Edison International (EIX) Q2 2013 Earnings Report, Transcript and Summary

Good afternoon. My name is Kelly, and I will be your conference operator today. At this time, I would like to welcome everyone to the Edison International Second Quarter 2013 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, Kelly, and good afternoon, everyone. Our principal speakers today will be Chairman and CEO, Ted Craver; and Executive Vice President and Chief Financial Officer, Jim Scilacci. Also with us are other members of the management team. The presentation that accompanies Jim's comments, the earnings press release and our Form 10-Q are available on our website at www.edisoninvestor.com. We will be using the slide materials in our regular quarterly business update presentation that will be posted tomorrow on the website to support 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.

Thank you, Scott, and good afternoon, everyone. Today, Edison International reported second quarter core earnings of $0.79 per share, up from $0.56 per share last year. As Jim will comment more fully, quarterly comparisons to 2012 will not be that meaningful given the delay in receiving SCE's General Rate Case decision last year. That said, second quarter core earnings reflect strong operating results from higher authorized investment in our electric grid infrastructure, good cost management and favorable tax benefits. These results are consistent with the Edison International core earnings guidance of $3.25 to $3.45 per share that we updated in June and are reaffirming today. GAAP results include a $575 million pretax or $1.12 per share estimated impairment charge related to the shutdown of the San Onofre Nuclear Generating Station, which we announced June 7. Much of my commentary this afternoon will be on San Onofre. Having made the shutdown decision, SCE's focus for San Onofre has shifted to 3 key areas: First, maintain our focus on safety as we transition the plant from operations to decommissioning it; second, work with California regulators to plan for a reliable electric system without SONGS; and third, resolve the issues of cost recovery raised in the CPUC Order Instituting Investigation, or OII process, consistent with our belief that our actions were prudent and reasonable. As part of the cost recovery effort, we are highly focused on securing recovery from Mitsubishi Heavy Industries for its failure to provide functioning replacement steam generators that met their 20-year warranty and technical specifications. Pursuing our insurance claim from NEIL will also be a major focus. We are moving quickly to transition the work at SONGS, including reducing staffing levels, to reflect the shutdown decision. On June 12, SCE filed with the Nuclear Regulatory Commission formal certification of permanent cessation of power operations at San Onofre. On June 22, SCE filed its formal certification of permanent fuel removal from the reactors. These are the first 2 steps in the long decommissioning process, which is governed by Nuclear Regulatory Commission rules. With the removal of fuel from the units, we are transitioning from an operating license to a nuclear fuel possession license. SCE is currently evaluating alternatives for accelerating the start of decommissioning. We expect to complete the necessary site-specific cost study next year, which will refine the current cost estimates and required timelines. Until this detailed study is complete, we have requested that the current funding levels for the decommissioning trust be maintained. Limited funding for early stage decommissioning planning is available through the trust. SCE intends to initiate the process shortly with the California Public Utilities Commission to access the trust for some decommissioning-related costs. SCE continues to work with the California Independent System Operator, the California Public Utilities Commission, California Energy Commission and other stakeholders on the planning process for adequate and reliable resources of electricity post SONGS. We are doing so against a backdrop of several state policies, including shutting down or repowering coastal natural gas-fired generation due to once-through cooling requirements, a 33% renewables mandate and the state's ambitious greenhouse gas reduction targets under Assembly Bill 32. There are a number of forums that have generated considerable discussion on generation, transmission, demand response and demand reduction and the role of new technologies in meeting future grid needs. SCE will play an active role in shaping an informed set of policies and principles for continued grid reliability in Southern California. Our plans remain focused on the wires-related investments while encouraging the use of competitive markets for new generations. I'd like to elaborate on how we are aggressively pursuing third-party recovery of costs on behalf of our customers. On July 18, SCE provided Mitsubishi Heavy Industries, or MHI, a formal notice of dispute. This begins the process for initiating claims against MHI, resulting from its supplying faulty replacement steam generators. In the notice of dispute, SCE alleges that MHI totally and fundamentally failed to deliver what it promised, and that it was guilty of gross negligence. We also alleged that the liability limitations in the contract do not apply. We have chosen not to specify dollar amounts of damages at this time. We will pursue recoveries aggressively on behalf of customers if our disputes with MHI cannot be resolved otherwise. MHI has already publicly expressed its objections to these claims as would be expected. Consistent with the contract terms, we are now in a 90-day period for SCE and MHI to try to resolve these claims. If MHI and SCE are unable to resolve their differences regarding liability, SCE expects to initiate binding arbitration under the auspices of the International Chamber of Commerce rules in San Francisco. This dispute resolution forum is also specified in the contract. We expect MHI to step up to meet its obligations. Pursuant to our rights under the outage insurance policy written by the Nuclear Electric Insurance Limited, or NEIL, SCE is pursuing claims for energy purchases from the market. SCE expects the total claims under the NEIL outage policy will be $388 million in total, with SCE's share, $304 million, although not all claims have yet been filed. With the decision to shut down San Onofre, SCE's claims under the policy are reduced. We don't expect any decision from NEIL until late in the fourth quarter or sometime next year. If the claims are denied in whole or in part, SCE has recourse, including nonbinding mediation and binding arbitration. SCE continues to work with the California Public Utilities Commission comprehensive OII process to determine the appropriate cost recovery treatment for San Onofre. The CPUC is in the process of scoping out the additional phases in the proceeding. In fact, a scoping memo was issued yesterday for Phase II, which Jim will discuss more in his comments. We will not be able to comment on the likelihood of any potential settlement, which CPUC President Peevey urged parties to seek after our shutdown decision was announced. I'd like to now turn to the drivers of long-term growth. On July 15, we initiated the first phase of SCE's next rate case by delivering the Notice of Intent to the division of ratepayer advocates for our 2015 test year GRC. The actual General Rate Case application is expected to be filed in the fourth quarter of this year. The GRC strategy is consistent with what we've outlined for you previously. We have proposed a modest increase of $120 million for 2015, representing a 1.2% increase over base rates and a 0.6% increase in total rates. We have also proposed increases of $368 million in 2016 and $331 million in 2017. Our request in this GRC cycle will emphasize the need to build on previous infrastructure improvement efforts. Funding the needed increase in infrastructure investment while mitigating rate impacts requires striking the correct balance between reliability, policy goals and affordable customer rates. This means continuing our efforts to achieve efficiencies in our operating and maintenance costs. Operational excellence is the framework we have established to deliver on our mission of providing safe, reliable and affordable power to customers. It is supported by one of our core values, continuous improvement, something in which our employees across the company are fully engaged. For example, we have significantly reduced our support staff to approximately 2006 levels. We are reducing overhead spending in virtually every area. While most of these reductions have been implemented in 2013 and are reflected in our 2013 earnings guidance, we expect to continue cost improvements. These improvements are included in our 2015 rate case, allowing additional capacity for infrastructure investments without significantly impacting customer rates. Our proposed capital spending plans, together with updated forecasts for required FERC transmission investments, steps up our expected rate base growth to a 7% to 9% compound annual growth rate from 2013 through 2017. Jim will review the details in his comments. What I want to do is reiterate our intention to meet our capital spending needs without issuing equity and to moving our dividend back into the target payout range in steps over time. These remain cornerstones of our investor value proposition for Edison International. GRC cycle provides a transition path for SONGS costs as well. For example, to support ongoing O&M costs at San Onofre, we will transition to funding from our decommissioning trust and ramp down revenues collected from customers through the GRC. This will need to be synchronized with the progress of the SONGS OII. We expect to fine-tune requested levels next year, as detailed analysis of operating and capital expenses in the shutdown period are completed. We made a filing with the CPUC last week, for example, to move any O&M savings resulting from shutdown into the ERRA balancing account we used to track purchase power costs. If approved, this will create customer bill offsets from the reductions in costs as we transition to the lower staffing levels appropriate for decommissioning. This proposed treatment will allow us to reduce impacts on customer rates sooner and would not impact earnings. These costs are subject to refund after review in the OII process. I'd like to touch on one other topic related to capital investment. The CPUC's recent decision to require undergrounding of a 3.5-mile, 500 kV segment of the Tehachapi renewable transmission project through the city of Chino Hills. We remain concerned about the potential precedent for future transmission line costs, though we respect the commission's decision and we'll move forward to implement it expeditiously. Next steps are to finalize some technical and scope questions with the PUC, finalize the construction plans and file for rate recovery with FERC based on our estimated capital cost for the project completion. Our estimate is higher than the estimate referenced in the CPUC decision. Important to our ability to develop electric infrastructure while limiting rate impacts is rate design reform. A better rate design remains an important long-term priority to ensure that costs for maintaining grid reliability and availability are fairly borne by all customers using the grid. Especially important is the ability to recover fixed costs through a charge carried by all residential customers. This is important because California policies encouraging residential rooftop solar are subsidizing those who install rooftop solar and shifting fixed costs to those who do not. Assembly Bill 327 has bipartisan support and provides the CPUC the authority to reduce current subsidies between upper and lower-tier residential rates and allow overtime for a more meaningful monthly fixed charge of up to $10 per month. Recovering fixed costs for the grid and the rates of all residential customers is important, as the state moves towards a more distributed and smart grid model. This is especially true since the grid facilitates and enables distributed energy resources and will require significant utility investment. I'll finish with a brief comment on Edison Mission Energy. As a result of last week's termination of the original settlement agreement we reached with EME and a majority of its noteholders, we will now participate in the bankruptcy process, seeking recovery of our claims as a creditor and could be a target of claims as well. Our philosophy in the original agreement was to use tax benefits to address EME's liabilities to us and facilitate its reorganization, if possible. We do not believe we can justify doing more nor are we obligated to do so. We have become aware of one of the many legal filings in the case made in the middle of last night on behalf of creditors, which contains a number of allegations against us. We believe these to be completely without merit. There seems to be a contest for control in the bankruptcy and that we have been thrust into the middle of it. Frankly, it will be a shame if this kind of behavior is allowed to interfere with the principal purpose of the bankruptcy, which is to successfully reorganize EME. As a result of the bankruptcy process, the investment in EME was written off last year and is no longer included in our operating results. EME was and remains structurally separate from Edison International with all that implies. We won't change that. I'll now turn the call over to Jim Scilacci. Jim?

Thanks, Ted, and good afternoon, everyone. My comments will focus on the following topics: Second quarter earnings, SCE's Notice of Intent or NOI filing for the 2015 General Rate Case, updated capital expenditures and rate base forecast for 2013 through 2017, SONGS and earnings guidance. Turning to Page 2 of the presentation. Second quarter 2013 core earnings are $0.79 per share, up $0.23 from last year. SCE contributed $0.25 of their earnings growth. The key drivers are shown on the right side of the slide. As with the first quarter, the largest earnings driver is the delay in the 2012 General Rate Case decision. This timing item affected SCE's quarter-over-quarter comparisons by $0.16 per share. You will recall that during 2012, before a final GRC decision was received, we recorded revenues at 2011 authorized levels. We also benefited $0.08 per share from higher revenues authorized for 2013. As I mentioned last quarter, the earnings benefit of rate base growth was offset by lower CPUC ROE of 10.45% in 2013 versus 11.5% last year. On the cost side, there are a number of items to mention. The first is severance. Severance accounting for employees who worked at SONGS is rather complicated. Here's my plain English explanation. During the second quarter of 2013, we accrued $56 million of severance. Of this amount, $24 million or $0.05 per share was offset by authorized SONGS revenue. For the balance, or $32 million, we established a regulatory asset and we expect that this amount will be offset during the third quarter as we ramp down other expenses at the plant. Because we believe the full amount of the $56 million will be recovered in rates, this cost did not impact earnings. Additionally, for the quarter-over-quarter variance analysis, we see the $0.05 of severance showing up this quarter, and the balance will run through expense next quarter. The severance for employees that indirectly support SONGS is accounted for differently. Severance for the estimated 175 positions was accrued during the second quarter or $0.03 per share and will reduce earnings, but will yield savings once these employees depart later this year. As a reminder, this severance was included as transition cost in our June guidance update. The balance of severance or $0.03 a share relates to the operational excellence initiative Ted discussed, and we'll have similar future benefits through 2014. SONGS inspection and repair costs are $0.04 per share lower in the second quarter. In addition, we did not receive any warranty payments from MHI during the second quarter. One last point on SONGS. We are not showing any variance for removing SONGS rate base from earnings or from AFUDC on CWIP. For the partial month of June, these amounts were relatively small and offset by other items. However, these variances will show up next quarter. The completed SmartConnect project had O&M costs recorded in the balancing account in the second quarter of 2012 of about $0.04, resulting in a positive variance this quarter. Depreciation is $0.03 per share higher from rate base growth. Incremental tax benefits from repair deductions added $0.05 per share. Year-over-year, we continue to expect incremental tax benefits from Transmission & Distribution repair deductions consistent with earnings guidance. Income tax and other items netted to $0.02 per share benefit. Edison International parent and other costs were $0.02 per share higher than last year, as you can see on the left side of the chart. This relates principally to quarter-over-quarter change in our consolidated income taxes. In noncore items, as Ted mentioned, the SONGS impairment charge of $1.12 per share was within the disclosed range. We also recorded a positive $0.04 per share in discontinued items as we continue to refine the estimated income tax impacts of the expected future separation of EME. As Ted mentioned, EME is in discontinued operations and is no longer consolidated as part of our results. Together, the core earnings, non-core charge and discontinued operations tie to the basic and diluted EPS loss of $0.29 per share in the quarter. Page 3 summarizes the year-to-date results and core earnings drivers. I will not go into full reconciliation of year-to-date results because the explanation is very similar to the quarter. Looking ahead to the third quarter, the timing of the 2012 CPUC GRC decision will continue to result in positive variances over the last year and there will be a negative variances from the removal of SONGS from rate base and the elimination of AFUDC earnings from CWIP. Page 4 summarizes many of the key points Ted has already made about the policy direction we're taking in the 2015 General Rate Case. The Notice of Intent will go through a detailed review by the CPUC Division of Rate Payor Advocates. Once the area is satisfied, the filing is complete and deficiencies are cleared, we will finalize a filing and update for any necessary changes. We will file the application in the fourth quarter, commence evidentiary hearings in the spring and target a decision for the fourth quarter of next year. As we have previously mentioned, the workforce reductions and other efficiency improvements will flow back to customers beginning January 1, 2015. Turning to Page 5, we've updated our capital investment forecast to show the profile we anticipate over the next 5 years. The forecast shows the increase in distribution spending in 2015, consistent with our infrastructure reliability focus. The chart shows that we expect to spend between $18 billion to $20 billion from 2013 through 2017. It also reflects the expected moderation of FERC spending, with 2 of our 3 major transmission projects nearing completion. The forecast reflects a modest shift to the right, with 2013 CapEx down about $200 million from our prior forecast. This mainly reflects cost overruns on the 2 transmission projects going into service this year, as well as timing of expenditures -- underruns, sorry. Over the 5-year period, CPUC spending is 78% of the total -- the CPUC spending is 78% of the total, and FERC is 22%. Please note that we also have continued to provide a range case with 12% variability. This is the average variability experienced between forecast and actual capital spending over the last 3 years. Included in FERC capital spending is $360 million estimate for the undergrounding of the portion of the Tehachapi project that Ted discussed. This is the estimate SCE provided to the CPUC and updated Tehachapi testimony earlier this year. SCE assumes that this line is in service in 2016, and we expect the cost estimates and timing will be refined over time. Additional updates on our 3 major transmission projects are in the presentation appendix. On Page 6, we show the detail on the resulting rate base through 2017. The forecast excludes SONGS rate base. Ultimately, Phase II of the OII process will determine what, if any, rate base will be used and useful. We currently estimate about $400 million of SONGS property, plant and equipment, plus construction work in process would continue to support ongoing activities at the site. On August 12, we will make an additional filing to the CPUC and it will contain rate base figures. The capital expenditures provided on Page 5 yield a compound annual growth rate of 7% to 9% for the 2013 through 2017 period. These numbers also reflect bonus depreciation in 2013, which is trued up in the 2015 GRC NOI. Page 7 is an update of our FERC formula rate case proceeding. As many of you are aware, the FERC judge announced a settlement among the parties and that the settlement will be filed on or before August 16. The terms of the settlement are confidential and will not be made public until this is filed with the FERC. We will file an 8-K concurrent with the filing of the settlement so we can discuss the key terms with the market. Please turn to Page 8. We continue to provide updated summaries of key SONGS data and the details supporting our net investment. Note that we have added a new category of SONGS severance cost related to shutdown decision. These are the direct costs that I mentioned earlier, and we expect to recover and not impact earnings. In addition, in the OII proceeding, we have recommended that any excess of SONGS authorized O&M over actual O&M be returned to customers through the credit to our fuel and purchase power balancing account, as Ted mentioned previously. We do not anticipate that O&M spending will decline meaning -- excuse me, we do anticipate that O&M spending will decline meaningfully over time as we transition to decommissioning and downsize staffing. The fuel and purchase power balancing account is running and increasing under collection, primarily from higher-than-forecast natural gas prices and replacement power for SONGS. We are still working on a plan on how to -- we will transition from funding SONGS from base rates to decommissioning. At a minimum, we will need approvals from the CPUC and the Nuclear Regulatory Commission to withdraw funds from a decommissioning trust. On Page 9, we've updated one of the slides we used in the June 7 SONGS call to better reflect the items we considered in recording the impairment. At the bottom of the slide, we summarized the accounting treatment, which moves the net investment into a regulatory asset less the pretax impairment charge of $575 million. This charge is based on the required accounting determination. As we have previously said, we may take different positions in the SONGS OII process based on our view that our actions have been prudent and reasonable. Based on our conversation with investors, we have summarized the current status of the various OII phases on Page 10. Note that this time, the judge has not targeted a specific date for a proposed decision for Phase I, but we expect it in the third quarter. This includes the schedule for Phase II published yesterday by the CPUC. The schedule calls for hearings in October and a final decision in February of next year. One of the key points we made in the June 7 SONGS call was that the recovery precedent allowed return of capital in early shutdown scenarios, but mixed results will return on capital. We have tabulated those precedents for reference, Pages 12 and 13, summarized for reference on Page 11. Pages 12 and 13 summarized the key points that Ted made regarding potential recoveries from MHI for direct and consequential damages and from NEIL for replacement power. Almost all of the potential NEIL replacement coverage falls within the 52-week period of maximum coverage. The tail portion after 52 weeks is covered at 20%. Also, a coverage of 10% of costs may be available after permanent shutdown. Page 14 provides a brief update on the decommissioning process that Ted also covered. Given the permanent shutdown of SONGS, we are now developing a detailed site-specific plan and cost estimates. This detailed plan will not be completed until next year. As a result, we have asked the commission to continue the current decommissioning funding of $23 million a year until we can incorporate the detailed plan. As shown on Page 15, we have reaffirmed our updated core earnings guidance from the June 7 SONGS update call. We have updated our basic earnings per share guidance to reflect the second quarter noncore items. Other than the amount we recorded for the impairment charge for SONGS versus the prior range we provided, all of the guidance elements remain unchanged. Page 16 also reaffirms our dividend policy, which is to return to our targeted dividend range over time to 45% to 55% of SCE's earnings. Ted and I have met with a number of investors over the last few months. We have heard the importance you place on progress with the dividend, as management and the board remain committed to delivering significant shareholder value from both attractive rate base and earnings growth and above-average dividend growth. Thanks, and I'd like to turn the call over for Q&A to the operator.

[Operator Instructions] First question is from Jonathan Arnold of Deutsche Bank.

Firstly, Ted, in your prepared remarks, you said about the dividend that the plan was to increase it to the range that you said in steps and over time. Can you give us any flavor as to how many steps and how long -- and how much time is the right way to think about this, given the SONGS' sort of ongoing deliberations?

So, Jonathan, it's obviously a question I understand people would like more specificity on, as I think actually you and I talked about before as well. The tricky part about either saying we're going to be at 50% by x year, is it implied in any kind of a commitment along that line, is you might find yourself having to either issue debt to increase the dividend or possibly even issue equity in order to maintain that target. And we just feel that's imprudent, that's not the right way to manage capital. So that's why we say in steps over time. And I think the intent, obviously, is to get back into the range, get back into that range as soon as it is prudent. We obviously have a few things bubbling on the stove here, and we've got to figure out the most appropriate way to get back into that range. So I can't be more clear at this point, but we certainly don't expect it to be in one big jump and we don't expect to spend an excessive amount of time getting there.

Okay. And can I just start another topic? The -- obviously, the CPUC approved Tehachapi, but they think it's going to cost less than you're saying it's going to cost. Can you -- I'm sorry if you covered this, but I was cut off for a bit. What -- how will it work? How will you resolve that difference? Are there risks associated with not recovering the actual costs?

So, Jonathan, we're going to have Ron Litzinger cover that.

Yes, Jonathan, cost recovery is at FERC. We will make our filings at FERC, and we have to demonstrate prudency, whatever it costs. The public California PUC does like to put cost caps in their decisions, but it's ultimately decided by FERC.

So that there is -- it doesn't matter essentially what the commission decided on costs, that'll be determined by FERC based on your future filing?

I think people look at the cost caps that the PUC has, and it certainly begs questions. So if we feel we need to file an advice letter with regards to the cost cap at an appropriate time after we get a little further along with the construction risk we face at Tehachapi, we would file an advice letter just to clear up that question.

Next question is from Michael Lapides of Goldman Sachs.

I'm just curious in terms of thinking about the risk reward around the settlement and the transmission, the TO case. I know that you haven't disclosed any of the information regarding what's in the detail of the formal settlement. But just curious, are you looking at a process where you could be coming back in every year, where you're reviewing potential ROEs on FERC-regulated transmission? Are you looking to try and get more of some long-term certainty around that?

Michael, I'm sorry right now. We -- I'd love to be able to get into the settlement, but since it's subject to confidentiality, I can't peel off a piece and give you a feel for how that was treated in the settlement process. When we actually file the settlement, which is expected around August 16, the full settlement will be in the public domain and we'll be happy to talk to you then. So I got to beg off until we get that into the public domain.

Okay. Follow-on question related to EME, if I go back in time and if I go back and recall whether it was NRG, whether it was Mirant, whether it was some of the bankruptcies on the merchant side that we've seen, there wound up being significant cash payments made, whether it was by Xcel or other companies, to bondholder or creditor committees. How do you think or how should investors think about the potential ramifications or impact of that for Edison International in the EME process?

Well, Michael, you're going to get Jim's response redux. I'll just say, I chose my words carefully in my prepared remarks, and those are really probably where we need to leave it at this point. Lots -- it's the nature of the animal, lots of these claims and counterclaims and all kinds of interesting tactics get used. But at the end of the day, as I said, we think the claims or the allegations that were made in this latest filing are without merit, and we intend to vigorously defend our approach. I have to leave it there.

Hugh Wynne of Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: You all mentioned that the scoping memo for Phase II of the OII called for a decision in February of next year. And if I remember correctly, that's only the second phase of a 4-phase process. What are the prospects for settlement with interveners in the OII to be reached on an accelerated basis so that we don't have to wait through the end of '14 for a resolution?

Yes, Hugh, this will be Ted again. I guess, I get to make all the responses where we don't respond. But that's why I said in my script that although, we're obviously aware that President Peevey and others have urged the parties to get together and consider settlement and bring that to the commission, we really can't go into any discussion about that. So there is an interest in it obviously on the part of the commission, but that's about all we can really say on that point. Otherwise, meanwhile, back at the ranch, there is a schedule that is under the OII and that's what we're focused on, at least publicly. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Okay. My follow-up question is kind of a nitty-gritty question on NEIL insurance. You seem to be making substantial claims under the outage policy, but I believe you say here that you've not made claims under the property damage policy. And I guess, I just wanted to verify that. And is there an ability to collect under the outage policy even if the loss to property is excluded from coverage under the property policy?

Hugh, it's Bob Adler. We have delayed making a judgment about submissions under the property policy to this point in time. It's not correct to say that we've decided not to make a submission. So we have not yet determined that, but we have been able to submit claims under the outage policy. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: That contention on the claim on the property policy, because that's the point I wanted to clear up. You can claim under the outage without claiming the property or is that...

Correct. They are independent policies. They're triggered by independent coverages and they have independent exclusions and inclusions.

Dan Eggers of Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just changing pace a little bit, if you look at the CapEx plan from the GRC, there's a lot more distribution spending than you've had in the past. Can you maybe share a little more color on where those monies are going and how much of that is tangibly visible today for explicit needs in the sense of in the past transmission investment had very clear projects associated with it?

So, Dan, I'll give you a quick update, and Ron will give you lots of detail because he is the policy witness for the company for the 2015 GRC. To say it's tangible, I think it would be very tangible to spending a lot of it and we can break it down for you. When you get into the back part of the deck, there'll be a pie chart that shows the distribution of capital spending in the various categories. So we can get into a little bit more probably outside of this call. But a lot of it, a significant amount, I can't quote you a percentage right off the top of my head, is for what we call infrastructure replacement. Those are poles, transformers, conduits, you name it. It's just we're stepping up the replacement level of our facilities given the age to get it closer to where we think we need to be, so we can get on top of any kind of potential down-the-road reliability issues. I'll pause there and look to Ron to fill in around it.

I think Jim has really captured the key point. Our focus on the distribution system is on infrastructure replacement. We need on almost all asset classes to get at or near, what we call, the equilibrium replacement rate, which is sort of the population divided by the mean time to failure. As our system ages, we need to get to that rate to keep the system at the average age of the system less than that mean time to failure for reliability. So we're making some significant step-ups in this particular rate case, especially on poles, as we go forward. And that's what's driving it up primarily.

Yes, it's on Page 23 of the deck when you have a chance to look at it, Dan. So infrastructure replacement is more than 50%. It's almost 60% of the total distribution spending during the 5-year period. The service connections represents about 10% to 15%, load growth is about the same amount; general plan, so that'll be facilities and IT-related activities. So it's -- going back to the main point, infrastructure replacement, that's our way of saying maintain the reliability of the system, that will be very tangible. Dan Eggers - Crédit Suisse AG, Research Division: And I guess, I don't know, it's hard to talk to what the OII is going to look like. But with such big claims outstanding both from your perspective of the MHI and then NEIL, is there a way to work an agreement or, looking at past precedent, to work an agreement where the recovery number would be determined from the customer and then you'd net back proceeds? Or do you need to know -- have a better handle on what you're going to get from these other parties before you can figure out what the customers are going to pay for?

Yes, it's hard to speculate at this point in time. I think what's going to happen, we're going to go through a process and the commission is going to determine what's use and useful in this next phase, in Phase II. Phase III is the important one, that's the prudence of our decision in and around the steam [ph] generator project and all the activities that supported that. So I think that's the process that we will be going down and they'll determine in each one of those phases a decision leading up to the third phase, which I think is the key because that's what will determine reasonableness. But to speculate beyond that, it's really hard to do it at this point in time.

The next question is from Steven Fleishman of Wolfe Research.

Just a question on the -- first on the rate base forecast. You mentioned the bonus depreciation is in there and then the true-up for that. Could you give a little more color on how that plays out through these numbers?

I don't know if I have more color to give you besides we gave you the amount in our script in terms of what the bonus depreciation amount is reflected in the 2015 number. So these numbers are reflective of it, and I'll stop and pause and look at Linda Sullivan for further detail.

Right. It's included in our Notice of Intent filing bonus depreciation, and that is in the rate base numbers that are on this page.

Can you give us that number, though?

Well, we said $700 million.

$700 million is included in the NOI and about 85% of that was associated with the extension into 2013.

Okay. So just in terms of the way that flows through, that's the bonus depreciation in '13, '14 or that's the true-up for that in '15 essentially?

That's the true-up in '15.

Yes, it wasn't reflected in '13, '14. We didn't know about it, so it can't be in rate. So it's now picked up at 2015, Steve.

Okay. And then just on these -- the Edison Mission issues, which I know you can't comment on in detail, but just can you give us a sense on the process of this case and just when you would be in the process be responding?

So Steve, we'll have Bob Adler, our General Counsel, comment.

Well, right now, Steve, the -- there has been a motion filed before the court for a -- for the creditors to take control of the potential claims against EIX. That motion will be heard some time later in August. And, of course, I wouldn't speculate about outcomes. Currently, I believe that Edison Mission has the exclusive reorganization rights into November, as I recall. And so that would be, presuming the next up in the bankruptcy process itself, after a resolution of this particular motion. Does that answer your question?

Yes. Will you be responding to what was filed last night as part of this motion?

We have made a decision whether to respond to the motion. But I want to make clear, there's been no complaint filed against us. There is a motion pending in court.

Paul Fremont of Jefferies.

I guess my first question, looking at Page 9 of your slide presentation, the authorized revenues and the replacement power don't seem to be part of the regulatory asset. Is that because you're asking for recovery of that through the balancing accounts? Or what would be the venue to recover those?

Okay. So it's a good question, Paul. Thank you for picking it up. The authorized revenue, the $804 million here that we reflect on the Page 9, that has been previously recovered from customers, and it's subject to refund as part of the OII process. The replacement power, so here, you can see the $670 million that's been in a -- that sits in our ERRA or our fuel and purchase power balancing account, and it would be subject to review in prudency by the Public Utilities Commission. Thirdly is the net investment, as you slide over to the right. And we said back on June 7 when we announced that we were going to shut SONGS that the net investment is approximately $2.1 billion. And what we did was we took the impairment that we announced today, the $575 million pretax, and reduced the original net investment by that amount, the $575 million, to come up with a regulatory asset of $1.5 million to $1 million [ph]. So there are 3 separate pieces, to be clear, and the commission will review each of these as part of the investigation process. So I'll pause there and make sure we've got clarity here. And if you have a follow-up, please ask it.

Yes, the follow-up question that I have is does the schedule in the scoping memo for Phase II imply that SONGS rate adjustments would occur commensurate with the final order in February of 2014? Or is that not clear based on what's out right now?

Yes, Phase II, for clarity, is looking at the question of what should continue as rate base, what will be used and useful. And that was in my script. I commented, at least based on the initial filing that we made last week, that we will update on August 12 that we believe that there's about $400 million of net plant. Not rate base, net plant that would continue to be used and useful. And so the commission is going to need to look at that and decide. And so it affects ultimately the net investment number that we're talking about here and the regulatory asset that resides at the bottom of the page. And ultimately, remember, for earnings purposes, we pulled out the entire earnings on the entire $1.2 billion of rate base associated with SONGS. So there's a lot of pieces it affects. And Phase II should be recovered by February. And again, this is for interim rate treatment in Phase II. Phase III, if there's prudency issues, it could come back and affect what happens in Phase II.

I'm still not clear, I mean are any rate adjustments then contemplated as part of Phase II or not?

So they'll look at rate adjustments on an interim basis. So Phase I takes a look at 2012 and could have an interim decision, but then that could be affected by ultimately what they decide in Phase III. So -- and just like with rates, you could pull certain costs out of rates and it will not be -- would no longer be used and useful, and certain portions of our rate base would continue. And they could adjust rates on an interim basis until they get to Phase III and they look at everything again. I know it's confusing. We're still working through the details as we understand it, too.

Okay. So it would be like subject to refund. In other words, if you were -- if the costs were deemed to be prudent, then you would essentially get that back?

Yes, I think that's a good way to think about it because per candles [ph], if that would -- put it in rates, and they reserve the right to adjust it as part of Phase III.

The last question is from Julien Dumoulin-Smith.

So first question here. Obviously, pretty successful on cost cutting here, and it seems like moving forward on that front. How do you feel now on executing on '14 cost cuts as you guys previously described on the SONGS update call a few weeks back?

Well, that's a good question. And frankly, we haven't put anything out there for discussion purposes yet. I think we implied through our comments that with the workforce reductions that we've indicated and from things we previously said that there will be some tax benefits that flow into '14 that there will be earnings above the standard rate base model that we've talked about previously. So you'll have growing O&M savings from the workforce reductions where you don't have severance, and you'll have what's not -- and just want to emphasize to you, and thank you, Scott, for pointing that out, the benefits we see from SONGS, reductions and costs will not flow to earnings, those are being captured. Whatever benefit of -- arise from the difference between authorized rates and actual expenditures will flow to reduce fuel and purchase power under collections that we're experiencing right now. And then I have to stop there. And obviously rate base, we expect to grow based on the numbers we gave you today.

That is what we have proposed with the CPUC.

Right.

Right. But there is this separate and distinct cost cutting initiative underway, at least from the last time you guys updated it, it seemed like that would at least in part offset the reduction of rate base, correct? I mean the -- and no change at least from that base [ph]?

Yes, there's no change, so there's multiple different pieces here and you've got non-SONGS reductions in workforce, you have SONGS reduction in workforce, but that should not affect earnings on the SONGS piece. And you have rate base growth and you tax benefits. So those are the primary elements of -- as you're trying to look forward into '14.

Can you give us a flavor, at least as to the tax element that you're alluding to, what that could contribute potentially?

We have not said -- we'll catch you in the first part of next year what that amount will be. I think we had $50 million after tax for 2013. We have not said what it's going to be in '14.

Operator?

Okay, sir. I'll turn it back over to you now.

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