Edison International (EIX) — Q2 2015 Earnings Call Transcript

Thanks, Jaclyn and good afternoon, everyone. Our principal speakers today will be Chairman and Chief Executive Officer, Ted Craver and Executive Vice President and Chief Financial Officer, Jim Scilacci. Also here 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. Consistent with last quarter, we posted Ted's and Jim's prepared remarks so that you can follow their comments. Tomorrow afternoon we will distribute our regular business of the presentation for use in upcoming investor meetings. During this call we will make forward-looking statements about the future outlook for Edison International and its subsidiaries. Actual results could differ materially from current expectations. Important factors that could cause different results are set forth in our SEC filings. Please read these carefully. The presentation includes certain outlook assumptions as well as reconciliation of non-GAAP measures to the nearest GAAP measures. During Q&A please limit yourself to one question and one follow-up. I will now turn the call over to Ted.

Thank you, Scott and good afternoon, everyone. Second quarter earnings were $1.16 per share, up $0.08 per share from last year. However, until SCE receives a decision on its 2015 general rate case, comparisons of year-over-year results will not be that meaningful. Jim will have the details in his comments. Today I will touch on several policy and growth topics but first a comment on SONGS. We were disappointed about the renewed uncertainty surrounding the SONGS settlement. Most of the recent procedural moves and various motions have come from individuals and organizations that have consistently opposed the settlement since it was first announced over a year ago. It was more troubling to have one of the six signatories of the settlement, The Utility Reform Network, advise the CPUC in late June that it no longer supported the settlement. Interestingly, in TURN's announcement, it acknowledged that the terms of the settlement were good for customers and that the outcome of any litigated reconsideration process may not differ substantially from the terms of the settlement. TURN is an important voice on consumer matters before the CPUC so we must hope that its failure to adhere to its obligations under the SONGS settlement represents an aberration. We have now responded to all requests for information from the CPUC's administrative law judges regarding the challenges to the SONGS settlement. We're hopeful they will rule on the outstanding issues soon. Prolonging this period of uncertainty is not good for anyone. We continue to believe strongly that the settlement met all of the required standards for last November's unanimous commission approval. We believe that the SONGS settlement was the product of good faith arm's-length negotiations that resulted in a fair and reasonable outcome for our customers. Let me turn to some regular policy developments. The CPUC recently ruled on a residential rate design reform as required by Assembly Bill 327. Their recent unanimous decision was the product of significant debates and compromise among the commissioners. We didn't get everything we advocated for. We would've liked to have seen more progress in increasing the proportion of revenues collected through fixed charges which would better match our actual cost of residential customers but the minimum bill will be raised from $1.80 to $10 a month. Also, we preserve the opportunity to revisit a more meaningful fixed charge in the future. We achieved rate reform that places approximately 96% of our retail customers' kilowatt hours into a two-tiered rate section structure, very similar to what we recommended. About 4% of our retail customers' kilowatt hours will be subject to a surcharge for high usage. The commissioners invested a tremendous amount of time and effort in this phase of the proceeding and we appreciated the unanimous agreement that getting residential rates closer to the true cost of service was an important tenet in producing fairness among customers. Attention will now turn to the portion of the CPUC proceeding on net energy metering which relates to how customers who opt for rooftop solar are credited for their own generation. Parties will be filing their net energy metering proposals next week. Turning to a different subject, we have received broad support for SCE's Charge Ready program. This is the program we announced last October to invest in infrastructure to support transportation electrification. On July 9, a settlement with most of the parties was filed with the CPUC on the $22 million pilot phase of the program. Importantly, both TURN and the Office of Ratepayer Advocates are parties to the settlement, as are environmental organizations and electric vehicle charger equipment companies. The principal change to our original application in the settlement is to expense rather than capitalize the rebates that SCE would provide customers for the vehicle chargers installed. While it didn't change the amount recommended for the pilot program, we expect that if this provision is adopted for the full program the rate base opportunity will now be $225 million of the total $342 million estimate for the program. We look forward to commission action on the pilot and subsequently on the full program. The final topic I want to cover is SCE's distribution resources plan or DRP filed with the CPUC on July 1. We consider this plan to be one of our most important filings this year and probably in several years. We endeavored to not simply answer the commission's initial questions about the integration of distributed energy resources but also to lay out our vision for how the grid of the future will facilitate customer choice of new technologies and support California's policies to move to a low-carbon economy. The goal of the distribution resources plan is to facilitate the integration of distributed energy resources at optimal locations within the distribution grid and to upgrade the distribution grid to better enable a plug-and-play approach for adding distributed energy resources and new technologies more broadly across our system. These resources include distributed renewable generation such as rooftop and ground mount solar, electric vehicle charging, energy storage, energy efficiency, demand response. California will use these resources as enablers in achieving its low-carbon objectives over the next several decades. At the expected adoption rate for these distributed resources, the electric grid will require substantial investment in modernization and upgrades. As part of its filing, SCE provided an initial view of the range of possible capital investments to achieve the goals of the DRP. Assuming the CPUC supports this provides some indication of our view of the investment required for the long-term program which will likely go well into the next decade. Jim will talk about some of the financial details and how we see this working with the GRC process. As I've just indicated, significant capital investment will be required to modernize and upgrade SCE's distribution grid consistent with the DRP recommendations. This is in addition to continued distribution system reliability investment, anticipated electric vehicle charging and storage investments, continued transmission and generation maintenance capital investment and potential improvements in capital spending productivity. All of this is consistent with our lower risk wires-focused investment strategy. Taken together, we expect overall SCE capital spending to be at least $4 billion annually for the foreseeable future. Depending on the state's preferences on the pace of adoption and on approval of DRP-related work in future general rate cases, capital spending could be higher.

Thanks, Ted. This afternoon I will cover second quarter and year-to-date results and several other topics. Please turn to Page 2 of the presentation. I will lead off my comments with a general statement about attempting to compare 2015 to 2014 earnings. Because SCE has yet to receive a 2015 general rate case decision, the utility is recording revenues largely based upon 2014 authorized levels. In the quarter SCE receives a final GRC decision, we will record a cumulative adjustment retroactive to January 1, 2015. Earnings comparisons will not be useful until we report full-year 2015 earnings. In the meantime, we believe the simplified rate base approach is the best starting point to model full-year earnings. As Ted said, second quarter core earnings are $1.16 per share. Consistent with our first-quarter approach, we did defer revenues to offset incremental repair deductions, pending the outcome of the 2015 GRC. The amount of deferred revenue this quarter was $0.09 per share, with the offsetting benefit in taxes. You can see this in the summary of SCE's driver on this slide. On a year-to-date basis, SCE has now deferred $0.16 of revenue from incremental repair deductions because of the large delta between expected and forecast repair deductions for 2015. Last May, SCE made a filing with the CPUC to update its repair deductions for the 2015 through 2017 GRC period. With the May filing, SCE's updated 2015 revenue request would result in a $120 million revenue decrease from authorized revenues. For the two post-test years, the year-over-year revenue change would be an increase of $236 million and $320 million for 2016 and 2017, respectively. We have no insight as to the timing of the proposed GRC decision. On July 24, SCE did respond to certain questions raised by the ALJ concerning the May filing regarding repair deductions. The questions related to the coordination of ratemaking between CPUC and FERC. The major items impacting second quarter results is a $0.31 per share tax benefit from reducing liabilities from uncertain tax positions. During the quarter, we received an IRS report for tax years 2010 through 2012. Based on this report, we updated our estimated liabilities for uncertain tax positions which flow directly through to earnings. We had a similar benefit of $0.09 last year related to updating uncertain tax positions for other tax benefit years. Both of these are highlighted in the SCE key earnings drivers. Historically, we have classified the change in an estimate of an uncertain tax position as both positive and negative as part of core earnings and highlight significant changes that affect period-over-period comparisons. These items are not part of the simplified earnings model that we have discussed in the past and are subject to future revisions based on audits, new information, and other developments related to our tax positions. Excluding the $0.31 benefit, second quarter core earnings are $0.85 per share with SCE contributing $0.87, offset by a $0.02 loss at the EIX holding company. In the core EPS drivers table we netted out SONGS related impact on revenues, O&M, and depreciation. On this basis, revenues are lower by $0.03 per share due to the $0.09 deferred revenue I mentioned earlier and partially offset by a $0.06 benefit from higher FERC-related and other revenues. Looking at costs, O&M has a $0.01 per share positive variance which continues our cost management focus. SCE's second quarter results included $0.02 per share in severance costs this year and $0.01 per share last year. On a year-over-year basis the difference is minimal because of rounding. Depreciation expense increased by $0.06 per share, reflecting SCE's ongoing wires investment. SCE benefited from lower financing costs by $0.03 per share. This relates primarily to higher AFUDC equity earnings. Turning to taxes, I've already discussed most of the major items. These include the uncertain tax positions this year and last year as well as the $0.09 of incremental repair deductions, which is the offset to the $0.09 of revenue, so no net earnings impact. The balance is lower tax benefits year over year of $0.12 per share, mainly related to lower flow-through tax benefits than last year, revisions to estimated liabilities of our net operating losses, interest and state income taxes. Remaining $0.07 per share negative variance includes benefits from last year that did not recur in 2015 such as generator settlements and a San Onofre property tax refund. For the EIX holding company, losses were $0.01 lower than last year due to lower corporate expenses and higher income from affordable housing projects. We continue to wind down the Edison capital low-income housing portfolio. Please turn to Page 3. I don't plan to review the year-to-date financial results in detail, but the earnings analysis is consistent with the second quarter results. Please turn to Page 4. You will see that the uptick in interest rates is reflected in the trend of the Moody's Utility Bond Index shown at the green line. The 12-month moving average line shown in blue is moving back towards the 5% base rate. Given the short time period remaining on the 12-month measurement period, it is likely that SCE's CPUC return on common equity will remain at 10.45% during 2016. At FERC, the moratorium on filing and ROE change expired on July 1. I would also like to touch on a few other SCE-related financial matters that are not shown on the slide. First, SCE's weighted average equity component, for regulatory purposes, was 48.9% at June 30 compared to 48.4% at the end of the first quarter. SCE is required to maintain a 48% common equity layer on a rolling 13-month basis. Second, SCE continues to make good progress on reducing its fuel and purchase power under collection. As of June 30 of last year, SCE's ERRA balancing account was under collected by $1.6 billion. As of June 30 this year, the ERRA under collection was $543 million. The billion-dollar reduction was from three primary reasons: SONGS settlement refund credits against the ERRA balancing account, the 2014 ERRA rate increase and lower-than-expected power and natural gas prices. As of the July 23 commission conference, the CPUC approved SCE's access to the SONGS 2 and 3 nuclear decommissioning trusts for costs incurred from the June 2013 plant shutdown through the end of 2014. These costs amounted to $343 million and the amount will be refunded to customers via a credit to the ERRA under collections pursuant to the SONGS settlement. This morning SCE filed the settlement agreement and the 2015 ERRA proceeding. As part of this settlement, SCE has agreed to forgo any 2015 ERRA rate increase adjustment. We now expect that the ERRA under collection will be fully recovered before year-end. Lastly, earlier this month both SCE and EIX extended the terms of their respective credit agreements by a year to July 2020 for $2.6 billion at SCE and $1.18 billion at EIX. The remainder $150 million for SCE and $68 million for EIX will mature in July 2019. There are no material changes to the terms and conditions.

I will now turn the call over to the operator to moderate the Q&A.

It's Julien here. I suppose first question out of the gate, in terms of the GRC, can you elaborate on the settlement opportunity? And also perhaps just in terms of the potential for a longer than a three-year resolution, is there an opportunity for a fourth year?

I find it challenging to speculate on that, and we typically don’t comment on any settlement discussions, so I will try to avoid that question. We have only filed for three years, making it difficult to consider a fourth year without a special arrangement. While we would like to expedite these processes and get them approved, it presents a challenge to achieve that.

Got it. But in terms of confidence in the timeline here, perhaps if you can elaborate?

As I said in my prepared remarks, we just don't have a view. We're waiting for a proposed decision and that's all we can say right now.

Fair enough. And then perhaps just terms of the wider CapEx program, obviously you provided it pretty meaningful update intra-quarter here. How are you thinking in the long-term? Is there going to be eventually coming out of this process incremental CapEx? Should we ultimately be continuing to think about $4 to $4.5 billion throughout the process of having these proposals, ultimately, I suppose ratified or adopted, or what have you?

That's what we've been indicating. We've said in fact it was in my remarks and probably in Ted's, too, that we see that $4 billion to $4.5 billion range being sustained based on all the things we're seeing now and with the DRP but, again, some of it is subject to a lot of commission approval. Obviously they are going to go through and review this and give us some indication as far as a time frame, and so that's still a lot in their court in terms of how they work through it. But our current view is somewhere in that $4 billion to $4.5 billion range.

I know you can't call the outcome but I was wondering if you might provide a little bit of clarity on the procedural steps that have to be taken by the commission to consider the potential reopening of the SONGS settlement and if so, the steps that you would expect after that.

Hugh, it's Jim. We're going to have to Adam Umanoff, our General Counsel, provide some answers there.

Good afternoon, Hugh. As you know, there is a potential petition for a modification before the public utility commission. We really can't give you any certainty on the timing of the commission's consideration of that petition. Motions have been filed, and responses have been made. There is no specific time period under which the commission is obligated to respond. We're certainly hopeful, as Ted mentioned, that this will be resolved quickly, but we can't give you any definitive timeline for that resolution. There is a companion motion for sanctions before the public utility commission in connection with ex parte communications or allegations of improper ex parte communications. We would hope that that would be resolved concurrently if not in advance of the consideration of the petition for modification.

If the petition for modification is accepted and the San Onofre rate case is reopened, can you provide any general insights on the litigation process and the expected timeline?

Again, first and foremost, we don't believe that the existing commission precedent would support reopening of the SONGS settlement. But we certainly can't advise you with any certainty that it can't happen. If the proceeding is reopened we would return to litigation and litigation of the San Onofre OII would likely take a considerable period of time. It would not happen in a matter of weeks or months.

On SONGS, can you give an update in terms of where you are in the process with NEIL? And also there were lots of headlines over the last couple of days about the arbitration with MHI. Can you just give an update on that as well?

Sure. I would be happy to. Hello, Michael. With respect to NEIL we continue to pursue recovery of our losses from NEIL but really can't speculate as to the timing of concluding that effort. With respect to MHI, I think it's important as a preface to remind everyone that we're subject to a confidentiality order from the arbitration panel who is hearing the MHI claims. We're not in a position to comment on any of the substantive or procedural activity in the MHI arbitration. I can tell you that we believe we're still on track for a spring 2016 hearing and I hope for resolution to that hearing and final order later in 2016.

Can I ask just a procedural question? If any of the parties has issues with the final order that comes out of an ICC arbitration, if they want to litigate, can they? And if so, where?

Generally the arbitral order is expected to be final. There are very limited grounds for appeal. It remains to be seen if a frustrated party chose to appeal where they would take that.

Could you may be spend a little time going through what the DRP process is from here and what the commission is actually going to decide on the DRP?

Sure. Steve, this is Pedro Pizarro. We and the other utilities submitted our plans on July 1. The commission will now conduct a standard review process for the filings and will eventually provide comments and approvals. As Jim noted, besides the requirements outlined by the PUC, they also requested an analysis of our system's capacity to integrate distributed resources, as well as a method to ensure market transparency regarding that capacity and updates. Additionally, we proposed several demonstration projects in accordance with the PUC order, which will be considered for final approval along with everything else. We also requested the memorandum account treatment that Jim referred to. At this juncture, it is difficult to predict the final timing, but under a usual timeline, we anticipate approval within the next year.

And is this a case where there is intervention and people can have their own view on your proposal? Is this something then where maybe there could be a chance to try and settle this case? How does this case proceed from that aspect?

So it is a litigated proceeding so there will be opportunities for interveners to file comments and for different views to be aired at the PUC. Really too early to comment on whether there is a prospect for settlement among parties or the like.

Okay. And then just a question on the memo account treatment. So you wouldn't keep seeking recovery of the investment through 2017 until the GRC. But under the memo account would you effectively be able to recover that investment on like a non-cash basis with a return in the meantime?

That's a good question. There’s still some uncertainty regarding how it actually works. The memorandum account was primarily set up to maintain the chance to recover the revenue requirement linked to the expenditure. This allows us to revisit and justify the reasonableness of the spending. During the general rate case in 2018, we aim to seek recovery if all conditions are satisfied. I don’t anticipate additional earnings from 2015 to 2017 related to this matter; it seems premature to predict any returns in that timeframe. It’s likely that we’ll see more action in 2018. Furthermore, the expenditure levels for the DRP are largely concentrated in 2017, assuming the commission permits us to allocate that kind of funding.

Regarding the long-term capital expenditures, during the period from 2015 to 2017, we saw a gradual phase-out of transmission work, focusing more on distribution and maintenance. Looking ahead from 2018 onward, what capital expenditures will be replaced? Consider how the mix of your capital will change as the DRP funding becomes more prominent.

Transmission will depend on the outcome of some pending legislation. We've seen an increase as we've constructed renewable lines, but that has been decreasing as we complete Tehachapi and other renewable projects in progress. We have consistently noted there's limited generation capacity, with around $100 million allocated for maintenance of the legacy generation fleet. As transmission costs have decreased, we have increased our distribution efforts to improve our replacement rates, which are essential for supporting overall reliability. Our objective is to manage this within the $4 billion range, and we aim to align these efforts with the DRP.

What I would add is to consider that a key area of spending is the replacement of infrastructure for the distribution system, which will persist. In the DRP filing, we highlighted various categories of DRP-related investments. I anticipate that as we navigate future rate case cycles, the distinction between new DRP spending and core distribution spending will become clearer as modern technologies become integral to the distribution system. Additionally, some of the DRP spending, particularly in grid reinforcement, has been outlined for previous years and beyond; this involves expediting work normally categorized as distribution infrastructure replacement. We are enhancing low voltage circuits to higher voltage ones to support more distributed resources. Thus, we are pushing forward investments that might have typically been part of a longer-term infrastructure replacement plan due to the need for integrating distributed resources, which is essential for strengthening the grid and facilitating quicker adoption of new technologies. In summary, over the coming years, you will see the boundaries between infrastructure replacement and the DRP category becoming less distinct.

And just on transmission with the Delaney line going away from your group, how do you guys think about the ability to win bigger transmission projects in California in the future? Is this going to become just a lowest-cost bid type of environment that makes it harder to get the most optimal project on?

So you know the ISO is running their competitive process under FERC Order 1000. We had been with partners in the Delaney-Colorado River process. We expect that as other opportunities come up in our service area we will continue to bid on those and put out competitive proposals. I think as we go through this and, frankly, not only ourselves but the entire market continues to learn in terms of what the competitive practices are in terms of designing lines, constructing them, etc., I think we want to be part of the learning process and make sure we're making our proposals more competitive in the future. So, we're still capturing the lessons learned out of the Delaney-Colorado River experience but certainly support the process that the ISO is going through and evaluating proposals and accepting bids based on the parameters they are evaluating.

Firstly, regarding the revenue deferral, should we view it as aligning your actual expenses with the anticipated revenues, meaning there won't be any earnings impact once the GRC is completed?

Roughly that's what we're trying to do.

So maybe a bit less noise in the numbers? At least from that source.

Well the goal here in the May filing is really what you need to go back to, is that the misalignment between the actual expenditures and the deductions we're taking and the forecast and the reserves are creating first and second quarter, what we're trying to do is get this stuff put together and we recognized that they were misaligned. And that's why we went back in for the supplemental filing. And if they adopt that supplemental filing, obviously that would not flow to earnings. So if that's your initial question, the answer would be yes.

Regarding the overlap between DRP projects and potential spending you might have pursued otherwise, you indicated that a significant portion of the initial DRP is in 2017, and you have a rate case filing in process. Do you see any overlap at this point, or do you think this might change as you progress through the next year or two?

So it's not in the current GRC forecast. The only way we have contemplated spending some money is if you don't spend all that is authorized, for example, if you have fewer service connections than we had forecast, that creates some delta, some room to spend additional dollars. Now what I said in my prepared remarks, if we spend all this authorized based on our forecast and we would like to make DRP expenditures above that, that's where the memorandum account comes in, why it's important. So you don't get into any retroactive ratemaking issues.

I was wondering if we could revisit the DRP. Regarding the 2018 and 2020 numbers, can you provide a qualitative understanding of the differences between the $1.4 billion low end and the $2.6 million high end? There's a significant difference—what happens there?

This is Pedro again. I'll keep it at a high level. One of the reasons we have the range is that as we look towards the 2018 to 2020 timeframe, our perspective on the DRP is influenced by our internal forecasts regarding the pace of technology adoption and how that pace differs across various parts of our system. For instance, the capital spending forecast included in the DRP filing primarily focused on urban areas. We anticipate that rural areas may not adopt technologies as quickly and that this may occur in later years. We've made some estimates on which circuits might see faster or slower adoption levels. However, the range is really linked to where customers decide to implement these technologies, how quickly they do so, and what actions we need to take to ensure our grid is prepared to accommodate their choices. This reflects our intention to support a robust grid that can keep pace with customer needs, as opposed to making a definitive decision on where to invest. At this point, we are making some educated guesses regarding those customer choices.

Travis, you can see on Page 6 of the investor deck the breakout of the spending. $0.5 billion of it alone is the grid reinforcement. That's what Pedro alluded to, is taking the lower voltage circuits and bringing them up to higher voltage levels to prepare for more distributed generation. And that's just pace. How fast do you want to make those changes? That's a choice that we will have to make and the commission will have to make together.

One other variable that we mentioned in our filings is that we are making forecasts based on our current perspective and the market's view of available technologies. For instance, communications systems. We know we will need to enhance the capabilities of our field area network. We are constructing these capital numbers based on what we expect the costs of those technologies to be today, but it’s important to recognize that computing and communications technologies are rapidly evolving, and as we look ahead a few years, the actual prices and costs for those technologies could vary significantly.

Coming back to SONGS for a second and just looking at the key gating items we should be keeping an eye on. You've got that re-hearing request out there and then you've got the ALJ trying to close the OII proceeding that continue to get pushed back and now has that September 27 deadline recently approved. How significant is that in the scheme of things? And if they stick to this final deadline and close the books, does that imply some final resolution on this matter or is that irrelevant to this?

We certainly hope that the CPUC will now conclude its consideration of the application for re-hearing motion for sanctions and the petition for modification of the settlement, all by that September 27 date. But, frankly, there's no guarantee. That deadline for extension of the OII proceeding has been extended previously and it can be extended again.

Okay. But that proceeding is the one sort of gating item to keep an eye on. If they stick to that that could be the resolution date, if you will, of these matters?

It could conceivably be.

Okay. And separate question, Ted, to you, as you think about your dividend plans going through the December period, as you normally do, are those going to be completely independent of these regulatory issues out there? For example, if the GRC decision hasn't come out, if the SONGS settlement hasn't yet happened or closed, would you still stick to your dividend plans based on your CapEx and cash flow programs or do these things influence how you are thinking about the dividend?

I want to emphasize that we have clearly outlined our objective, which is to return to a payout ratio of 45% to 55% for SCE earnings. This process won't happen all at once; we've already made significant progress last year and aim to continue making steady improvements to reach that payout ratio. While I cannot guarantee that we will achieve this under all circumstances, we must consider capital requirements and other factors. However, as we see it today, these elements appear manageable, allowing us to make progress toward one of our core objectives of achieving that payout ratio of 45% to 55%.

I would like to follow up on Dan Eggers's question regarding the Delaney transmission project. I'm curious if you can share your thoughts on what factors contributed to Abengoa and Starwood winning the project. You had the advantage of rights-of-way and local knowledge, so what did you think gave them a cost or revenue requirement edge that was key in securing the deal?

I don't believe that the Cal ISO has published the cost estimate, their revenue requirement for that project. The goal we have at this point is a statement from the ISO that in their view the proposed costs for that Abengoa team were significantly less than those of the next competitor and I don't think the ISO has publicized who the next competitor was. So it's tough to speculate on what some of the key drivers would have been. But when you think about the costs of transmission projects, key elements would include everything from the upstream design of the project, what kind of powers, what kind of conductors to rights-of-way, as you suggested, to environmental impact and mitigating those impacts depending on what route you choose to the cost of the actual construction labor you are using to build. Very difficult for us to speculate on what it would have been, but, again, we note that the ISO said that the choice was based on the lower revenue requirement and also binding caps on capital costs and as well as the return on equity.

Okay. Do you know when they are going to provide more information? Cal ISO, I mean.

I don't think we're aware of that.

Okay. Finally, you mentioned the cost of capital in 2016. When do you think that might be revisited? It has been deferred in the past regarding your separate cost of capital proceedings. What are your expectations, or what should we consider in terms of when the CPUC may address this? Is there a possibility that they may delay it?

Okay. Paul, this is Jim. Right now, procedurally we would file in April 2016 for cost of capital effective 1/1/2017. And that's cost of capital, that would be return on common equity, capital structure and the like. That wouldn't preclude an extension like we've done before, but the current policy or the current procedural path would be filing in April.

Is there any thought or discussion about whether you might be able to defer that?

It's a possibility that we could defer it again. This is the first time we've done it in the past, and generally, when I've talked with my counterparts at PG&E and Sempra, we appreciate the procedure and the trigger mechanism. It's transparent, and it's clear what's happening with it. We have a strong desire to continue using it. If we can get an extension, that would be great. If we have to enter a litigated process, we will have to see where interest rates stand. It seems like they are returning to where they were three years ago, well now four, if we continue down this path. Overall, the mechanism has worked well considering our goals.

Okay. But do you get the feeling that your counterparties on the other side might be willing to do that as well?

We've done it once already so we will have to see if they'd do it again.

Okay. Finally, regarding the legislative initiatives related to the CPUC and potential reforms, there have been some changes and several competing bills. Is there a specific legislative initiative that we should pay attention to or anything in that area that might be upcoming? I know there are a few, and I was wondering if there is one that you believe is more significant than the others.

There is a hearing coming up in the middle of August directly related to ex parte governance issues at the CPUC. There have been a number of independent reports that have been prepared for the CPUC. There is a draft of the commissioner code of conduct that's been prepared and we welcome a transparent exercise considering reform to the ex parte and other governance rules of the commission. That might be worthwhile listening in on. Again, I think it's in the middle of August, so in a couple of weeks from now.

Thanks very much, everyone, for participating and please do call us if you have any follow-up questions. Thanks again and have a safe day. Bye, bye.