash-collateralized LC facility, to take care of some of the requirements we have with the things that go on, admission, to back up the trading shop, and other requirements. And then we've disclosed that in terms of the usage in our current quarterly report.

The last question comes from Raymond Leung of Goldman Sachs.

Just following up on -- just questions about flowing of cash. But related to Walnut Creek, have you guys made the entire equity contribution? If not, how much more do you need to put out there and over what timeframe?

Yes. The equity went in first, and now we're drawing down on the facility to cover the construction expenditures, Ray.

Okay. So you're done funding that. That wouldn't be another cash drain.

Correct.

That is the last question. And I will now turn the call back to you, Mr. Cunningham. Go ahead.

Great. Thanks very much, everyone, for joining us. And please don't hesitate to call us at Investor Relations if you have any follow-up questions. Thank you. Goodbye.

This concludes today's conference. Thank you for your participation. You may now disconnect.