Good morning, welcome to the third quarter earnings 2012 conference call. All lines will be muted during the presentation portions of the call, with an opportunity for questions and answers at the end. At this time, I would like to introduce your host, Gabriel Togneri with PG&E. Thank you, enjoy your call. You may proceed, Mr. Togneri.
Thanks, Monique. Hello everyone, 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 One, located in the appendix of today's slides. 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. With that, I'll hand it over to Tony.
Thanks, Gabe, good morning, everyone. Before I start, I know many of you are on the East Coast, I want to urge you to make sure that you're in a safe location. Please don't try and travel until the storm passes and we 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, I'll turn it over to Chris and Kent. On slide two, as you've seen before, our focus is on three 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, 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, Chris is going to elaborate more on this point. As it stands, the proposed decision is punitive and with costs 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 result 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 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. With that, let me turn it over to Chris to go into some of these things in detail.
Thanks, Tony. Good morning, everyone. As you can see on slide three, 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 will also provide an update on Hinkley, the environmental activities there. You will 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 two months' time in response to the CPUC directive to develop a comprehensive multi-year 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 above 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 will 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 ROE on PSEP capital investments, 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 have 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 expensive component of the planned PSEP expenses. We did achieve a 25% cost reduction in 2012 compared to our per-mile cost in 2011. We expect the strength testing in 2013 and 2014 to be at a similar unit cost as it is in 2012. 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 five 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've 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 lengthier permitting processes, as well as land acquisition delays and project re-engineering. The pipeline replacement cost is expected to be at a level consistent with our request when you include the contingency in 2013 and 2014. In our work validating the Maximum Allowable Operating Pressure, or the MAOP, 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 cost associated with these programs are in line with what we assumed in the PSEP filing when including the contingency. 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. Before I conclude, I'll briefly mention our chromium cleanup of the groundwater at 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 a final plan until sometime in 2013. 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 four 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 pre-tax 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. We did book insurance recoveries 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 developments at Hinkley that Chris described. Slide five 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-based 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 six summarizes our 2012 guidance. The changes from last quarter are shown in blue. Our range for earnings from operations is unchanged at $3.10-$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 pre-tax dollars. I'll just briefly go through them. For pipeline-related costs, the range remains $450-$550 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 impact is not included in our guidance at this point. I'll say more about that a little later on. The third-party liability claims, our range for 2012 is unchanged at $80 million-$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've booked during the first three quarters of the year. It's 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 through 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 seven, 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. 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. It's an opportunity to true up our costs 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 rate making's 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 a data point regarding some of the issues. Obviously, there's much about the PD we don't agree with, but I know many of you have been trying to assess the financial implications in the event it is approved by the commission.
Now, slide eight 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. Let me reorient you to the slide. At the top, you can see our 2012 guidance for pipeline-related costs totaling $450-$550, and this is comprised of the four 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 PSIP 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.
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'll cost, but we do expect the work to be significant. Then fourth are the legal and other costs, which we show as declining after this year. Now it's that first component, the PSIP 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 amounts and the advice letter mechanism to address costs above those levels. Let's go to slide nine, 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.
The bottom half does the same thing for capital. 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 would leave us short for expense work by about $130 million over the two-year period compared to our original request, which included the contingency. That's the $81 million and the $51 million on the slide. However, as Chris indicated, our experience to date with pressure testing is that our cost will be higher than our original request. That means our unrecovered expenses in 2013 and 2014 could be roughly double the amount shown here. Let's go to capital.
The proposed decision would disallow recovery of about $400 million of capital expenditures over the four-year period, including the entirety of our records project and all the contingencies 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 take an immediate charge. As 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. Long as that trend continues, the amount shown here will approximate our unrecovered capital costs over this period.
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 five-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 included in an item impacting comparability, since earnings on rate base is typically viewed as ongoing. 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.
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 three 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. 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.
With that, let's move to the Q&A.
Certainly. We will now allow questions from the phone lines. Ladies and gentlemen, to ask a question, press star followed by one on your touchtone keypad. If you would like to remove your question, press star followed by two. If you are using a speakerphone, please pick up your handset before using your keypad. Again, to ask a question, press star followed by one. We will pause a moment to allow questions to generate. Our first question comes from the line of Michael Lapides with Goldman Sachs. You may proceed.
Hey, guys. 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 nine, 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, after third quarter, are you still vastly underspending the proposed capital tied to the PSEP?
Hey, Michael. This is Kent. Yeah, the cumulative CapEx for under the PSEP program through the end of Q3 was $187 million CapEx, that number's been updated. You're right, our original plan shown in slide nine here would approach $450 million. We may not get there completely by year-end, but we are going to have a significantly higher number than the $187 by the end of the 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. 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.
Got it. Okay. Thanks, guys.
Thank you, Mr. Lapides. Our next question comes from the line of Jonathan Arnold with Deutsche Bank. You may proceed.
Well, good morning, guys.
Hey, Jonathan.
Good morning, guys.
Two questions. One is, 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?
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. We've not actually done that.
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. Secondly, a bit more to do with the process. I missed the first couple of minutes, but Tony, I believe, mentioned that having a mediator would still be something you guys would be in favor of. Is there sort of a timeframe whereby you'd want to sort of see progress with these talks? How long do we have to sort of figure out whether we're going to be talking or litigating?
I'm giving up predicting timeframes. I've said often I wanted to try and get the proceedings behind us by the end of the year. I guess until December 31st, we can still get an agreement in principle. It's probably unlikely to get the agreement and get it through the regulatory approval process with just two months left in the year. I think the important piece is getting the parties together. 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.
We've gotten back to the parties and suggested that let's see if we can get another mediator.
Right. It was reported, I think CPSD filed on Friday, that there was going to be a meeting today and an update to the ALJ November 1st. Is that the sort of latest and greatest?
Yeah, I'm not going to comment on the specific timetable of any meetings, Jonathan, but I can tell you, there isn't a day that goes by that we're not working that issue.
Okay, great. Thank you, Tony. Thanks for the call.
Thank you, Mr. Arnold. Our next question comes from the line of Brian Chin with Citigroup. You may proceed.
Hi, good morning.
Morning, Brian.
Brian.
Just to clarify a comment you made on slide nine, 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-
Yes
for 2013 and 2014. 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. Essentially, the main driver here is the pressure testing. I think we've talked in the past on prior calls that our unit cost there has been in excess of $1 million a mile, and our filing, including the contingency, was more in the range of $600,000 per mile. When you apply that to about 350 miles we have planned for 2013 and 2014, you get a number, an increment above this $130 that's about equivalent to that amount.
Okay, great. Thank you.
Thank you, Mr. Chin. Our next question comes from the line of Greg Gordon with ISI Group. You may proceed.
Thanks. 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. If they were ultimately to approve that, if the CPUC were to approve that, do you have recourse in the courts because it's essentially selective rate making on similar investments?
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. 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 full recovery of it, including an allowed return on equity on that. We'll be making that point. We won't wait till appeal. 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.
Thanks, guys.
Thank you, Mr. Gordon. Our next question comes from the line of James von Riesemann with UBS. You may proceed.
Good morning, California.
Morning, Jim.
Just a quick question, more of a modeling type, 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 nine 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 effective tax rate in future years. Obviously, the last few years have been very unusual with bonus depreciation. Very, very unusual. 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. There's lots of other proposals out there for tax policy. That one's going to be a tough one to wrap our minds around at this point.
Okay. Thank you.
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 have settled from many years ago. Those are being worked down very rapidly. We would expect that we would not have that level of tax issues to be working through in the future.
Thank you, sir. Next question comes from the line of Anthony Crowdell with Jefferies. You may proceed.
Good morning, guys. I guess two quick questions, hopefully. When the settlement discussions were going on or when the procedural calendar, I guess, was suspended, there was a date of November first where I want to know, does the procedural calendar start up again, just what happens on that November first date? The second question, the company seems optimistic or even the interveners that a mediator would work best, but the selection of Mitchell seemed that it created a very charged atmosphere out there in California. Was it the CPUC or was it the utility that was really driving the selection of Mitchell?
I'll start off with the second part of that question. It was the CPUC's process selection and contacted the senator, not the utility. I'll let Tom comment on the procedural schedule going forward.
Yeah. Hi, this is Tom Bottorff from Regulatory Affairs. The only procedural issue at this point for November 1st is waiting for CPUC to report on the progress of discussions at that point with the ALJs and proceedings. That's the next significant date in the process.
Do the hearings start up again? I thought there was still some more hearings to go on, maybe six or something like that. Do they start automatically on November 1, or they are still suspended?
Those hearings are suspended. If they do resume, it wouldn't be until November 25th.
Great. Thank you.
Thank you, Mr. Crowdell. Our next question comes from the line of Travis Miller with Morningstar Securities Research. You may proceed.
Good morning. Thanks. Real quick, I wondered if there was any precedent at the CPUC for offering a lower ROE on any kind of capital investment.
Yeah, 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 their 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 regulations.
Sure. Okay. Then real quick, the financing plan, if that proposed decision were to be approved, would that be pretty much in line with capital spends and operating spend, or would there be some kind of timing issue there in terms of equity and debt issuance?
Well, the proposed decision essentially has a similar capital to what we had planned. It essentially says, go ahead and get the work done. You just won't get recovery of all your capital. On the expense side, again, it's get the work done without the contingency 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. Essentially, the after-tax amounts of the write-offs drive some incremental equity issuance. That's the way to think about it if you're modeling it.
Okay. Thanks a lot.
Thank you, Mr. Miller. Our next question comes from the line of Dan Eggers with Credit Suisse. You may proceed.
Hey, good morning, guys. Just maybe two mechanical questions. Number one, Kent, can you speak 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 at all.
Yes. I'm sorry about that. Can you just walk through what would be the process for reevaluating the level of fine you guys are assuming in your numbers and equity raise so far, so adjusting the $200 million to a new number?
Yeah, Dan, we actually do that assessment every quarter. Essentially, the thought process we go through is we look at all the information available to us, through the regulatory process and otherwise, to try to assess whether or not $200 million is still at the lower end of a reasonable range. 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.
Okay. I guess one other question. Can you just tell us where you are as far as authorization for more equity issuance? Could you turn on the DRIP in the fourth quarter or next year? Is there a new authorization that has to occur?
If you're talking about the 401(k) and dividend reinvestment, if it's that DRIP, those are our internal programs, and that's fine. On the DRIP program, we do have authorizations, 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.
Okay. Thank you.
Thank you, Mr. Eggers. Our next question comes from the line of Paul Patterson with Glenrock Associates. You may proceed.
Good morning.
Hi, Paul.
Just to clarify a few things. The mediator, the other parties are not objecting, you said, to a mediator. They want a mediator? Do I understand that correctly?
All we can read into it is 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, just it was the selection process for the senator that they were concerned with. 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 there's a process that we ought to go through to select one.
How long do you think that might take?
As I said before, I've given up predicting.
Okay.
We'll work it every day.
Okay. Then, I think Travis was asking the question on the ROE reduction, and you mentioned the generation assets from the 1990s. As I recall, there was some securitization there. Is there any discussion of securitization, as a means of dealing with this sort of low ROE asset? Theoretically, there could be a tax benefit for ratepayers and what have you. I'm just thinking, just in general, securitization, any of the options or a strategy that's being discussed at all?
No, there hasn't been any discussion like that to date.
Okay. Then just on the actual ROE cost of capital case. The schedule doesn't look like it's changed, and I'm just wondering, given the slippage that we're seeing, not just in your case, just in general. It seems that the PUC seems to take some time, quite often, more than scheduled. Do you still think the schedule still holds for the call? I noticed the testimony seems to be filed and stuff. Do you think it's still going to happen at that time? Or any flavor on that?
Yeah. I'm very hopeful that it will. It has stayed right on schedule. The utilities, everyone just filed reply briefs last week, it's chugging along. It's a fairly straightforward proceeding, really, we are hopeful that we'll have a final decision on phase one by year-end.
Okay. Just finally, the safe harbor. There have been a few changes in the safe harbor statement. I noticed, I think the addition of the nuclear issues of potential legislation or regulation. I know you guys had some seismic stuff going on. I was just wondering, I don't believe I saw that last quarter, I was just wondering, has there been any change that we should be thinking about on that area with either respect to seismic or, post Fukushima or something like 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 specifically with these risk factors.
Okay. There's not anything new that's developed that you have particular concern that we should be thinking about?
Well, I think we have disclosed we're actually making progress in getting the approvals to do the seismic testing, so-
Right
We're moving in the right direction there.
Okay, great. Thanks a lot.
Thank you, Mr. Patterson. Our next question is a follow-up question from Michael Lapides with Goldman Sachs. You may proceed.
Hey, guys. Just a handful of things. First of all, want to make sure I follow, Kent, your comment that when I look at page nine of the slide deck, the expense you will still show, even if it's more than what's on this slide, you will still show as a non-recurring item impacting earnings. The capital and therefore any potential write-offs of capital, you will show in the lower ROE. The capital write-offs you would show as non-recurring items, but the lower ROE on which you are allowed to earn on, you will actually include an ongoing EPS?
A little different, Michael. The shortfalls for expense and for recovery of capital, we would show as an item impacting profitability. It just gives you more transparency. You guys can keep track of the pieces that way. The ROE component, that reduced return on the subset 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. 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'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 property purchases. They're fairly near-term items for the accruals we've done this quarter. When you look at our overall accruals 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. 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, you want to take that one?
Michael, on the generator settlements, there's really no news there other than what we said, I believe, on our last 10-K. 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. At some point, what remains will probably have to be decided by FERC.
Okay. Coming back on to 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 has really only mirrored the accruals reasonably closely. 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 accruals for, that does not mirror the cash flows at all. The cash flows will be much more gradual on that one.
Got it. Okay. Thanks, guys.
Thank you. Our next question comes from the line of Ashar Khan with Visium Asset Management. You may proceed.
Good morning. Sorry I joined a little bit late, so I don't know address it. 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 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 gaps issues and whether or not that continues to signal a balanced regulatory environment in California or not. I think that's really the key indicator that I believe the rating agencies are focused on.
Okay. It's more of a qualitative issue than a quantitative issue.
Mm-hmm. I think that's fair.
Okay. The timeline still remains, right? There's been no change in the timeline regarding, right? There was a November 26th drop-dead date before the OII's 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. Those dates have not been changed, right?
No.
Okay. Thank you so much.
Thank you, Mr. Khan. 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 families are protected. Thanks very much.
Thank you, ladies and gentlemen, for attending the third quarter earnings conference call. This will now conclude the conference. Please enjoy the rest of your day.