Hello and welcome to the PG&E Corporation Third Quarter Earnings 2013 Conference Call. [Operator Instructions] I would like introduce your host Mr. Gabe Togneri with PG&E. Thank you, you may proceed.

Hello, everyone and thanks for joining us. Before you hear from Tony Earley, Chris Johns and Kent Harvey, I'll provide you with the usual reminder that our discussion is going to include forward-looking statements about future financial results and these are based on assumptions, expectations and information that's currently available to management. Some of the important factors that could affect the company's results are described on the second page of today's slide deck and in addition, we encourage you to review the Form 10-Q that will be filed with the SEC later today and also the discussion of risk factors that appears in the 2012 annual report. And with that, I'll hand it over to Tony.

Thank you, Gabe. We've got a fair amount to cover today and I'm going to start with the gas business. We continue to make progress in the field to improve the safety and reliability of our system. We've gathered an unprecedented amount of data about our Gas Transmission system and we're using our comprehensive pipeline features database to prioritize our pipeline safety work. This has resulted in some changes to the work plan and higher unit costs for work on the pipeline safety enhancement plan, as compared to the filing that we made a couple of years ago. Yesterday, we filed a required update with the CPUC that reflects these changes. As a result, we'll be taking a charge for the additional costs that won't be recovered from customers. We're disappointed to have to do this but it reflects the complexity and the challenges of this important gas safety work, and Chris will go through the details in just a couple of minutes. A noteworthy accomplishment this quarter was the resolution of substantially all of the remaining San Bruno related third-party claims. From the beginning, our focus has been on bringing closure as quickly as possible through settlements that treat people fairly. The judge overseeing the case expressed how pleased he was that we're able to work with the plaintiffs to resolve these significant cases without going to trial and we are proud of the outcome. Also the San Mateo County District Attorney's Office has publicly indicated they will not be pursuing criminal charges under state law. However, the federal investigation under the Pipeline Safety Act is ongoing and we continue to cooperate with the U.S. Attorney's Office on that. In the regulatory area, the gas penalty proceedings are taking much longer than we had ever expected. However, the record…

Thanks, Tony, and hello, everyone. I'll begin my remarks focused on operations and then touch on the regulatory proceedings. Although we've had a lot of success in our overall operations, I'm going to focus my comments on gas ops today. First on Slide 4, you can see the significant amount of work we've completed to make our pipeline safer just since the beginning of this year. Over the past few years, we've been testing and replacing more pipeline miles and installing more automated shutoff valves than just about any utility that I'm aware of. Much of the pipeline safety work we've been doing was based on the Pipeline Safety Enhancement Plan that we filed in 2011. The CPUC approved the work in December of 2012 but only gave us partial recovery of our costs. That decision also required us to update the plan once we had finished validating the Maximum Allowable Operating Pressure for all 6700 miles of our transmission pipelines. We recently completed that effort and used the result to reprioritize every pipeline segment for strength testing, which is funded with expense dollars and pipeline replacement, which is capital work. Yesterday, we filed the required Pipeline Safety Enhancement Plan update application with the commission. The biggest change is to the pipeline replacement component, which is the capital side of the program. About 90 miles or roughly 1/2 of the previously planned replacements were removed from the program and about 50 miles were added to the pipeline replacement portfolio, again based on the reprioritized risk ranking. Although there were fewer miles to replace in total, many of the miles reflected in the update are short pipeline segments, each with costs comparable to the longer segments. In addition, many of the segments included in the reprioritized and updated plan are in…

Thank you, Chris. As usual I'm going to go through our Q3 results, as well as guidance and I'll address the impact of the PSEP capital charge that Chris discussed. Slide 6 summarizes the results for the third quarter and earnings from operations were $0.88 per share and GAAP results were $0.36. The differences in our item impact comparability related to natural gas matters, which totaled $0.52 in the quarter. As usual that's broken out in pretax dollars in the table at the bottom of the slide. Pipeline-related expenses totaled $113 million pretax in Q3 and these include the strength testing work in our pipeline safety enhancement plan, our rights-of-way and integrity management work and then our legal costs. Next you see the $196 million pretax charge that Chris described, related to the required update to the Pipeline Safety Enhancement Plan. Again these are capital costs we expect to incur for pipe replacement work, which we don't expect to recover from customers. In Q3, you see there were no changes in our accrual for potential fines in connection with the gas pipeline investigations. Our accrual remains at $200 million. During the quarter, we did increase our accrual for third-party liability claims by $110 million as a result of settling virtually all remaining third-party claims in Q3. The total accrual for third-party liabilities stands at $565 million, which is within our previously established range of up to $600 million. During Q3, we also recognized $25 million of additional insurance recoveries and that brings total insurance recoveries to-date to $354 million. Slide 7 shows the quarter-over-quarter comparison for earnings from operations. Our lower authorized cost of capital resulted in a reduction of $0.09 compared to Q3 of last year and our increased shares outstanding resulted in a $0.04 reduction. These negative factors…

Thanks, Kent. Let me just summarize what we're doing to both resolve outstanding issues and to move the company forward. First, we're focused on wrapping up the uncertainty related to the gas penalty proceedings and we expect the final result in the first quarter of 2014. Second, on third-party liability claims, we're in good shape and we expect to recover a significant portion of the cost through insurance and we're going to continue to work through that process. Third, the hearings and all subsequent regulatory briefs for the General Rate Case are all completed and we're now awaiting the proposed decision in the GRC. And fourth, we're working on the gas transmission rate case that will be filed by year end. The GRC and the gas transmission cases are critical to our path forward. We made solid progress executing on our plans and we know we're laying the foundation for future success. So with that, we'll open up the lines and answer your questions.

[Operator Instructions] Our first question comes from the line of Leslie Rich with JPMorgan.

So just in terms of thinking of the timing of the ALJ rulings, I know they're on really separate and distinct paths. But is it possible that you get an ALJ ruling on the GRC, before you get an ALJ ruling on the fines and penalties? And then in terms of the commission decision on the final decisions for both of those, are they interrelated at all or really sort of separate and distinct?

I'll let Tom comment in a minute, but since the record is closed and now the ALJs are working on their decisions, it really is up to the ALJ to decide how to orchestrate when they issue those decisions. And I'm not privy to what their thinking is, but they really have lots of flexibility right now. Tom, I don't know if you have any more insights.

I think that's right. On the General Rate Case, Chris mentioned schedule calls for the GRCP to come out in November, that may or may not happen but that's the current schedule. And with respect to the posed decisions [ph] on the 3 investigations, we expect those to come out in mid-December. That remains to be seen as well, but the procedural schedule would call for that kind of outcome. I don't think that the 2 decisions are being coordinated. I think they're on separate tracks. The judges do communicate with one another occasionally, but I think they're working on their own decisions and trying to get them out as quickly as possible.

And then the final decisions are sort of typically within 60 to 90 days, but not necessarily?

Yes, it could be as early as 30, that rarely happens. Yes, 60 to 90 is realistic.

Our next question comes from the line of Steven Fleishman of Wolfe Research.

I have a couple of questions. First on this issue of -- I guess there's kind of like a revenue per mile cap in the PSEP 1 final order, could you just explain a little better why it matters, how much cost per mile?

This is Chris. I'll start off and then Tom can come in on some of requirements from the regulatory process. But in general when the order was put together and the supporting work papers behind that, it identified a certain amount of work and then allowed revenues based on that certain amount and type of work that was being done. So when we've taken work out and put work back in, it basically reduced the amount of work being done and therefore, the revenues go down with that. Unfortunately, when you look at the mix of work that's remaining to be done, it is at a higher unit cost. And so it wasn't - the way it was set up was not something that allowed us a bucket of dollars to do a bucket of work. It had a cap on it based on the very specific type of work that was done and so unfortunately, the way the order works out for us is that the revenues are decreased because the amount of work is decreased. And it was indifferent as to what the cost per unit was and the types of work that we're seeing that's left to do is, as I've said in instances in different terrains and situations where the cost per unit is higher.

Okay.

Remember, Steve, we had also proposed contingencies that were disallowed in that case, which we didn't think was fair because of the uncertainties like this and that has hurt us.

Tony, you've talked before about -- with the right kind of GRC orders, being able to earn your allowed return, I guess, electric in '14 and gas '15. Can you say that, that's still feasible?

That's still our objective. I think as we've said in the past, I was pleased with the way the GRC went in. Remember, the commission had asked us to really focus on risks and safety and what we're doing, we did that. They hired independent consultants to look at both the gas business and -- the gas distribution business that's in that case and the electric business. The consultants had favorable reports and the interveners in the case really did not take issue with the safety analysis and the risk analysis. It was really just, well, we don't want rates to go up too high, and in the case, we've shown that even if we were granted the full relief, which obviously never happens but even if we were granted the full relief, the average customer bill is still below the national average. And so I'm guardedly optimistic that we will get a good result and we believe with a good result in the GRC that we certainly have an ability to earn -- or meet our objective and earning allowed return [ph]. On the second piece, Gas Transmission & Storage. That case, as Chris said, we'll file by the end of the year. Once we file it, we'll see what the reaction to it is from various interveners and get a better feel for whether it's going to be hotly contested or whether people say, yes, you really do need to spend on Gas Transmission & Storage. Because remember, a lot of new requirements that we have to cover in that case.

And then just 1 other question to clarify the other rights-of-way issue. I mean, in the past when you've talked about the $500 million, you kind of would say that we're still kind of on track for that. I mean is that fair to say at this time, if it's still kind of -- is that estimated?

This is Chris, and as I said earlier, we're getting near completion. We still have just do San Francisco, which is a more congested area to go through but based on what we've seen, we're reiterating the $500 million at this time.

Okay. And then 1 last thing, can you just explain kind of what happened with this San Carlos situation and how -- how these might be handled going forward?

Sure, Steve. This is Chris again, and one of the things that everybody needs to recognize this obviously this is a very politically-charged environment that we're working in right now. And when you look at San Carlos, this is what we refer to as our Line #147 and we pressure tested that line in 2011 and have done the work on it that we're convinced makes it a safe line and we reiterated that to the commission and to our customers. But the issue that arose is that when we were in 2012 doing some follow up excavation on a routine leak survey and repair, we found in there that some of our records associated with that line weren't accurate. So we updated those and we did alert the CPUC and their staff to that process. And then eventually filed making sure that -- through an errata filing that folks were aware that we found that discrepancy. And quite frankly, that's part of what we want to do. As we're doing work, we want to constantly challenge and make sure that our records and the pipes are safe, and so we're going to continue to look for those kinds of things. But as we went through that, that caused the others in San Carlos to get concerned and that's where it's become a little bit more involved in the press and through the political process. But the CPUC did -- because they took issue with and had concerns about the timing of how we -- of when we notified them and the method of which we notified them, they opened these orders to show cause and both of those are proceeding now. It's hard to estimate what the outcome will be on those but we do anticipate that we will wrapped up in the next month or 2, especially on the one that we need to get them to authorize us to reenergize that line.

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

FYI, I think a PD [ph] on the very question you're addressing just came out. But my question is to -- only equity delay, Kent saying that it might be pushed into 2014. Is that -- and you've obviously already also had this additional charge you've taken. Is that really just because the proceedings are taking longer and pushed into the next year, so timing for any sort of significant incremental charge is pushed out or are you doing better elsewhere? Can you just talk around your thought process there?

First of all, to state the obvious, which is that equity requirements is sort of the end game. There's all sorts of different things that factor into our cash needs, as well as our capital structure, essentially everything in our results factors into that. So it's kind of at the end of the line. The reality is, as in any others there are puts and takes that drive our equity needs. And the fact that we did take this charge fairly recently, in reality it isn't a huge driver for the total annual needs, because the annual needs are weighted average over the whole year and when you have a charge towards the end of the year, it doesn't have the same kind of impact as when it's reflected throughout the entire year. So puts and takes, no major changes in our expectations and in our plans, we've built in flexibility so that obviously some amounts can always spill over into the following year just because that's how the markets work and that's how the timing is and you want to have that kind of flexibility. So we're going to see how the last part of the year goes. We're generally on track but some of it may end up being in 2014. I don't think it is a concern.

Our next question comes from the line of Dan Eggers with Credit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Just following up on this extra $200 million of cost as you've reallocated, in priority of work. Is there potential for more of these to be done as you guys reprioritize kind of the phase of work that's going to get done in '14 or '15 under the PSEP? Or is there a chance this can be reversed as you continue to do more work as what needs to get done?

Dan, this is Chris. We were required to file this as a onetime update on the Pipeline Safety Enhancement Plan. So we don't anticipate going through and reprioritizing or doing another update on this through the end of the program, which is through the end of 2014. Dan Eggers - Crédit Suisse AG, Research Division: And then I guess, just kind of, putting the cart before the horse a little bit, but as far as getting the resolution on San Bruno and potentially where the fines could end up or the penalties could end up. Can you guys just walk through kind of the legal arguments if some of these high fines or penalties are put out there. How you guys look to protest or try and reduce those impacts to shareholders from a legal perspective?

I'll start off, and Hyun Park, our General Counsel is here, he can add to this. But we believe that there are some very strong arguments that when a penalty gets too large, that we do have options to appeal that penalty. There are provisions under California law that prevent excessive fines and penalties, and we think that we've got some good arguments there if they just get out of line with precedents across the country and what's reasonable, given all the money that we've already spent. Hyun, I don't know if you want to add any more to that.

This is Hyun Park, General Counsel. I actually think it's too early to tell. Obviously, we're speculating. But as Tony said, we believe that if the fine is so excessive, we would have both state and federal constitutional law based arguments. Dan Eggers - Crédit Suisse AG, Research Division: And those would be appealed through California state court, U.S. federal court or a combination of any which [ph] route you decide to go.

I think those are all being assessed at this point and we would have the option to go to both state, as well as federal court, we believe.

Our next question comes from Kit Conlidge [ph] the line of with BGC.

To revisit the gas transmission case a little bit again, is it going to be part of the potential reaction here that it may not be completely clear what you've been disallowed from recovering that you've already spent or plan to spend versus what the new rules require you to spend in the future. In other words, are we going to get into some very complex detailed arguments that will make it hard to figure out what the rate base is and what the return is likely to be?

This is Chris, and just for clarification, are you referring to the gas transmission case that we're going to file, is that what we're talking about?

Yes.

So as I've said, we're spending significantly more right now, as you guys are well aware, than we're getting in revenues. And so we expect this filing to be a pretty large ask and I think it's important to remember there's a couple of differences from what we asked for the first time that got disallowed versus what we're going to ask for this time. In the last case when they did the big disallowance, there were 2 real big areas that they disallowed: One was on our records systems that we were updating and modernizing and that project will be done by the end of next year, and so that won't be part of the ask for the next time. And then that next one was, as was referred to earlier, is we asked for a large contingency because at the time, this was several years ago, we hadn't gotten through the design phase and all the engineering and the estimates were pretty rough at that time, so we put in some large contingencies and they disallowed all those contingencies. And that in this case, we got 2 years under our belts, 2.5 years under our belts knowing what these costs look like and so the contingency request would be a lot smaller. And so I think that it will be a little bit more of a standard type in terms of filings and such, other than part of the big increase is from the fact that they've changed the rules. And they've raised the standards around safety, which are good standards and that requires a lot more work from us and the other utilities and so those will be items that will be in there. We do expect that because of the size of the asset interveners, we'll get involved and they'll probably challenge us as they did on the last cases, did we already have -- did we already be get paid for these kinds of costs in the past. But we think we'll have a very solid case to be able to file and I think you'll be able to see with transparency what the rate base ask will look like. And I don't think that the issues that will be raised will be any different than things that we've seen in the past.

Our next question comes from the line of Julien Dumoulin-Smith with UBS.

So just wrapping up on the gas side, quickly. You talked about filing this later this year, just to provide a little extra buffer. How much buffer do you think that provides you ultimately in terms of getting through it in a timely fashion?

I'll start and Tom you can -- this is Chris again. What we're trying to do is that if we do it in December that gives them, hopefully, a full 12 months' worth of time to get through the regulatory process, which is what we would hope that they would be able to do at the commission. Normally the schedules will call for something around the 12-month timeframe. So that's really what we're trying to have accomplished. I don't know -- Tom if you want to add anything?

The schedule that calls for us to file no later than February 3, so we're adding this extra couple of months just to try to make sure we get a decision by the end of the year, and we'll have that established once the commission application is filed, there will be a pre-hearing [ph] conference to set the schedule again, we hope it calls for a decision by January 1, of '15.

And then going back to Dan's question and kind of juxtaposing, if you will, a potential appeals process in the context of equity needs. Can you provide just a little bit of clarity in terms of when you might need to issue equity to the extent to which a decision were to come out from the CPUC. Is there is some need to fund that immediately pending an appeal process? How do you think about that ultimately? I mean, obviously there's some balance sheet ramifications as well.

Julien, this is Kent. Of course any answer to that is somewhat hypothetical because it kind of depends on what the decision is, and we have a huge variety of recommendations out there and a range of possible outcomes still in these proceedings. So the specifics are going to depend on what the final decision is. If we do appeal it, unless it is an unusual situation, my guess is that from an accounting perspective, we'll still be required to accrue what the decision is because to not do that would essentially -- we'd have to think it probable that the appeal would occur and so my guess is the accounting will cause us to have to deal with some of the capital structure and financing implications, and the appeal could last a long time before that's actually resolved.

So really, the reality is you could only -- a partial amount of equity to the sense that you'd get [ph] resolution and then ultimately full payment -- ultimately would be on resolution of the appeal most likely, if it were to come to that.

But Julien, let's remember the scenario, and if I use one scenario, which is the SED recommendation, there's only a portion of that, that actually drives upfront equity financing. A lot of it is over time. So again it really depends on the specifics of the final PC [ph] decision.

Our next question comes from the line of Anthony Crowdell of Jefferies.

I want to follow up on Julien and Dan's question, talking about the appeals process. And I think that one of the responses you give Dan was, based on precedents across the country, I guess, and other pipeline matters. I mean could you highlight or give us some examples or yard markers of where previous appeals, or I guess pipeline penalties have been?

As far as we can determine, the largest penalty in a -- pipeline gas pipeline explosion incident related to El Paso natural gas about -- a little over a decade ago, it was just over $100 million in penalties. Now there have been some more recently, there was one in Pennsylvania that was in the low double digits. Nick, do you remember that number? About $25 million. Some of that was constrained by some of the state law in Pennsylvania. But if you look at all of it, and we've done this work -- the numbers that are being talked about, which would total $4 billion in penalties are orders of magnitude beyond anything that's ever been assessed. And when you think about it, assessing a penalty that size doesn't accomplish anything. We made major changes in the leadership in the organization here, we immediately started to do work, knowing that we weren't going to recover, but we didn't wait until we had an order telling us what we'd recover and what we didn't. We went and did the right thing, and so we think it accomplishes any logical purpose to have penalties the size that some of the folks are talking about.

So just a follow-up, if I think about it, a decision comes out we hope in the first quarter of '14 and let's just say the decision comes out that's on top of the SED recommendation and the company does appeal it and I guess, there's really no timeline for an appeal. If an appeal brings a decision back to something closer to like an El Paso decision, does the utility now go refile with the commission to recoup the difference or start recovering what was disallowed previously?

Yes, it's too early to speculate what we do in that case but clearly, if we get a decision that's near where some of the proponents are advocating, we'll start the appeal process and work that through.

Our next question comes from the line of Michael Lapides with Goldman Sachs.

Question on the General Rate Case. Tony, you commented that you've got a little bit of positive outlook, or have gotten some positive feedback on the rate case filings. But if I go back and actually look at the testimony, there's a pretty big spread between your request and what some of the main intervenors had requested in terms of a revenue requirement. I'm just curious, is there a bogey or a level where if you get a certain amount in the rate increase, it wouldn't impact what you would wind up spending on the system, whether in OpEx or in capital spending levels, meaning -- are you in a position where if you get an outcome that isn't what you're looking for, that you're willing to dial back spending on the system?

Well, we think everything that we've asked for is justifiable. We did a lot of work around the risk associated with not doing the work. I think the issue as I said before, you never get 100% so at some point whatever the number is you have to take a look at -- are there discretionary things that you take out of your spending, or are there some important things that, instead of a having a 5-year plan to do a particular program, do it in 7 years or 8 years or something like that. So I think there will be flexibility. We'll have to work hard, but I think we made a really good showing that a lot of this, and particularly on the gas side of the business, are things that we ought to get on with.

Okay, and how much when you think about the rate increase request, how much is capital driven versus how much is growth in O&M?

Let me ask. Tom, do you have those numbers handy?

No, we don't have those numbers available, but we can certainly share them with you later.

And apologies, just kind of focusing on the rate case because I know there's been so much attention on the San Bruno related dockets but I mean, the revenue request of over $1 billion is a big number in the grand scheme of things and some of the intervenors came out with dramatic differences versus your forecast.

They did, but to get back to my point early, when you look at it -- it's a big company with total revenues in the high teens. The average bill, if we get 100% of what we've asked for, is still below the national average. And I think that's what customers really care about. I mean, it's always a discussion about why your rate is high, but in many parts of our service territory the total bill is low because of usage and that's why the legislation we got that allows restructuring the rates is so important because this skewing where the high-end of our structure was way high. We'll be able to make a significant dent in that high-end. Our current high rate is about $0.35. That will come down significantly if we just use the normal cost of service regulation that many other states, probably almost all states use.

Our next question comes from the line of Angie Storozynski with Macquarie.

I'm looking at the calendar here. So we're waiting for a decision on the penalty -- or a proposed position on the penalty. Then you will file a transmission -- gas transmission rate case where you can ask for a pretty significant increase as you're suggesting. We have a pending electric rate case. So how is it possible that you could actually challenge the decision by the commission while you have 2 big rate cases pending? I'm asking about legal challenges to a proposed penalty decision or a final penalty decision.

Well, there certainly is no legal barrier to doing that. I mean these are all --

I'm talking about the collateral damage to those other proceedings from such a filing.

Right, and remember -- I mean, so our Gas Transmission & Storage case while we'll file it, it will go through a year-long process. So you're going to have a significant amount of time pass between when we file the case and when it actually gets decided, and lots of hearings and a recommended decision there. So I mean I'm comfortable that in the interest of protecting our shareholder's interest, we'll have to make the right decision on the penalty phase. And if the penalty phase is too big, we're comfortable with going ahead and appealing that. And we've seen that the commission seems to have been able to separate the San Bruno proceeding from our normal regulatory process. I know early on, there was a lot of concern about, was there going to be some slop over and would San Bruno affect other regulatory proceedings, and we continue to believe that there isn't any evidence of that.

Okay, and separately, so you were planning to issue between $1 billion and $1.2 billion of equity this year. And we are almost in November and you've issued $740 million. Is it that you need less for this year and thus, you're not rushing to issue the additional equity? Or are you basically waiting for the final proposed penalty decision?

Angie, this is Kent. We have had $1 billion, $1.2 billion as our target for the year. I indicated on an earlier question that we do have some flexibility. So if it's appropriate and we're going to sort of assess things over the remaining months, if it's appropriate, some might push into next year. But we haven't had any major change in our overall needs for equity.

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

Ken, I was just trying to look at this Slide 8, where you have the natural gas matters and the expenses tied to them. The pipeline-related expenses to the low end of the guidance is $450 million and the high guidance range I guess, is $350 million. And if I'm right, you spent total 9 months something like, $250 million. So can you give us a sense where you are going to end up over here because it's still, I guess, the range is still wide enough with still 1 quarter left and I guess now only 2 months left as the year is coming to a close.

We're keeping the range at -- we've adjusted the range to $350 million to $450 million. That range used to be at $400 million to $500 million and that's the adjustment we made on the call.

So we could still -- why is it back-end loaded, can I ask? That's what I'm trying to understand.

Let me just recap what's included in that. There's 3 major components. There is our Pipeline Safety Enhancement Plan expense work, which is for the strength testing and that is seasonal work, and we didn't have a lot of that very early in the year so it tends to be certainly in the third quarter, and some of it in the fourth quarter as well. The second component of that is our rights-of-way work as well as our integrity management work, and Chris gave an update on the rights-of-way work. We're not done with that yet and that will continue into the fourth quarter. And then the last category is sort of our legal and other costs, and that also is obviously driven by the things you think would drive that. Those are really the factors and our guidance is $350 million to $450 million.

Can you give us some approximation, percentage wise, the 3 factors that you mentioned how much they make up of this total?

There is a slide in the appendix that gives ranges for each of the components. So I'll refer you to that.

Our next question comes from the line of Travis Miller with MorningStar.

One, in terms of the trend -- the electric transmission stuff, the TO. I wonder if you can characterize the key issues in those settlement discussions right now, both in the TO14, TO15.

This is Tom Bottorff. You may be aware, the TO14 has been settled, we reached a tentative agreement with all the parties and we filed that settlement agreement with FERC yesterday. So that's pending. We expect the judge to certify it, make a recommendation to the full [ph] commission to improve it and probably expect a final decision in first quarter of next year. So all the issues in that case were settled. The key issues tend to be around the rate of return, that's been one, not just in our proceedings, but nationally. And the amount of investment is also an issue; the depreciation rate sometimes is an issue; operating and maintenance costs compared to historical trends tend to be an issue. So they tend to be fairly consistent from proceeding to proceeding and I'm sure we'll address those again in TO15, which is pending.

And then on TO15 with that possible increase in the ROE, what kind of earnings impact could that have, given the rates went into effect October 1. So you have essentially 3 months versus what -- I believe you said in the guidance was about a 9.1% full year.

Yes, this is Kent. It is in effect for 3 months. I'll just say we booked the revenues that we request, but we also reserve against those revenues for a litigation assessment until the case is resolved. So it's really the net of those that affect our overall results. I would say compared to the 9.1%, we're hopeful there we're going to end up doing better so it's probably a slight favorable this year but in reality, not in place for very long during 2013.

[Operator Instructions]

I take it that there are no further questions?

We have one question from Kamal Patel with Wells Fargo.

Two questions. One, dealing with --

Monique, did we lose him?

[Operator Instructions] . [Technical Difficulty]

What risks do you see in your pending -- or your upcoming gas transmission rate case with the potential shuffling of leadership at the CPUC late next year, early 2015?

This is Tom Bottorff. I don't think the shuffling of the commissioners puts the case at risk at this point. It depends on the arguments that are presented by both sides and what the judge ultimately considers to be a reasonable outcome after hearing the case. If the decision -- if the PD is out prior to the end of the year and the commissioners who are seated today get a chance to vote on it, there's no change. But you're correct, if the decision is beyond January 15th we could have 2 new commissioners and it's unclear what perspectives they will bring to the commission at this point.

Second question being, one of the key focus areas for the management team has been to partner effectively and rebuild relationships. And wondering where you think you stand in light of, Tony, I think you've been there about 2 years, in light of comments that were made back in August regarding concerns surrounding a bankruptcy and the recent San Carlos issues. Do you think those have had detrimental impact on rebuilding those relationships?

Well, obviously, this is politically charged and the articles in the press can affect that, but we continue to see improvement in our customer satisfaction numbers. Last quarter, we saw yet another increase. And the other indicator, I think, over the past, probably 2 months, we've had 1 to 2 dozen editorials and op-ed pieces from community leaders, mayors, business associations supporting the notion that while PG&E ought to be penalized for San Bruno, that the numbers that are now being talked about are counterproductive, that the company is an effective and an important member of communities across large portions of the state. And if you read those things, it's very encouraging that our message has gotten out and our efforts to, as we call it, go local and really partner with local communities have been very effective.

It's seems like the newswire tend to pick up the negative articles a bit more than the positive ones.

We'd be happy to send you the copies of the good ones.

Thank you. There are currently no additional questions waiting from the phone line.

In that case I would like to thank everybody for your time today. I know it's a very busy day with a number of earnings calls, and we'll probably see many of you at the EEI finance conference in a little bit more than a week. Thank you.

Thank you, ladies and gentlemen, for attending today's PG&E Corporation, third quarter earnings 2013 conference call. This will now conclude the conference. Please enjoy the rest of your day.