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Executives

Janet T. Clayton - Senior Vice President of Corporate Communications

Theodore F. Craver - Chairman, Chief Executive Officer and President

Ronald L. Litzinger - President of Southern California Edison Company and Director of SCE

Edison International (EIX) San Onofre Nuclear Generating Station Update Conference June 7, 2013 12:00 PM ET

Operator

Good morning, my name is Marcella, and I will be your conference operator today. At this time, I would like to welcome everyone to the San Onofre Nuclear Generating Station Medica Teleconference. [Operator Instructions] Today's call is being recorded. I would now like to turn the call over to Janet Clayton, Senior Vice President of Corporate Communications. Thank you, Ms. Clayton, you may begin your conference.

Janet T. Clayton

Thank you, Marcella, and good morning, everyone. With me today are Edison International Chairman and CEO, Ted Craver; and Southern California Edison President, Ron Litzinger. We conducted a teleconference with investors earlier this morning, and those materials are available at our website at edison.com. We'll make some brief remarks and then open it up for questions for Ted and Ron. [Operator Instructions].

With that, I'll turn the call over to Ted.

Theodore F. Craver

Thanks, Janet. Good morning to all of you. I assume you've seen our announcement that we've decided to no longer seek restart of Unit 2 and Unit 3 of our San Onofre Nuclear Generating Station. The principal reasons that we've outlined for that really are the continuing uncertainty around the future of the plant and what the approval process would be and particularly how long the approval process might continue to be.

The other part of reason is that while when we [indiscernible] that restart plan to the Nuclear Regulatory Commission [indiscernible] to continue [indiscernible]. Over time, that economic advantage diminishes and at least, our estimate is that by the end of this year, it would really no longer be the lease cost alternative because while the plant sits idle, we have to pay for replacement power cost, as well as continue to pay the operations and maintenance costs of keeping the plant in the ready to restart when the approval would come through. And those kind of doubling up of costs really erode the lease cost advantage over time.

So for those reasons, again, to clear out the uncertainty and move forward in a decisive way, as well as reduce the drag that was continuing from having the -- the economic drag from having the plant, we decided to no longer seek restart and close the plant.

So perhaps, best use of the time here is to answer the questions that you have on your minds. I have with me Ron Litzinger. And between us, we should be able to fill the questions you have.

So operator, I guess, we will open it up to questions from the group.

Question-and-Answer Session

Operator

[Operator Instructions] The first question is from Rebecca Smith of the Wall Street Journal.

Rebecca Smith

And could you kind of walk us through what the process will be now in terms of retirement and then eventually decommissioning, and also tell us how much you've got in the decommissioning fund? I think it's quite a bit of money. But could you walk us through that?

Theodore F. Craver

Yes, sure. In terms of the decommissioning fund, that's kind of the straightforward facts. I think you know how that kind of works. We regularly contribute to the fund, it's sitting now at about $2.7 billion. That's on an after-tax basis. And we're also constantly updating what the cost will be for decommissioning. And in fact, we're about ready to submit another set of updates on what decommissioning costs will be in the future. So at this point, it looks like it's around 90% funded with a balance of about $2.7 billion. The other part of your question is a little harder to answer in terms of what exactly is the process. But the kind of the critical one is the NRC considers the plant to still be an active operating plant until the nuclear fuel is taken out of the reactor and put into the spent fuel pools. So that's going to take a little while to do that for Unit 2. That's already been done for Unit 3. So within, I'll say, a matter of weeks to a few months, that should be completed. At that point, it then kind of moves over to a different part of the NRC regulatory oversight as a plant that's being readied for decommission. But there's a whole series of notifications that have to be made to the NRC along the way, and kind of the final point is full decommissioning of the site is going to be a multi-decade process. So this is a very long process to be fully decommissioned. Rebecca, does that get to...

Rebecca Smith

In other words, the plant is going to be there for a long, long time, and there's going to be fuel in wet or dry storage for a long, long time, correct?

Theodore F. Craver

Yes, correct. The way -- really the vast majority of the nuclear plants in the industry are currently configured is after the fuel is cooled down enough in the spent fuel pools, it then goes into some form of dry cast storage, goes into stainless steel canisters and then is laid up. So we have fuel both in our spent fuel pools and we also have fuel in dry cast storage. Until there's a permanent solution to storing spent fuel -- the spent fuel rods, it's largely going to be managed by dry cast storage on-site at the nuclear plants. So this, as you say, it will be -- until there's a permanent solution for that, this will be on-site for a very long time.

Operator

Our next question will come from Matt Wald of the New York Times.

Matthew Wald

In 20-20 hindsight, where did you go wrong?

Theodore F. Craver

Well, I think the -- obviously, the issues at the steam generators have not performed as the original specifications. So the design and manufacture of the steam generators, clearly, is not performing the way they were specified. So that's, I think, kind of the core of it. Like any of these kinds of circumstances, I'm sure we can find lots of things that if we could roll the clock back, we would try to do a little differently. But I think that's kind of the nub of it.

Matthew Wald

To follow up, did your company limit the engineering questions had asked and the review it did of this proposal in order to avoid having to go for a license amendment for new steam generators?

Theodore F. Craver

No. The whole process that's been used for replacing steam generators in the industry is a pretty well-traveled path. After the first few were done several years ago at other plants, the so-called 5059 process was established. And essentially, I'd like to think of it as a test. It basically says, if you have essentially the same form, fit and function, as the previous steam generators, then you can go forward with the so-called 5059 process. When we went through that analysis, which takes quite some time to do, we determined that much of it was really standard and could go through a 5059 process. But we actually did need to obtain some license amendments to our technical specifications and our license. So it's -- the 5059 process is basically, as I say, is kind of a test. If you go through that analysis and you determine that, yes, what you're proposing is essentially the same form, fit and function as what you had in there before, then you can go forward with the replacement. Anything that's outside of that has to go through a license amendment process. So as I said, we actually had a little bit of both in our case.

Matthew Wald

And you don't think you'd have benefited by doing a more thorough review upfront that might have uncovered that these steam generators were prone to the failure mode that's developed?

Theodore F. Craver

I guess -- and thinking about this, we have to ask ourselves that question. I think the general sense we have is this was such a unique phenomenon that I'm not convinced a more thorough approval process would have uncovered the technical engineering issue, the so-called fluid elastic instability. That's obviously the question, I think, we've asked ourselves and others will ask. But the best sense we have of it is the technical nature of that would not have really been identified in a lengthier process because really, the technical issue is a first-of-a-kind, unique circumstance.

Operator

Next, we have a question from Abby Sewell, Los Angeles Times.

Abby Sewell

Ted, can you talk a little bit about what this means in terms of energy planning for Southern California, and also about how Edison is going to proceed with the cost issue?

Theodore F. Craver

Yes, let me do a few comments on this, and I'm also going to ask my colleague, Ron Litzinger, to talk about some of the reliability planning, resource planning. First, I think, this is very much part of that uncertainty that I was talking about that we are really anxious to resolve and focus on going forward. I did have some conversations with the governor and the president of the California Public Utilities Commission in the last couple of days really around this point. So I think you will see shortly, some intensity and a sense of urgency around getting California Independent System Operator, the California Public Utilities Commission, California Energy Commission, perhaps AQMD, the 2 utilities that are involved here, San Diego Gas & Electric and ourselves, and probably others to really sit down and focus on the long-range planning requirements. One of the toughest parts about having to make the decision here to no longer seek restart is that nuclear plays a fairly unique role, particularly here in California, in our energy mix. It's the only large baseload, nonfossil fuel generating resource, and particularly given the state's goals on greenhouse gases and global warming, nuclear, which represents around a little less than 20% of the total fuel mix in the state. Now that's -- a chunk of that is now out of the mix and it will have to be replaced. It will be difficult for it to be replaced just with renewable resources because the nuclear is dispatchable, which means we can determine when it needs to come on, and it's a major resource in a very important part of the grid. So all of those things are lost with the decision here to no longer seek restart for San Onofre. And we need to figure out how we're going to kind of rebalance the mix of resources, not only for generating electricity but for maintaining the integrity of the grid, the voltage regulation on the grid. I'm going to ask Ron to maybe pick up a little bit on that because your question really goes to a very essential part of what we'll be focusing on over the next several years.

Ronald L. Litzinger

Yes, thanks, Ted. You really hit the nail on the head with regards to the long-term planning. We will be working with CAISO, California ISO, the California Energy Commission, the Public Utility Commission going forward. We've already even had conversations this morning on that topic. We've eliminated a key uncertainty going forward. We had already been, for many years, in discussions of replacing the generating capacity at the existing coastal units, which were slated for retirement giving -- given water quality regulations. And so with San Onofre being sort of thrown into that existing planning mix, it increases the challenge. The first step is to determine what generation will replace those coastal facilities and San Onofre. And then, depending on where those generation resources are located, we may need to plan for transmission lines as well. If the bulk of the generation is located inside the Los Angeles Basin, there will be little need for transmission. However, if a significant portion of that generation ends up outside the basin, then we will need to add additional transmission lines. Both of those take -- generating stations and transmission lines take a long time to permit. So it's best we get started right away planning for that future. In the short term, Ted had mentioned voltage concerns. South Orange County has relied heavily on San Onofre being there, close to the load. We do have sufficient generation located in the broader Southern California area. It's how we're able to deliver that energy into South Orange County through the existing transmission system, which can get strained. We've done a lot of transmission upgrades, both last summer and this summer. We feel we're in pretty good shape for this summer coming up. Barring we don't have an unusually hot summer, wildfires that take the transmission line out or unexpected generation outages, we should be pretty good on the voltage in Orange County this summer.

Operator

Any further questions Ms. Sewell?

Abby Sewell

Yes. And could you also talk about the cost issue, how you're proceeding with that with Mitsubishi or through insurance or other means of potential cost recovery?

Theodore F. Craver

Yes, Abby, I'm going to be pretty limited on what I can say about where we are with Mitsubishi. But if I can maybe just drop back one step and talk more broadly about what we have here. There are kind of essentially 3 buckets of costs. There are replacement power costs. There are what we call O&M, operations and maintenance, costs to maintain the plant. And then there's the investment that's been made in San Onofre. So those are kind of the 3 buckets of cost. I mean, essentially, the cost recovery process will focus on 4 sources for picking up those costs or recovering those costs. The traditional way, of course, is all these costs are passed through to the customers, to the ratepayers in the form of our rates. Additionally, Mitsubishi, because as we've made clear in previous statements we have -- we believe significant claims there. We do have an insurance carrier for the nuclear industry called NEIL, N-E-I-L. We have claims that we've submitted to NEIL. And then, of course, the fourth is the shareholder. So those are the 3 buckets of cost and the 4 potential sources of recovery.

Operator

The next question is from Pat Brennan of Orange County Register newspaper.

Pat Brennan

I was wondering if you could tell us how this will affect the workforce at San Onofre? How many more layouts might there be and how many have there been so far?

Theodore F. Craver

Yes, I'm going to ask Ron Litzinger to cover those pieces.

Ronald L. Litzinger

Yes, we currently have approximately 1,500 employees at the facility. Over the next couple of months, we will be reducing that to approximately 600 personnel. And then, we will make some applications to the Nuclear Regulatory Commission to modify our emergency response plans and our security plans to reflect a facility that is in a shutdown condition rather than an operating condition. And then, once those 2 plans, the emergency response plan and security plan, are approved, we will then reduce the staffing down to 400. We would still be able to properly secure the facility with that 400 and respond to any incident that could occur for a facility in that shutdown condition.

Pat Brennan

And can you say how many layoffs there have been so for? And I'm taking it, the layouts that you just talked about will be more than was initially projected a few months back.

Ronald L. Litzinger

That's correct, Pat. In our 2012 rate case, we had put forward that we were going to reduce the forces at San Onofre such that its staffing was more consistent with other 2 unit nuclear stations throughout the country. That resulted in a reduction of 730 personnel. Again, that was planned several years ago. It was implemented this year. And then the numbers I just -- that's how we got to the 1,500. The numbers that I gave you going forward are a result of the shutdown.

Operator

Next we have a question from Michael Blood, the Associated Press.

Michael Blood

As you know, the company made a number of changes between the original steam generators and the replacement steam generators. Those changes included adding 377 tubes to each of the replacement generators. The replacement generators weighed nearly 24 tons more. There were -- there was larger surface area, there were changes to the tube supports. What I'm wondering is what was the goal of the company? Did you want to run at a higher power, or what -- why were all these changes made compared to the originals?

Theodore F. Craver

Yes, well, first, maybe we can clear up one piece. This term of like-for-like is actually something I'm not really exactly sure why that's even grown up. It's not in the 5059 regulation. There's no such term like-for-like. The term is really that the new equipment has to be the similar form, fit and function to the equipment that it's replacing. So there is no like-for-like. And in this case, in the nuclear industry, steam generators have had an issue really across all of the plants, the vast majority of the plants, what they call cracking and corrosion of the tubes. It was determined many years ago that the principal cause of that was the alloy, the type of metal that was used in steam generator tubes, so-called INCONEL alloy 600. So that -- it was determined that the way you could solve the cracking and corrosion problem in those nuclear steam generators was to use an improved metal INCONEL alloy 690. However, that tube metal also does not conduct heat, as well as the previous metal. So all of the steam generator replacements that have been done in the industry over the last many years really are to improve a problem with the metal and the cracking and corrosion. So you certainly wouldn't want to put the same stuff back into the steam generators because you're just going to have the same problem. And that's where the improvements in the metal were made. Again, because the metal doesn't conduct heat as well, really you end up having to put additional tubes in there, so that you can get the same type of heat transfer in the steam generators. So really our -- there's no additional power consideration here. It was really to address a cracking and corrosion problem. In fact, in our case, the 2 steam generator -- or the 2 units, Unit 2 and 3, had we not replaced the steam generators, one of those units would have shut down in 2012, and the other unit would have to shut down in 2015. So they were really at a critical point, where you could no longer plug the tubes and maintain safety. So they had to be replaced, and that's what we did with the improved metals so that we could avoid the cracking and corrosion problem.

Michael Blood

And just as a follow-up, does Edison have any plans for building any new plants here as replacements? Has that been discussed, or is it a possibility?

Theodore F. Craver

We haven't really come to any final conclusions on that. I took your question to mean any kind of plant. And so we really haven't come to any conclusion on that. We largely, here in California, have generations supplied by third parties. And the utilities themselves, typically, do relatively little of building and owning and operating their own plants since the deregulation started in the late '90s. So we'll have to go through that process, that will be part of this planning process that Ron was talking about. And I think our operating assumption is we focus the vast majority of our investments on maintaining the electric grid on the so-called wires part of the business. So the transmission and distribution represents about 90% of the investment dollars that we put into the system every year; and generation and all of the other things, kind of general plant and equipment, represents around 10%. So I think our focus will continue to be strategically on making sure that we have a solid distribution system that is robust and capable of supporting many different kinds of generation, including distributed generation and renewables.

Michael Blood

Okay. And so just to clarify, again, I'm sorry, the question of new plants, you said no decision has been made and that would include any range of plants whether gas-fired, nuclear, what have you, did I that follow that correctly?

Theodore F. Craver

Yes.

Operator

Morgan Lee, from San Diego Union-Tribune.

Morgan Lee

First off, I wonder if you could -- I'm not sure if you mentioned the cost of the actual steam generator replacement project, which I think has been submitted for over $700 million. How that will be treated? And secondly, if I might, some recently released documents by Edison officials show that there were concerns about the steam flows and anti-vibration bars, some of the things that came to pass as far back as 2004 and 2005. Can you talk about why those problems couldn't be resolved?

Theodore F. Craver

Yes, so it's still on the dollars and cents piece first. Actually, the numbers that we showed to our investors this morning is that the steam generator replacement project, the approved amount was $665 million, this is for us, for our part of the plant, and incurred to date $602 million. In terms of -- I'm not sure I completely got the second part of your question, but it sounds like you want to know about steam flows and the steam generators?

Morgan Lee

Well, it was just -- it's sort of another 20-20 hindsight question, that some of the problems in terms of the dry steam is the fluid elastic instability, where there were signs that there were concerns there early on in the design phase, it looks like, and also about this part of the bundle at the top of the tube bundle. So I just wonder if you can talk at all about, in hindsight, why that couldn't be fixed if it was spotted so early? I'm asking because this sort of just came out.

Ronald L. Litzinger

Yes, if you review the letters and the design reviews we did, those issues were challenged and brought up with Mitsubishi. They subsequently responded back and assured us that those issues had been addressed.

Morgan Lee

Okay. And just one small follow-up. Edison supposedly was part of the design team and followed up deeply in meetings. Did its engineers try and help them solve that?

Ronald L. Litzinger

Our engineers, as a owner and a purchaser of equipment, the normal practice in the industry is you review and make comments. But the manufacturer is ultimately responsible for and qualified for the design.

Theodore F. Craver

If I might add one piece in here. So I think this is really an important concept. We are the licensee, Southern California Edison. So the Nuclear Regulatory Commission looks to the licensee as the responsible party. It's our responsibility under that when we use vendors, whatever the vendors might be doing for us. And as you can imagine, we use a lot of different vendors and buy a lot of equipment that's throughout the plant that comes from third parties where we haven't designed it, manufactured it or whatever. And so the Nuclear Regulatory Commission and the industry has a phrase they use, they refer to it as intrusive oversight. And I think the simplest way to think about that is it's not a matter of Southern California Edison just writing down on a piece of paper, here's the basic specifications that we want. You go out, design the thing, manufacture the thing and ship it over to us when you're finished, and we'll put it in. If we took that approach, what I would call a passive or hands-off approach, we would be very much derelict in our responsibility as the licensee. So it is expected, and indeed, in this case, we did become very active with the supplier, in this case Mitsubishi Heavy Industries, through this process of intrusive oversight. We actually look at some of the letters and other discussion that's arisen here in the last few weeks as indeed a demonstration that we performed our responsibility of intrusive oversight correctly. So it isn't a matter of simply handing somebody your specification sheet and saying, "Make it for me and bring it to me." We have to be very actively involved, questioning, challenging, asking for proof and all of those things. In fact, we're done here.

Morgan Lee

The only other question was, San Diego Gas and Electric consulted on this decision?

Theodore F. Craver

Yes.

Operator

Mark Chediak of Bloomberg News.

Mark Chediak

A question here regarding certain possible head to shareholders here. You guys disclosed some figures in your release. But what is -- ultimately, what could shareholders ultimately be on the hope for here regarding cost recovery? It sounds like that's going to be decided largely by the CPUC. And kind of the second part of that question is when do you see some clarity from the CPUC on cost recovery?

Theodore F. Craver

Yes, great questions. So let me try it this way. In terms of the final determination, it is, as you suggested in your question, that will be a matter of resolving the order instituting investigation on San Onofre that the California Public Utilities Commission started back in November of last year. So we don't have an exact -- there's no way to have an exact idea of what potential liability to shareholders could be until we get all the way through that process. I saw earlier this morning that President Peevey from the PUC has urged, I think, it was the word he used, parties to get together and try to work out some sort of a settlement of all of these items and bring it to the commission. But whether it goes through that kind of a process, a settlement process, or it goes through the standard litigated process, in the OII proceeding, we will end up eventually with an answer to the question. But as of today we don't -- we really don't have a way to approach that other than by looking at the handful or so of precedents that exist with the somewhat similar circumstances. So for instance, San Onofre Unit 1 was decommissioned early. And in fact, if I remember it right, it was -- there was a steam generator issue involved there. So that gives a precedent. The Mojave plant gives a precedent when that was retired early. The Geysers, another plant, a hydro -- a geothermal plant, and so on. There, a handful of these different precedents that have taken place over the years here in California. And when you look at those precedents, you get some idea of how these things have been resolved in the past. Using those precedents and a margin of conservatism, we made an attempt to estimate that, in fact, we're obligated, as you know, to do that under GAAP accounting rules, Generally Accepted Accounting Principles. So we did that. We talked to our investors about all of that this morning and that's what gave rise to the $450 million to $650 million range for an impairment. And it's also what gave rise to us reducing our earnings outlook for the year by $0.20 earnings per share. It was really based on those precedents and -- but we won't know the exact answer until we get all the way through the process. Sorry for the lengthy answer.

Morgan Lee

That's all right. And just one quick follow-up question. If it is litigated through -- if it just end up [ph] just being litigated, does the company have a sense on when that -- could that ultimately may be resolved by? Or does that still remain to be determined?

Theodore F. Craver

Yes, it's only a swag. And the swag comes from -- when the commission combined a number of issues into the single proceeding, they indicated that time that the final phase, there are 4 phases to this OII proceeding, that the final phase should be completed by the end of next year. So I don't -- don't take that as a quote, but that's -- that was the rough guideline they gave on timing. But that said, we haven't really come forward with a specific schedule yet for anything other than the first phase of the 4 phases. So the best info we have at this point is sometime next year if we went through the full litigated process.

Operator

Eileen O'Grady of Reuters.

Eileen O'Grady

Mr. Craver, you mentioned the double costs at San Onofre and the uncertain -- uncertainty about the timing of the restart for making this plant uneconomic or not having the nuclear advantage any longer by the end of the year. But actually, when is 70% -- how would your 70% plant have faired against that? Surely, operating at 70% for 5 months and not really knowing the future was also not really a good plan economically.

Theodore F. Craver

Yes. Actually, the way we evaluated that was as part of the conservatism and baking in additional safety margin, we determined that we could stop the fluid elastic instability by running the unit at reduced power. The point of the 5 months was to be extra cautious on how long that we would actually run the plant before taking it down and reinspecting all of the tubes again to ensure that we were not having the fluid elastic instability reoccur. The intention, of course, would be once we went through that inspection that we would put the plant back in service and for some period of time, continue at a 70% power. I think, we had in our minds that perhaps that power to be moved up, that power level to be moved up over time. But when I made the comments about the -- evaluating the alternatives, we assumed Unit 3 would not operate and that Unit 2 would operate at 70% power for the remaining license period. So that means out until 2022. And the total costs associated with that, without worrying about, in the analysis, how it might be dillied up between ratepayers, Mitsubishi and all the rest of the stuff, but just the total cost of that alternative was less than the total cost of the other principal alternative, which is to shut both units down and buy the power out of the market. So that -- when I made the comment in the investor call this morning, that was the way the analysis was done. So it did assume 70% power through each of the subsequent fuel cycles, all the way out to 2022. And it did assume Unit 3 would be shut down. That was still less expensive than the alternatives. The problem is the longer the plant sits idle, waiting for a definitive yes-or-no answer, we're racking up, in a sense, double cost. We have the replacement power costs, but we also have the cost to keep the plant ready so that we could restart it when we got approval to do so. And that double cost ends up eroding that cost advantage over time, plus every day you delay, you have one less day that you can run the low-cost alternative. And so it creates a crossover point. And roughly speaking, that crossover point was at the end of the year. So the evaluation became, okay, we know we're tripping away at the economic advantage every day that it delays -- restart, what is the -- what is our view of the reality of getting through the approval process and all the kind of inevitable legal challenges, appeals, the emotions and what have you, even after the NRC staff would approve the unit restarting. And our conclusion was we couldn't get through all of those different components of the process by the end of the year. And in fact, it could very well be late into next year or even after that. And that risk just wasn't worth continuing to push this thing forward and continue to rack up those costs.

Eileen O'Grady

What do you hope happens with the investigation sort of being called for now with this decision by the politicians and the state?

Theodore F. Craver

Well, I assume whatever those requests are will continue to work their way through. The ones that we've been focused on are really all the process with the NRC.

Eileen O'Grady

Right. Do you have enough dry gas -- room in your dry gas storage for all the fuel that you would need to move there eventually?

Theodore F. Craver

Yes.

Operator

Kevin Smith of Los Angels News Group.

Kevin Smith

Ted, quick question. You've talked, sort of in general terms, about how you have to ensure the integrity of the grid and make sure that you have enough power. When you talked about San Onofre, of the power you provide all your ratepayer or your customers, what percentage did that provide out of that mix?

Theodore F. Craver

About 17%.

Kevin Smith

Onofre, about 17%. Okay. And then realistically, I know you said you haven't, you don't have any specific plants or new plants of any kind, but what would it take, whether you have those plants formalized now or not, what would it take to fill in that gap in your mind? I mean, how would you best characterize what you would need?

Theodore F. Craver

Ron, do you want to take a shot at that one?

Ronald L. Litzinger

Yes, that would be a combination of gas-fired combined cycle plants and a few gas-fired peaker plants within the basin. A portion of that energy could be covered through the renewable projects that are coming online. So it would be sort of a combination, but you'd have to fill in for that 17% energy need. And then the more critical question I had mentioned earlier is depending on where those plants are located, we may have to add additional transmission lines.

Theodore F. Craver

Kevin, one thing it might be worthwhile to have in mind here, in Southern California, Edison today buys about 2/3 of the power that it delivers to its customers. And it self produces the other 1/3. So using the numbers I was talking about before, with San Onofre being in around 17% of the energy that we deliver to customers, that mix will now become even more skewed. It will be getting close to 7/8 of the power that we deliver to customers will be purchased and about an 8 or so will be self generated.

Operator

Dan Morain, Sacramento Bee.

Dan Morain

Asked and answered.

Theodore F. Craver

That was the easiest question yet.

Operator

Next up is George Lobsenz, The Energy Daily.

George Lobsenz

I wanted to ask how important was the CPUC investigation and particularly the adverse initial decision from the ALJ there on cost recovery, how important was that to your decision-making on disclosure.

Theodore F. Craver

Maybe just a little clarification. So the CPUC, if I'm thinking about the same thing that you are, the CPUC really hasn't come to any conclusions relative to San Onofre. So we don't have any proposed decisions here at this point. And we're very early in that process, that's the Phase 1 of the 4 phases. So I think really all of the kind of the economics, if you will, the financial aspects of cost and cost recovery, those are still basically in process. You're referring to some of the Nuclear Regulatory Commission decisions, really the critical one for us is the one regarding restart of Unit 2. That's the plan we put before them and they still are in the process of -- or have been in the process of asking technical questions, so-called requests for additional information and we've been responding to those. So no decision really had come forth from the NRC staff. The final thing that has happened was the Atomic Safety and Licensing Board ruling that came out on May 13. And absolutely, that was very definitive for us because that's the ruling that made clear we're going to have a much more uncertain process. And as a result of that uncertainty, there were going to be many more opportunities for various state motions, appeals and we could foresee a very long involved process to get to a final yes-or-no decision on our restart plan.

George Lobsenz

Okay. But on the CPUC process, clearly, the -- what was happening there raised the prospect that you would not be able to recover a lot of these costs of the outage at San Onofre and obviously, those costs were piling up with replacement cost as time went by. So even though that was in a very early stage, was that not a major consideration that you -- a lot of these costs as they continue to build, that you would not be possibly be able to recover them?

Theodore F. Craver

Yes, first off, no decisions were made there. And it's just -- It is an ongoing proceeding. It will have, I'm sure, a lot of length to it and it'll have -- it's a typical litigated process before the PUC. But I think I'm getting a little better understanding of the issue you're trying to get to, and I think the answer is, yes, because the shareholder, in a sense, is underwriting the regulatory risk of what the final cost recovery will be. That meant that these costs that I was talking about that we're adding up, without clarity about when the unit could restart and without clarity about how those costs were ultimately going to be recovered. That meant that the shareholder is effectively underwriting that risk. And as we said in our first quarter earnings call to investors, we -- that's when we highlighted the end of the year as the critical time when the low-cost alternative of restarting the plant was going to crossover with the alternative of shutting it down and buying the power out of the market. And we also said, we are -- we and the shareholder are picking up this regulatory risk. We're underwriting this regulatory risk. So I think that's the point you were trying to get to. It doesn't mean that we would end up picking it up. But it does mean that we are going to end up underwriting that risk until there was clarity on what cost recovery would be.

George Lobsenz

And just one last question. Would this process at the NRC become politicized? I mean, and perhaps, overly politicized here in your view, in terms of pressures being brought to bear on the NRC. Do you think that was a major factor in this case?

Theodore F. Craver

It's a fair question, but I'm going to be frank with you, I just don't see a lot of mileage in kind of going and wringing our hands over this part. I mean, what we really need to be focused on is eliminating the uncertainty, controlling the things that we have some influence over. We've done that with our announcement today. We want to focus on how do we move forward in a positive way here, a responsible way. I think that's already underway. We already have the key groups working on how are we going to ensure the reliability of the electric system for our customers. I mean that's really -- that's why we exist, that's what we do. So that's where we want to be on this rather than kind of looking what the other kind of political issues might be on this.

Operator

You're next question will come from Dan McSwain, UT, San Diego.

Dan McSwain

I'm with the San Diego Union-Tribune, so we're double dipping. I'm trying to get a handle on all of the costs. And at the PUC proceeding, you talked about the 3 buckets. Do you have a running tab, including projected replacement power cost of that total figure? This would include the steam generator replacement, the unrecovered costs at San Onofre itself because you have made improvements over the years, and also the replacement power that's going to be decided at the PUC. What's that total figure that either ratepayers or shareholders or some of both are at risk for today?

Theodore F. Craver

Yes, that's a good question and like a lot of things in regulatory rate-making, are reasonably complicated to answer. Let me try to start with one piece. The steam generator cost was the number I gave a few minutes ago in one of the other questions. So the approved amount that relates to Southern California Edison, the approved amount was the $665 million for the 4 steam generators. The amount of money incurred to date under that was $602 million. So that's one part. And kind of the next piece up is what is the total investment that we have in operating plant. So this number is about $1.2 billion. So about 1/2 of that is the steam generator cost and the other 1/2 is, what we call, balance of plant. And there are a bunch of other components which really get into the arcane world of regulatory accounting, but something called Construction Work in Progress, or CWIP, there's also nuclear fuel and inventory. So when you throw all of those components in, you end up with an asset number, related to San Onofre, of about $2.1 billion. So I'll call that the investment in the plant.

Dan McSwain

And that includes the steam generator and the...

Theodore F. Craver

Steam generator, balance of plant, Construction Work in Progress stuff and nuclear fuel and inventory, whether on-site or off.

Dan McSwain

So that's the total asset figure.

Theodore F. Craver

Yes. That's $2.1 billion. The other numbers that you talked about were things that relate to replacement power costs, that's a little easier to put a handle on. Since the initiation of the OII, the Order Instituting Investigation in San Onofre, that number is now about $264 million. If you go all the way back to January 1, which is a date that is mentioned in the OII, that number is about $529 million. And then you're going to be sorry you asked this question. Then all the other stuff which includes O&M, operations and maintenance cost, includes the return on the investment, which is what we recover in rates, that is the component that is "our profit." And a number of other components, all of that, since November 1, when the OII was instituted, is about $270 million. If you go all the way back to January 1, 2012, that number is a little over $800 million. So you could say between the monies that have been collected in rates, that we've already collected, that are subject to potential refund, those numbers are some of the $800 million that I mentioned and the $529 million. So let's call it roughly $1.3 billion. And the investment in the plant, including the steam generators, all the rest of the stuff, the construction work in progress, the nuclear fuel, all of that is $2.1 billion. Are you sorry you asked the question yet?

Dan McSwain

Well, no. It's a big number, and this is all going to be handled in this 4-phase process in your view?

Theodore F. Craver

Yes. In some form or fashion, yes.

Dan McSwain

Okay. Just one follow-up, if I may. Did Edison, along with its subcontractors, do a cost-benefit analysis that goes like this: we think we know what the problem was, we could build a couple of new steam or tube arrays, I guess there would be 4 of them, and we could install them -- my understanding is that the steam generator or the steam tube array could be replaced without cutting a new hole in the domes. Put simply, was there a cost-benefit analysis done on what it would take to fix this plant and go back and try to operate it for another 30 years? Putting aside the rate -- I mean, clearly, your decision was driven by regulatory, political and economic uncertainty and along with power prices out in the market. But did somebody sit down and pencil out what it would take to fix this at both units? Or is -- were both units judged to be unfixable?

Theodore F. Craver

Actually, embedded in your question was kind of a principal answer. You've mentioned we'll fix it and run it for another 30 years. We have a license. Without the license, of course, we can't operate the plant. That license expires in 2022. So that's basically another 9 years. So all of the considerations that you just mentioned have to be thought about in the context of the current license period. And in fact, when the steam generator, the replacement steam generators were evaluated, that is the assumption that was made is that they would be put in and operated until the end of the current license, the 2022 period. Remember, I said earlier, if we had not put in new steam generators, we would have had to shut the plant down in 2012 for 1 unit, 2015 for another because the existing steam generators would have been deteriorated beyond the safety point if we went beyond those dates. So that's kind of the starting point. So back many years ago, there was an evaluation done along the lines that you've talked about. What if we replace those faulty steam generators or warrant steam generators with new ones? That's the same thing the industry has been doing all throughout the country. And that evaluation proved that it did make sense to purchase replacement steam generators, run the plant out to 2022. Now we're sitting here with only 9 years left, we would have to assume we could get a license extension beyond 2022. If we can't make that assumption or we don't see sufficient reason to make that assumption, then you would have to be able to put in the new steam generators that you're talking about. And they'd have to pencil out with only 9 years of running time, and they don't. We couldn't go out and replace the steam generators and make it pay economically with only 9 years left. You would have to assume that you could get the a license extension for those economics to work for you. Our view was you can -- you could not assume you could get a license extension, particularly under current circumstances.

Dan McSwain

Right. Could you tell us what that cost was? What would it cost to fix them?

Theodore F. Craver

I don't believe we've disclosed any of that. We've done some of that evaluation, of course, but we have not disclosed that number yet.

Operator

Your next question is from Ed of KPCC, your line is now open.

Ed Joyce

I have one question to clarify on the CPUC process regarding the outage at 16 months. Does the clock ticking now, with your announcement that the plant shuts down on those costs specifically?

Theodore F. Craver

Basically the precedent is replacement power exposure would stop once we shut the facility down.

Ed Joyce

And that formally doesn't happen until?

Theodore F. Craver

You've got us on a...

Ronald L. Litzinger

Technicality.

Theodore F. Craver

I don't think we've got a specific plant here or there. But the fundamental point is once you've both shut the plant down, then you're really not going to be -- you can't be responsible for both sets because you're going to end up having the asset taken out of rate base. You're not going to be earning on that asset, that's the write off that we talked about today that we're going to be taking. So you either have plant operating and it's in rate base and you're earning on that rate base and producing electricity or you're not -- you're not earning on it because you're out of rate base and you're buying power out of the market. So it's one or the other.

Operator

And our last question for today will come from Bill Freebairn of Platts.

William Freebairn

You have said that the regulatory process became complicated. I'm wondering if you're thinking that there's something wrong with the way the NRC regulatory process is set up, that it had taken this long to reach a restart decision?

Theodore F. Craver

I'm going to really respond the same way that I did on the political question that came up. It's -- we've got to look at this as we have to evaluate the facts and circumstances as they present themselves to us, take our best view of what's the responsible thing to do, what's the reasonable thing to do. And we feel we've done that. We've made our decision. Now we're really just focused on, as I said trying to ensure that we can maintain the reliability of the electric system and serve our customers. That's what we do. I'm sure there'll be plenty of discussions in the future, as there always are, about what kind of improvements can be made to the process and what have you. So we'll let the Nuclear Regulatory Commission deal with that on a go-forward basis. We've made our decision based on facts we have in front of us.

William Freebairn

Okay. And just to clarify something that you had said earlier about the license renewal. I thought the license renewal had become a routine matter for a nuclear plant, none has been turned down. And what made you think that you could not conclude that you would be likely to get a license renewal?

Theodore F. Craver

I guess, to be frank, I would argue that it's not, by any means, an automatic process. Number one, it's an expensive process. It is in the neighborhood, we estimated it would be in the neighborhood of around $150 million all in, we have to go through it. And it's not a quick process. It's anywhere between 3 and 5 years, and some of them have been longer than that. So it's, by no means, an automatic process. It's a quite lengthy process. And I think, again, in the context of -- the events of the last couple of years from Fukushima to the desire for enhanced seismic studies at the California plants and our own situation at San Onofre, we did not anticipate that getting a license renewal would be a quick or easy process. It will be quite a lengthy and expensive process.

So I'm going to turn it back over to Janet here for concluding comments.

Janet T. Clayton

We know that there are still several of you who weren't able to get into the queue, and we're sorry we didn't get to all of you. But our media team will follow up immediately after the call. And of course, our media line is (626) 302-2255. That concludes today's call, and thank you for joining us.

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