PG&E Corporation (PCG) Q3 2012 Earnings Report, Transcript and Summary

Good morning, and welcome to the Third Quarter Earnings 2012 Conference Call. [Operator Instructions] At this time, I would like to introduce your host, Gabe Togneri, with PG&E. Thank you and enjoy your call. You may proceed, Mr. Togneri.

Thanks, Monique. Hello, everyone, and thanks for joining us on our call. Before you hear from Tony Earley, Chris Johns and Kent Harvey, let me remind you that our discussion will include forward-looking statements based on assumptions and expectations reflecting information currently available to management. Some of the important factors that could affect the company's results are described in Exhibit 1, located in the appendix of today's slides. And we encourage you to review the discussion of risk factors that appears in the 2011 Annual Report and in the Form 10-Q that we'll file with the SEC later today. And with that, I'll hand it over to Tony.

Thanks, Gabe, and good morning, everyone. Before I start, I know many of you are on the east coast and I want to urge you to make sure that you're in a safe location, and please don't try and travel until the storm passes and we -- you know the extent of it. EEI has activated its storm response network. The industry is mobilizing all possible resources, including west coast resources. PG&E is looking at what we can do to help, along with the other west coast utilities. This could be a very major event. So please make sure you are careful and stay safe. My comments this morning will be brief, and then I'll turn it over to Chris and Kent. On Slide 2, as you've seen before, our focus is on 3 priorities: resolving the gas issues, positioning the company for long-term success and rebuilding relationships. I'm pleased to report we continue to make progress in these areas, including improvements throughout all of our operations, and we continue to be focused on the key stakeholders, especially customers. Given recent events, however, our call today will primarily cover gas issues, starting with our Pipeline Safety Enhancement Plan. We're disappointed with the proposed decision we received on the PSEP filing because, among other things, it failed to reflect the fact that much of this work is driven by new standards and requirements and that good engineering and planning practices include contingency plans in such complex operations, and Chris is going to elaborate more on this point. As it stands, the proposed decision is punitive and, with cost already incurred, represents more than $1 billion in unrecovered costs, without even factoring how the investigations will be resolved. We believe that the resolution of the investigations and the resolution of the PSEP rulemaking should be viewed in conjunction with each other to resolve in an appropriate conclusion. This is going to be the primary focus as we participate in continuing settlement discussions. I want to emphasize, we are still committed to the settlement discussions, and we still believe in the involvement -- that the involvement of a mediator is the best way to bring the parties together in what have been complex and protracted discussions. As always, our work to resolve the gas proceedings will not distract us from our obligation to deliver safe, reliable and affordable gas and electric service to our customers. So with that, let me turn it over to Chris to go into some of these things in detail.

Thanks, Tony, and good morning, everyone. As you can see on Slide 3, my comments will primarily be focused on the Pipeline Safety Enhancement Program, or the PSEP program, and the proposed decision and the work that we outlined in our PSEP filing. I'll also provide an update on Hinkley, the environmental activities there. You'll recall that the PSEP filing was made in August of 2011 and represents the work that we believe is necessary to address the new higher standards adopted by the CPUC related to pipeline safety and modernization. We made our filing in about 2 months' time in response to the CPUC directive to develop a comprehensive multiyear plan. In developing the PSEP cost estimates, we worked with an industry expert who followed industry best practices in helping us estimate these costs. In particular, our contingency estimates followed project management standards for work in the preliminary design stage, as much of our work was at that time. We also requested an advice letter process for recovery of costs of both those estimates. Since making our filing, our experience in the field shows that we need the contingency and, in some cases, more than that, as I'll describe in a moment. In contrast, the proposed decision in the PSEP orders us to complete the work we outlined but disallows a significant portion of the funding, including all of the requested contingency and the advice letter mechanism. We believe the rejection of these requests is both arbitrary and unreasonable, particularly since this is an established practice used in other commission proceedings. The proposed decision also drastically reduces our return on equity on PSEP capital investment, compounding the punitive effect of the decision. Shifting to the work underway, we are on track to accomplish the work we targeted for this year. On the strength test front, we completed 85 miles of testing in the third quarter, putting us on track to achieve the 160 miles we targeted by year end. Our PSEP filing targets more than 350 additional miles through 2014. As Nick Stavropoulos discussed on our call in February, we've seen strength test costs that are higher than both industry benchmarks and the cost assumptions in our PSEP filing. The strength testing effort is the largest and most expansive -- expensive component of the planned PSEP expenses. We did achieve a 25% cost reduction in 2012 compared to our per-mile cost in 2011, but we expect the strength testing in 2013 and '14 to be at a similar unit cost as it is in '12. There are a couple of drivers for these higher costs. First, we're testing short segments of older pipeline as opposed to newly constructed longer segments. These are often located in dense, urban areas as opposed to the rural, less populated areas. Second, when we prepared our cost forecast, we assumed that the pipelines could be cleaned with a single cleaning run. However, in practice, fully eliminating the contaminants in the older lines has required up to 5 cleaning runs, significantly increasing the cost of storing, testing, treating, transporting and disposing of the water used in the cleaning runs. On the pipeline replacement, we completed the replacement of 12 miles in the third quarter. We have additional replacement projects currently underway, and we expect to have replaced almost 40 miles by year end. We plan to replace an additional 150 miles through 2014 as outlined in our filing. Conditions we've encountered while completing this work include more complicated and lengthy permitting processes, as well as land acquisition delays and project reengineering. The pipeline replacement cost is expected to be at a level consistent with our request when you include the contingencies in 2013 and 2014. In our work validating the Maximum Allowable Operating Pressure, or the MAOP, our pipeline -- of our pipelines, we've completed the validation of more than 3,000 miles year-to-date with 4,000 miles expected to be validated by the end of the year. We're on track to complete all of the MAOP validation work of our entire gas transmission network of more than 6,700 miles by early 2013. We've also installed 35 automated valves so far this year and expect to reach our target of 46 by year end. The costs associated with these programs are in line with what we assumed in the PSEP filing when including the contingency. So summing this up, we continue to focus on ways to complete all of our work more efficiently, including competitive bidding and more pre-engineering and design work. It's a reasonable assumption, though, at this point that we will need more than the contingency amounts requested in the PSEP filing for the expense-related work and to meet our commitments and that we will remain on track, including the contingency, for the capital-related work. Now before I conclude, I'll briefly mention our chromium cleanup of the groundwater in Hinkley. To remind you, earlier this year, we established a program that offered eligible residents a set of alternatives, including a whole house water replacement system or the choice to sell us their property. We have adjusted our cost estimates for Hinkley to reflect the responses we've received. We have also made adjustments based on the draft environmental impact report issued by the water board in August. As a result of these items, we took an additional charge of $24 million this quarter. We believe that we've developed a strong, final remediation plan, and our accruals have been based on that plan. However, the water board is not anticipated to adopt the final plan until sometime in 2013. So with that, I'll turn it over to Kent.

Thanks, Chris, and good morning. As usual, I'll run through our third quarter results and our outlook for the remainder of the year. As you'll see, the quarter was in line with our expectations. I'll also address some of the financial implications of the proposed decision on our Pipeline Safety Enhancement Plan should it be adopted in its current form. Slide 4 summarizes our results for the quarter. Earnings from operations were $0.93 per diluted common share while GAAP results were $0.84. The difference is the items impacting comparability for natural gas matters and for environmental-related costs. The components of the item impacting comparability for gas matters are shown in the table at the bottom in pretax dollars. Pipeline-related costs totaled $139 million during the quarter, including work in the field and legal costs. There were no additional accruals for third-party liability claims during the quarter, but we did book insurance recovery of $99 million in Q3. That brings total insurance recovery since the accident to $234 million. In terms of the item impacting comparability for environmental-related costs, we accrued an additional charge of about $0.03 per share in Q3, reflecting the development at Hinkley that Chris described. Slide 5 shows the quarter-over-quarter comparison from earnings from operations, including the primary factors that take us from $1.08 in Q3 last year to $0.93 in Q3 this year. While we had a $0.05 increase in rate base earnings compared to a year ago, this was more than offset by our planned incremental work across the utility, which totaled $0.10 negative during the quarter, and share dilution, which totaled $0.06. In addition, we had other smaller items that net to a negative $0.04. Slide 6 summarizes our 2012 guidance. The changes from last quarter are shown in blue. Our range for earnings from operations is unchanged at $3.10 to $3.30 per share. Our range for the item impacting comparability for natural gas matters has been updated solely to reflect the insurance recovery booked in Q3. The table at the bottom provides the ranges for each component of the natural gas matters in pretax dollars, and I'll just briefly go through them. For pipeline-related costs, the range remains $450 million to $550 million for the year, and we continue to trend towards the upper end. I need to point out that the proposed decision for the Pipeline Safety Enhancement Plan, if adopted by the PUC, would result in the write-off of some capital expenditures we've made since the program began. That effect is not included in our guidance at this point, and I'll say more about that a little later on. The third party liability claims, our range for 2012 was unchanged at $80 million to $225 million. The larger number corresponds to the upper estimate for cumulative third-party liabilities, which remains at $600 million. For insurance recoveries, you see the $135 million we booked during the first 3 quarters of the year. And has been our practice, we're not providing guidance for future insurance recoveries or for additional penalties beyond what we've already accrued. Back to the table at the top, we've updated the range for environmental-related costs to reflect the accrual taken in Q3. To date, we've accrued $0.13, consistent with our guidance of up to $0.14. In terms of equity issuance, our year-to-date total to September was $720 million. We expect some modest additional issuance for the remainder of the year through our 401(k) and dividend reinvestment plans. On our last call, I talked about our financial profile over the next few years. And Slide 7, which we used on the last call, lays out some of the drivers of this profile, including our requested CapEx and rate base, our allowed ROE, our incremental spend across the utility and then our equity needs. And I'll remind you a few of the takeaways. We expect 2013 to be a down year for earnings from operations, primarily due to year-over-year dilution, some reduction in our authorized ROE and our incremental spend across the utility. 2014, on the other hand, is the start of our next General Rate Case period, and there's an opportunity to true-up our cost and revenues for significant portions of our operations and to continue to invest in our infrastructure. Of course, this picture is clouded by the uncertainty associated with the gas pipeline issues, what the total cost will be and how the ratemaking is going to work. We hope to resolve these issues as soon as we can through the settlement process. In the meantime, the proposed decision on the Pipeline Safety Enhancement Plan provides the data points regarding some of the issues. Obviously, there is much about the PD we don't agree with, but I know many of you have been trying to assess the financial implication in the event it is approved by the commission. Now Slide 8 is also from our last call, and I just want to spend a minute on it for context before we get into the proposed decision. So let me reorient you to the slide. At the top, you can see our 2012 guidance for pipeline-related costs totaling $450 million to $550 million, and this is comprised of the 4 components shown below that. These same components will affect 2013 and 2014 costs to varying degrees. First, the Pipeline Safety Enhancement Plan expenses, which we may not recover. Second, the PSEP costs we're not requesting recovery of, such as certain work on post-1960 pipe, and we show those costs as declining after this year. Third, the other work that's been identified this year, including the rights of way work we described on our last call. We show these costs as increasing after this year. And I'll just say we're still in the process of scoping out this work, how long it's going to take and what it will cost, but we do expect the work to be significant. And then fourth are the legal and other costs, which we show as declining after this year. Now it's that first component, the PSEP cost, that's really addressed in the proposed decision. As Chris said, the PD orders us to do the work but would disallow recovery of a significant portion of those costs, including all the requested contingency amount and the advice letter mechanism to address costs above those levels. So let's go to Slide 9 which shows you the numbers from the proposed decision. The top half of the slide compares our requested expense recovery each year with the amounts recommended for recovery in the proposed decision, and then the bottom half does the same thing for capital. So I'll start with expense. Assuming we don't receive a final decision until the beginning of 2013, the PD would disallow all 2012 expenses. That's in line with our guidance that we've been providing for this year. For 2013 and 2014, the PD will leave us short for expense work by about $130 million over the 2-year period compared to our original request, which included the contingency. So that's the $81 million and the $51 million from the slide. However, as Chris indicated, our experience to date with pressure testing is that our costs will be higher than our original request. That means our unrecovered expenses in 2013 and 2014 could be roughly double the amount shown here. Now let's go to capital. The proposed decision would disallow recovery of about $400 million of capital expenditures over the 4-year period, including the entirety of our records project and all the contingency we requested. If the proposed decision were approved by the PUC, we'd have to write off the disallowed capital. For capital that's already been incurred, we'd take an immediate charge. And then for future capital that exceeds the authorized level, we'd write that off as it's incurred. To date, we've had less experience with capital work than with our expense. But our experience so far suggests that our costs are generally on track with the amounts we requested, if you include the contingency. So long as that trend continues, the amount shown here will approximate our unrecovered capital cost over this period. Now going forward, I expect this to continue to show any unrecovered PSEP costs, both expense and capital, along with other gas pipeline-related costs from the prior slide, as an item impacting comparability in 2013 and 2014. For those PSEP investments we are allowed to recover, the proposed decision would also reduce the return on equity to the level of our embedded cost of debt. They continue to earn this reduced return for a 5-year period after each project's gone into operation. After that, they'd be allowed to earn our authorized cost of equity. We estimate that the total nominal value of this reduced return could be roughly $130 million after tax over the relevant period, and that figure is shown at the bottom of the table. If the PD is approved as proposed, I'd expect us to reflect the lower return in our earnings from operations going forward rather than include it in an item impacting comparability, since earnings on rate base is typically viewed as ongoing. So that basically covers the potential impact of the PSEP proposed decision, including the unrecovered expenses, the CapEx and the reduced return on equity. I'm going to turn it back to Tony now for a few final comments.

So let me reiterate a few points before we go to the Q&A. I want to assure you, we are totally committed to resolving the outstanding regulatory issues, the 3 investigations and the rulemaking associated with our Gas Transmission business. We believe it's in everyone's best interest to reach a conclusion as soon as possible and move forward with the important work to improve the system that we've already begun without the ongoing hearings, briefings and other activities that divert resources from the primary task at hand. If we can't settle these proceedings in a global way, it will be months before we get a final decision in all of them, and I know that's frustrating to you. But I still believe the commissioners know that we're working on the right things and that we need to be financially sound to complete that work successfully. So with that, let's move to the Q&A.

[Operator Instructions] Our first question comes from the line of Michael Lapides with Goldman Sachs.

Just curious, when you put out the 8-K after the proposed decision on the PSEP came out, one data point was in there caught our eye that -- I think it had said that you had spent $95 million of capital in total on the PSEP. And if I look at, I think it was Kent's Slide 9, your proposed capital spending combined for 2011 and 2012, that's $69 million and $384 million, so closer to $454 million, $60 million or so. Just curious, are you -- after third quarter, are you still vastly underspending the proposed capital tied to the PSEP?

Michael, this is Kent. Yes, the cumulative CapEx for -- under the PSEP program through the end of Q3 was $187 million CapEx. So that number's been updated. You're right. Our original plan shown on Slide 9 here would approach $450 million, and we may not get there completely by year end. But we are going to have a significantly higher number than the $187 million by the end of year. Whatever the number, a significant portion would be written off if the PD were approved. Obviously, we're still kind of working through the details of the PD.

Okay. But this isn't -- this is a timing issue. This isn't a, "Hey, you're finding ways to spend capital at a cost lower than what you had filed originally when you made this application."

Michael, that's right. It is a timing issue, and the work was more tilted towards the latter half of the year rather than early in the year.

Our next question comes from the line of Jonathan Arnold with Deutsche Bank.

Two questions. One is can you -- I don't think you've shared sort of what the rate base would look like under the PSEP PD. Is that something you can give us some guidance on?

You know we haven't updated any rate base estimates based on the PD, Jonathan. We just have sort of the original filing. You probably can back into it by just kind of looking at what the proposed decision would disallow, but we've not actually done that.

I just wondered. So there's nothing sort of quirky we need to think about then, Kent. We could probably just take the numbers that are face value and adjust, is that...

I think you'll get pretty close that way, Jonathan.

Okay, great. And then secondly, more to do with the process. I missed the first couple of minutes. But, Tony, I believe you mentioned that, yes, you'd be -- having a mediator would still be something you guys would be in favor of. Is there sort of a time frame whereby you'd want to sort of see progress with these talks? And how long do we have to sort of figure out whether we're going to be talking or litigating?

I've given up predicting time frames. I have said often, I wanted to try and get the proceedings behind us by the end of the year. I guess until December 31, we could still get an agreement in principle. It -- now it's probably unlikely to get the agreement and get it through the regulatory approval process with just 2 months left in the year. But I think the important piece is getting the parties together, and we do believe that given the complexity and the multiple parties that all have different interests, that getting a mediator would be helpful. The discussions around George Mitchell, if you read a lot of the filings, were not an objection as such to a mediator. It was about the process of selecting that particular mediator, even though his credentials were superb. And so we're -- we've gotten back to the parties and suggested that let's see if we can get another mediator.

Right. And so it was reported -- I think CPSD filed on Friday that you were going to have a -- there was going to be a meeting today and an update to the ALJ November 1. Is that still the -- is that the sort of the latest and greatest?

Yes. I'm not going to comment on the specific timetable of any meetings, Jonathan. But I can tell you, I mean, there isn't a day that goes by that we're not working that issue.

Our next question comes from the line of Brian Chin with Citigroup.

Just to clarify a comment you made on Slide 9. You said that unrecovered expenses on the expense side of things could be double what we're showing here. I just want to make sure I understand that, that is the difference row that you're looking at for '13 and '14, that would be largely a number we can take twice as large now on that difference line if we were to update for the most recent estimates?

Brian, that's correct. This is Kent. And essentially, the main driver here is the pressure testing. And I think we've talked in the past, on prior calls, that our unit costs there have been in excess of $1 million a mile and our filing, including the contingency, was more in the range of $600,000 per mile. So when you apply that to about 350 miles we have planned for 2013 and 2014, you get a number, an increment, above that $130 million that's about equivalent to that amount.

Our next question comes from the line of Greg Gordon with ISI Group.

Majority of my questions have already been answered. But I do have a question regarding the PSEP proposed decision. It strikes me that -- and please correct me if you think I'm wrong here, that the proposed decision in sort of opining that you should earn a modified equity return on the investments you're making that are deemed prudent and useful would sort of be selectively regulating you differently from the same types of investments that are being made by other utilities in the state to comply with the same plans. So if you -- they were ultimately to approve that, if the CPUC ultimately approve that, do you have recourse in the courts? Because it's essentially selective ratemaking on similar investments. And also does it just sort of blur the lines between the penalty phase, which is in the OIIs and this OIR, which is supposed to deal with capital investments and related to these new rules?

Well, I think we'll take your comments in the transcript and use that as our brief because those are exactly the points that we'll make. We think that's inappropriate. If the work is work that we ought to be doing and that we're going to get recovery of, then we ought to get recovery, full recovery of it, including a allowed return on equity on that, and we'll be making that point of not only -- we won't wait for appeal. We'll wait -- we'll make that point when we go to the commission. Remember this is a proposed decision. And we'll be making our points with the commission, and then they'll make their decision.

Our next question comes from the line of Jim von Riesemann with UBS.

Just a quick question, more of a modeling type, but how do you guys think about your long-term effective tax rate going forward? Because I know last year and this year, whether it's the quarter or the trailing 9 months, it's sub-30%. How should we think about that on a sustained basis?

Jim, this is Kent. We don't exactly provide guidance on our tax -- effective tax rate in future years. But obviously, the last few years have been very unusual with bonus depreciation, very, very unusual. And at some point, we will see that kind of get back to normal going forward. I think the other thing is just, going forward, we do have a lot of questions about what will tax policy be. We don't know whether or not bonus will be continued beyond this year. But then there's lots of other proposals out there for tax policy. So that one's going to be a tough one to wrap our minds around at this point.

I think I'd also remind -- this is Gabe. I'd remind everybody that we have said over the last few years, we've had a number of sort of overhanging tax issues that we had settled from many years ago. Those are being worked down very rapidly, and we would expect that we would not have that level of tax issues to be working through in the future.

Our next question comes from the line of Anthony Crowdell with Jefferies. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: I guess 2 quick questions, hopefully. When the settlement discussions are going on or when the procedural calendar, I guess, was suspended, there was a date of November 1, where -- I want to know, does the procedural calendar start up again? Just what happens on that November 1 date. And the second question, the company seems optimistic, or even the interveners, that a mediator would work best. But the selection of Mitchell's team, definitely created a very charged atmosphere out there in California, I mean, who -- was it the CPUC or was it the utility that was really driving the selection of Mitchell?

Well, I'll start off with that second part of that question. It was the CPUC's process selection and contacted the Senator, not the utility. And I'll let Tom comment on the procedural schedule going forward.

This is Tom Bottorff from Regulatory Affairs. The only procedural issue at this point for November 1 is waiting for CPUC to report on the progress of the discussion at that point with the ALJs in proceeding. So that's the next significant date in the process. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: Do the hearings start up again? Or the -- like I -- I thought there were still some more hearings to go on maybe like 6 or something like that. Do they start automatically on November 1, or they're still suspended?

Those hearings are suspended. If they do resume, it wouldn't be until November 26.

Our next question comes from the line of Travis Miller with Morningstar Securities Research.

Real quick, I wondered if there was any precedent for CPUC for offering a lower ROE on any kind of capital investment.

Travis, this is Kent. We did have experience back in the '90s where the PUC authorized all the utilities to have a lower return on other generation assets, and that's the one that comes to mind for me.

Is there any kind of correlation there that you could use on an appeal basis, or anything involved in that?

I don't know that that decision at the time was appealed by the utilities. It was all part of industry restructuring at the time, wrapped into a very complex dynamic going on in regulation.

Sure, okay. And then real quick, the financing plan, if that proposed decision were to be approved, would that be pretty much in line with capital expense and operating spec spend? Or would there be some kind of timing issue there in terms of equity and debt issuance?

Well, the proposed decision essentially has similar capital to what we had planned, and it essentially says, "Go ahead and get the work done. You just won't get recovery of all your capital." And on the expense side, again, it's get the work done without the contingencies that you need to complete the expense amount. I would say on the margin, the impact of the proposed decision, because of the disallowances, on the margin, it will drive somewhat more equity issuance than long-term debt in order to finance the overall program. And essentially, the after tax amounts of the write-ups drive some incremental equity issuance. That's the way to think about it if you're modeling it.

Our first -- our next question comes from the line of Dan Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just -- yes, maybe 2 mechanical questions. Number one, Kent, could you talk a little bit about how and when you would assess having to revise the expected fine from $200 million to another number?

I'm sorry, Dan. Can you restate your question? I couldn't hear it all. Dan Eggers - Crédit Suisse AG, Research Division: Yes. I'm sorry about that. Can you just walk through a little bit the process for reevaluating the level of fine you guys are assuming in your numbers in equity rate, so far as adjusting the $200 million to a new number?

Yes. Dan, we actually do that assessment every quarter. And essentially, the thought process we go through is we look at all the information available to us, through the regulatory process and otherwise, and to try to assess whether or not $200 million is still at the lower end of a reasonable range. And you can infer from our reporting this quarter and the quarter before and so forth that we've not had a basis for increasing that reserve to this point. Dan Eggers - Crédit Suisse AG, Research Division: Okay. And I guess one other question. Can you just tell us where you are as far as authorization for more equity issuance? I mean, could you turn on the DRIP in the fourth quarter or next year? Is there new authorization that has to occur?

If you're talking about the 401(k) and dividend reinvestment, if it's that DRIP, that -- those are our internal programs and that's fine. On the dribble program, we do have authorization. But the program we have, I don't remember exactly how much is left in it, but it's something like $60 million or $70 million left. Of course, we could replace that with another program when the timing was appropriate.

Our next question comes from the line of Paul Patterson with Glenrock Associates.

Just to clarify a few things. The mediator, the other parties are not objecting, you said, to a mediator. Is that -- did they want a mediator? Is that -- do I understand that correctly?

All we can read into is -- if you saw some of their public statements objecting to Senator Mitchell, and a number of the public statements and letters specifically said they don't have a problem with a mediator, I guess it was the selection process for the Senator that they were concerned with. And so we will be now raising the issue of, okay, are there other mediators, and of course, there are dozens and dozens of very successful mediators out there. And we'll suggest the -- there's a process that we ought to go through and select one.

How long do you think that might take?

As I said before, I've given up predicting. We'll work it every day.

Okay. And then on -- I think Travis was asking a question on the ROE reduction, and you mentioned the generation assets in the 1990s. And as I recall, there was some securitization there. Is there any discussion of securitization as a means of sort of dealing with this sort of low ROE asset? Theoretically, there could be a tax benefit for rate payers and what have you. I'm just speaking just in general the securitization. Any of the -- any of this -- the options or -- of strategy that's being discussed at all?

No, there hasn't been any discussion like that to date.

Okay. And then just on the actual ROE cost of capital case. The schedule doesn't look like it's changed. So I'm just wondering, given the slippage that we're seeing, not just in your case, just in general, I mean, it seems that the -- the PUC seems to takes some time quite often, more than scheduled. Do you still think we're really -- the schedule still holds for the -- I notice the testimony seemed to be filed and stuff. Just -- do you think it's still going to happen at that time, or any flavor on that?

Yes. I'm very hopeful that it will. And it's stayed right on schedule. The utilities -- everyone just filed their briefs last week. So it's chugging along. It's a fairly straightforward proceeding really, and we are hopeful that we'll have a final decision on phase 1 by year end.

Okay. And then just finally, the Safe Harbor -- there's been a few changes in Safe Harbor statement. And I noticed, I think, the addition of the nuclear issues, potential legislation or regulation, and I know you guys had some seismic stuff going on. But I'm just wondering, I don't believe I saw that last quarter. And I was just wondering, has there been any change that we should be thinking about on that area? It -- with the -- either with respect to seismic or post Fukushima or something like that, that we should be thinking about that has come up?

Paul, this is Gabe. It's really just our attempt to make sure that we're adequately covering everything in our disclosures, and specifically with these risk factors.

Okay. So there's not anything new that we should be -- that's developed that you're particularly concerned that we should be thinking about?

Well, I think we have disclosure. We're actually making progress in getting the approvals to do the seismic testing. So we're moving in the right direction there.

Our next question is a follow-up question from Michael Lapides with Goldman Sachs.

Just a handful of things. First of all, I want to make sure I follow your comments that when I look at Page 9 of the slide deck, the expense you will still show, even if it's more than what's on the slide, you will still show as a nonrecurring item impacting earnings. The capital and, therefore, any potential write-offs of capital, you'll show in the lower ROE. The capital write-offs you would show as nonrecurring items. But the lower ROE on which you are allowed to earn on, you will actually include in ongoing EPS.

A little different, Michael. The shortfall for expense, and for our recovery of capital, we would show as an item impacting comparability. It just gives you more transparency. You guys can keep track of the pieces that way. The ROE component that reduced return on the subsets of our rate base, which is related to the PSEP, that we would just put in earnings because that's really return rather than a cost.

Got it, okay. Can you give -- I'm going to change topic off the PSEP a little bit. Can you give an update on the cash flow impacts expected for both Hinkley and the generator settlements?

I think I'll take Hinkley first. In the case of Hinkley, most of what you've been seeing here have been accruals related to the whole house water situation, and those are fairly near term -- and property purchases. So they're fairly near-term items for -- like the accruals we've done this quarter. When you look at our overall accruals, one is up for Hinkley, there's a significant amount that is really over a very long period of time. That's the remediation of the chromium itself, and that goes on for years. So it really depends which part, but these most recent accruals will be nearer term because we're, essentially, in the process right now of providing those options and the residents have selected them. The second thing in terms of the generator settlements, Gabe, do you want to take that one?

Yes. Michael, on the generator settlements, there's really no news there other than what we said, I believe, on our last 10-K. And I think as everybody who's followed us knows, there is an overhang of several hundred million dollars or more that will require financing if all of the remaining generator claims that haven't been settled were settled all at once. That's fairly unlikely. We're having small settlements over time. But at some point, what remains will probably have to be decided by FERC.

Okay. And coming back on the Hinkley, just want to make sure I follow. Have the cash flow impacts mirrored the earnings impacts over the last year or so, or are the accruals solely for anticipated future cash flow spending on the more near-term items, Kent, that you addressed?

The cash flow impact, it really only mirrored the accruals reasonably closely. I mean, there's always a little bit of a lag, but it's really for this whole house water and property purchase. And even that, there's somewhat of a lag, certainly within quarters. It's the final remediation which we've taken significant accrual for, that does not mirror the cash flows at all. The cash flows will be much more gradual on that one.

Our next question comes from the line of Ashar Khan [ph] with Visium Asset Management.

Sorry, I joined a little bit late, Kent, so I don't know if it was addressed. Can you just talk about -- there was a note from the rating agencies that came out last week, which had negative implications from the proposed order. Can you just talk about what your conversation with the rating agencies are? And what is -- in your view, how does the company try to maintain its credit ratings where they are? Is that a focus? Could you share your thoughts there, please?

Well, we have been in conversations with the rating agencies once the PD from the PSEP came out. In many ways I like letting the rating agencies speak for themselves in their own reports, and obviously, people have access to the agencies themselves. I will say the way I look at the issue is it's not simplistically a numerical issue where you just look at our credit ratios. It's not that. I think the rating agencies to me it's more important to really be focusing on the overall appropriateness of the resolution of all the gas issues and whether or not that continues to signal a balanced regulatory environment in California or not. And I think that's really the key indicator that I believe the rating agencies are focused on.

Okay. So it's more of a qualitative issue than a quantitative issue?

I think that's fair.

Okay. And then, can I just -- so the time line still remains, right? There's been no change in the time line regarding -- right? There was a November 26 drop-dead date before the OIIs fine was to come out. That still remains intact, is that correct, or am I wrong?

That date is scheduled for the end of November. And whether it comes out or not depends on the status or success or progress in the negotiations that are ongoing.

Okay. So -- but those dates have not been changed, right?

No.

There are no additional questions waiting from the phone lines.

All right. In that case, I will wish everybody a safe day. Please stay inside and make sure you and your family are protected. Thanks very much.

Thank you, ladies and gentlemen, for attending the Third Quarter Earnings Conference Call. This would now conclude the conference. Please enjoy the rest of your day.