Gabriel B. Togneri - Vice President of Investor Relations Anthony F. Earley - Chairman, Chief Executive Officer and President Christopher P. Johns - Former President and Director Nickolas Stavropoulos - Executive Vice President of Gas Operations Kent M. Harvey - Chief Financial Officer, Senior Vice President, Treasurer and Senior Vice President of Financial Services - Pacific Gas & Electric Company Thomas E. Bottorff - Senior Vice President of Regulatory Relations-Pacific Gas & Electric Company

Dan Eggers - Crédit Suisse AG, Research Division Greg Gordon - ISI Group Inc., Research Division Paul Patterson - Glenrock Associates LLC Jonathan P. Arnold - Deutsche Bank AG, Research Division Steven I. Fleishman - BofA Merrill Lynch, Research Division Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division Michael J. Lapides - Goldman Sachs Group Inc., Research Division Travis Miller - Morningstar Inc., Research Division Andrew Levi - Caris & Company, Inc., Research Division

Good morning, and welcome to the PG&E Corporation Fourth Quarter Earnings Conference Call. [Operator Instructions] At this time, I would like to introduce your host, Mr. Gabe Togneri. Thank you, and have a good conference. You may proceed, Mr. Togneri.

Good morning, everyone. So let me provide the usual upfront remarks. Our comments today will include forward-looking statements based on assumptions and expectations reflecting information currently available to management. Some of the important factors that could affect our results are described at the front of today's slide. We also encourage you to review the more fulsome discussion of risk factors that appear in our 2011 annual report that will be filed as an exhibit to the Form 10-K with the SEC later today. This morning's speakers are Tony Earley, Chris Johns, Nick Stavropoulos and Kent Harvey. Other members of the team are also here to participate in the Q&A. And with that, I'll hand it over to Tony.

Thank you, Gabe, and thank you all for listening in today. Since this is only my second quarterly earnings call, I think I'm still enough of a newcomer to share some of my observations of the company before we get to the heart of our discussion this morning. At our last earnings call, I made several points about what we had done to start to transform PG&E. And we had hired a lot of top-tier talent to supplement the strong core of PG&E veterans that we have. We made organizational changes that established clear lines of accountability for our gas and electric businesses. We put a strong emphasis on operational excellence, and we made a commitment of resources to turn the business around, and, ultimately, to make our operations the safest in the country. So with the benefits of a few more months on the job, let me add a couple more observations. Our team understands that public safety is our highest priority, and we're now rolling out technologies to get us there. They understand that the focus is on back-to-basics, that we have to be -- have to focus on benchmarking and to put in place a continuous improvement program. Most of all, the team understands that we have to deliver. We know the areas we need to improve on, and we've got a solid foundation from which we can execute. And that's significant because it means that in contrast to where we were just 7 or 8 months ago, we now have a very real opportunity in 2012: first, to truly tackle and resolve our gas issues; second, focus on repositioning PG&E for long-term success; and third, rebuild relationships with key stakeholders. And that is exactly what our executive team is focused on. So let me start with…

Thanks, Tony. Today, I'm going to summarize the significant work that we completed in 2011 to help resolve the gas pipeline issues. And I'll touch on the work that we're doing to position the broader company for success. I'll also discuss some of the regulatory developments over the last couple of months. Let me start with the gas work in 2011. We accomplished a remarkable amount of work this past year to improve the safety of our gas pipeline system. To give you just a couple of examples, by the end of January, we have validated the maximum allowable operating pressures, or what we refer to as MAOP, for all of the more than 2,000 miles of transmission pipelines in high consequence areas. And along the way, we met every one of our commitments with our regulators. In the process, we conducted a records validation effort more detailed and comprehensive than anything done before anywhere. We've completed an unprecedented amount of pressure testing, validating the safety of over 160 miles of gas transmission pipe. This was technically difficult and highly complex work on in-service pipes in densely populated areas. And as Nick will discuss later, we'll be doing a similar amount of work this year to further validate and enhance the safety of our system. Now gas operations in place, we're not the only ones working hard to improve the safety and reliability of our operations last year. We made a number of safety enhancements to our electric system, focusing on reducing the risk from outages and reducing the number of, and the impact from, equipment failures. At the same time, we had another strong year in electric reliability, where we had our second consecutive year with the new low of outage frequency. In the area of renewables, 19.3% of…

Thanks, Chris. As Chris told you, we've completed a lot of gas work this last year, but we've also been building a strong team of experts from both within the company and from industry-leading firms across the country. As we go forward, we'll be making additional progress in gas operations, including improving our integrity management program, our gas distribution practices and the use of technology, all designed to enhance public safety. We know a lot more about our gas pipeline system than we did a year ago. And we've also uncovered new challenges even during this past quarter. Based upon all of our experiences last year, we've adjusted our operational plans and our cost expectations for this year. In terms of the scope of work for this year, we plan on pressure testing or verifying records for 185 miles of transmission pipe, replacing about 40 miles and upgrading 78 miles to enable in-line inspections on those segments. Also, by early 2013, we will complete the MAOP validation for all remaining transmission pipelines in the system, more than 4,000 additional miles. We now expect our costs for the pipeline-related work in 2012 to be about $120 million higher than we previously estimated. The main driver is the cost for the Hydrostatic Pressure Testing program. As a reminder, we filed our Pipeline Safety Enhancement Plan last summer, including estimated costs, which were based upon our limited experience up to that point. We completed the majority of our 2011 pressure testing since that time, which impacted our cost expectations for this year. Based upon what we experienced last year in the pressure testing program, we expect to continue to incur cost per mile much higher than what you might see from some of our industry peers. And there are a couple of reasons…

Good morning. I have a fair amount to cover, so I'd like to provide the big picture before I go through all the details. And I think there are 5 key takeaways: first, we took a $200 million of accrual in Q4 for potential penalties associated with all the gas matters; second, our other Q4 results were in line with guidance; third, we're maintaining our 2012 guidance for earnings from operations at $3.10 to $3.30 per share; fourth, we're modifying our 2012 guidance for pipeline-related costs; and fifth, we're increasing our estimate of 2012 equity needs. I'll explain each of these as I go through with my remarks. So I'm going to start with our Q4 results, which are summarized on Slide 6. Here you can see that earnings from operations for Q4 were $366 million or $0.89 per share, and earnings for operations from the year totaled $3.58 per share. GAAP earnings for the quarter were $83 million or $0.20 per share. The difference between Q4 earnings from operations and GAAP earnings is the item impacting comparability for natural gas matters. And the details of that are shown in the table at the bottom of the slide. First is the pipeline-related costs, which totaled $180 million pretax during the quarter. And this includes the strength testing and the pipeline validation work that Chris and Nick talked about, as well as our legal and other costs that we incurred during the quarter. For the year, this totaled $483 million pretax and was in line with our guidance. Below that, you see the $200 million accrual we took in Q4 for potential penalties stemming from the various gas matters. As you know, this was an item we had not provided guidance on. Chris described the regulatory developments that occurred since our…

[Operator Instructions] The first question comes from comes from the line of Dan Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Kent, I'm just kind of following up on where you finished off your conversation with the $200 million fine accrual in your numbers in the fourth quarter. What could cause that number to change up or down other than some sort of definitive agreement or some sort of fine out of the commission where that could move over the course of the year?

Well, Dan, the $200 million that we talked about, obviously, involved a lot of judgment. And every quarter, we'll continue to monitor the overall situation and all the factors that Chris described. And we need to be confident at the end of each quarter that our accrual accurately represents the lower end of a reasonable range. Dan Eggers - Crédit Suisse AG, Research Division: And so then you would adjust -- if that number were to move up and the equity number would go up in step with that, is that the right way to think about the kind of the one-for-one as you accrue against an equity need?

Yes. The only thing I would say maybe to just refine on that a little bit is in the case of our accrual that we took in the fourth quarter, obviously, that's a non-cash accrual at this point. And depending upon the resolution of the gas matters, at some point, it will become a cash item. While it's a non-cash accrual, it's not 100% you fund with equity because, obviously, you're raising cash, which otherwise you don't need at this point when you issue the equity. So in some ways, you end up initially raising roughly half of what you need and displacing debt issuance that you otherwise would have needed. Ultimately, when you pay a cash amount for the item, then we would raise the remaining equity and some a little bit of debt to offset what you displaced initially, and that becomes one-for-one eventually. Dan Eggers - Crédit Suisse AG, Research Division: Okay, and I guess just, Tony, I know you spend a lot of time trying to focus on the benchmarking work. Can you just kind of talk to us a little bit now that you have some metrics in place, where you see the businesses ranking out against your benchmarks today? And then what kind of deliverables you promised or committed to the board over the '12 and '13 timeframe to get to get improvement up to kind of meet the goals you want to have.

I think what the benchmarking has told us is there are some areas that we have made some real progress. And as Chris mentioned, some of our reliability numbers on the electric system, we've seen some tremendous improvements. We've also seen some very nice improvements in things like OSHA recordables on safety, although we still have some issues we've got to work on in terms of serious injuries and fatalities at the company. And we've committed to our board to move those along. Clearly, on some of the perceptual benchmarkings, so our customer satisfaction numbers, which combines not only our operational performance but also the perception of the company in the marketplace, those continue to reside squarely in third and fourth quartile. And to deal with those, you've got to do a combination of improving the service and also in improving the credibility of the company in the marketplace. That's why some of the work that Nick and his team has done this past year on the hydrotesting in the MAOP, we're starting to get some recognition. And we really have committed to having the safest gas system. And I think eventually, people will start to realize it's a very real commitment that we're delivering on. So I would say while there are some areas we've made some real progress, we continue on some of our operational areas that affect our customer satisfaction numbers and the like. We're still average to below average. Dan Eggers - Crédit Suisse AG, Research Division: And then what is your commitment to the board as far as making improvements over the course of '12 or '13? Is there numbers we should be looking at to gauge success?

Well, our long-term target is to have everything in the first quartile. There's some things like safety we want to be top decile. My commitment to the board is we will show significant progress in 2012.

The next question is from the line of Greg Gordon with ISI Group.

Tony, I just want to go back to your comments from the beginning of the call. I just want to be clear in my understanding that you feel very strongly that the commission, from a legal precedent perspective, needs to differentiate prudently incurred costs associated with new mandates and allow their recovery as it compares to the cost that you've already incurred and will incur in 2012 on sort of catching up with old mandates. Is that a fair regurgitation of your statement?

That is absolutely fair. And as I said, there's a lot of confusion because in the proceeding around our Pipeline Safety Enhancement Plan, there seemed to be more discussion from some the parties around the issue of who pays rather than -- whether the scope of the plan is the right scope and that we're working on the right things to make this the safest system that we can make it. So we did file a request to separate those 2 issues. We'll have to see what the commission does with it. But we're making it very clear, you do have to separate those 2 issues.

Okay. So when I look at Slide 9 of your presentation, which goes through the increase in the costs, your non-PSEP cost estimate previously was $100 million to $200 million. Is the full $120 million increase associated with non-PSEP-related costs?

This is Kent. I would say that the majority of that amount is associated with non-PSEP costs. And if you think about it in the PSEP, we had originally proposed work on pipe that was from 1961 to 1970, that timeframe. And we have since agreed that, that should be outside of the scope of the PSEP. So while the cost of the hydrostatic testing both in and outside the program has gone up, the increase within the program is somewhat mitigated by the fact that we've reduced some scope within the program and moved it outside. So most of the overall impact will be on the non-PSEP side.

Okay. So basically, the underlying tenet here is that PSEP costs, to the extent they're deemed to be in line with new regulation, should be recoverable. Non-PSEP costs are on the shareholders.

That's correct.

Great. One more question on that line. In reading the turn in the DRA testimony, they were very critical of a lot of things, frankly. But they were very critical of the cost estimates for doing certain types of work, including hydrostatic testing, and that they cited their experts indicating that they thought you could do it for less, and here you are increasing the estimate of how much it's going to cost. Can you speak to why there's such a wide difference of opinion on what the right cost is to complete this work?

Let me start off, and then I'll turn it over to Nick to get into the details. So having built pipelines like the Millennium Pipeline, Iroquois Pipeline, when you're going out doing hydrostatic testing on a brand-new pipeline and you've got the pipe lying there in the trench, you know where you're going to do the hydrostatic testing in advance. It's all laid out, and it's a relatively simple process. We're doing hydrostatic testing on pipe that's been in the ground for 50, 60 years that neighborhoods have grown up around, streets have been paved over. It is a major project. The other issue that we discovered was when you put a brand-new pipe in the ground, you fill it with water, you pressure test it, the water comes out clean. When you put water in a pipe that's been around for 50 or 60 years, you've got residual hydrocarbons, you got corrosion products in there, and we've had to then spend a huge amount of money treating the water coming out, out of the pipes. So Nick and his team have been working very hard to simplify the process. But, Nick, there still is a lot of challenge out there.

Yes, Tony. I think it's fair to say the work that we did this past year and that we're going to do in 2012 regarding hydrostatic testing is probably the most complex hydrostatic testing program anywhere in the United States. And as Tony alluded that these are shorter segments of older pipelines, very difficult working conditions to be able to stage the equipment at the point where you need to begin and then stage additional equipment at the end of the test. And the environmental requirements here in California are appropriately the most rigorous in the country. So those standards that we are adhering to here are the highest bar, no doubt, and drive a lot of these costs. And the majority of the cost that we incurred that were unanticipated really relate to handling the water in the hydro test program, where we need to, in many cases before we begin our hydro test, flush these lines to make sure that the water in the pipe when we do the hydro test, the actual test itself, is up to drinking water standards. So that has required us to do a lot of water handling, a lot of water treatment, a lot of water disposal, way over and above what would be required, as Tony indicated, in a new pipeline. That said, over the course of 2011, our cost per mile was around $1.6 million a mile. Our estimate for this year is somewhere in the $1.1 million, $1.15 million per mile. So a significant reduction of what we incurred in 2011. I would also add that we're dealing with shorter segments of pipe than I think that most people do, and so that adds to the cost per mile.

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

Just to go to the penalty stuff, how should we think about how you guys go about sort of -- I know there's a lot of judgment involved, but sort of how do you go about, sort of, estimating what you think they might be? I mean, is this based on discussions? Or just how do we get a feel for that process?

Let me start, and then I'll flip it over to Kent. And just to clarify that what we accrued is not what we thought it might be. It is the low end. And you get to there as we've looked at all the developments that we concluded having no accrual at all was not the appropriate place to be. Because I think it was certain we going to have a penalty. And in looking at all the facts and circumstances and using judgment, concluded that $200 million -- we didn't think that the penalty would, in any realistic circumstance, be below $200 million. Now there are a lot of facts that went into that. Kent, you might want to comment on just some of the things you look at. But I want to make sure that's what we think the minimum is it's not what we think, the best guess of what it's going to be.

Paul, Tony's overall summary is exactly right. And the things we looked at with the various proceedings at the commission including -- we looked at that CPSD's report that was filed early in the year. We looked at the new OII in San Bruno that was issued January and also the citation from the CPSD related to the maps that Chris covered earlier. And the reality of the situation, when you look at all the different issues, is that there are no clear precedents, really. And there's not just like a formula that can be applied to the situation. But all the indications are that the PUC will impose a large penalty here. So we considered previous penalties, such as Rancho Cordova. And then we tried to take into account the magnitude of this event, and we determined overall that the penalty will likely be higher than anything that's been previously issued by the PUC for all of those reasons. And we ended up thinking that $200 million was a reasonable estimate for the low end of the range of possible outcomes.

Okay, and then also, there was, a week or 2 ago, some articles regarding welders saying that the hydrostatic testing wasn't perhaps as good as it could have been or it was -- I'm just wondering, I know that it's been pretty recent since this came out, but just do you guys have any thought processes as to what they're talking about or the validity of it?

Well, this is Nick. We take every communication that comes into us concerning questions about whether or not we accomplish work properly very seriously. And so we took a look at what these 2 welders had to say, and we've gone back and made an intensive records review. We've pulled all the radiographic welding records and all of the asphalt material. We have looked at this every way we possibly can, and we find absolutely no merit whatsoever into the allegations that have been brought forth by these 2 folks. I can't speak to their motivations, but we take everything like this very seriously, and we have found nothing to suggest that our workmanship was nothing but top quality. That's another thing going back to the cost of these hydrostatic testing program. We have put in an extraordinarily extensive QA QC program way beyond what industry standards are to make sure that this work is done property, and that certainly adds to the cost, to the time of execution. But we find absolutely no indication whatsoever that we had any issues with our testing last year.

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

On the -- just to be sure I understand the PSEP number and how it's impacted guidance, is the situation that, that $230 million before was kind of neither in your operating guidance nor in the GAAP guidance because you were assuming recovery? And all this really happening, is it now -- it's in the GAAP guidance, having been a net 0 before effectively?

Jonathan, that's right. Essentially, we said last quarter that we were assuming full recovery of the PSEP cost, so that they wouldn't flow through the bottom line. Although I remember, sort of, talking through the fact that there could be a timing. Once you have a memo account in place, there'd be a timing about when we get a final decision, but that the cost would be recoverable. And we left it up to you guys if you wanted to make different assumptions.

Okay. So now if you were to get a memo account sometime mid-year and some of those costs will end up being recovered, that would just reduce the amount of charge to the GAAP earnings.

That's correct.

Okay. And then on -- just on the time -- you obviously put the slide out with the regulatory calendar. Just the way you've laid it out, it's sort of tempting to imagine that some of these hearings and proceedings could come to a head at more or less the same time. Am I reading too much into that? One. And two, what chances do you see that there would be some kind of merging of any of these proceedings at the commission? And I guess the third strand of that, would you need to see that in order to be able to potentially settle any of these?

Jonathan, this is Tom Bottorff, responsible for regulatory relations. I don't foresee the commission consolidating the 3 investigations at this point. But that doesn't preclude the parties of the proceedings from engaging in settlement discussions in connection with each of the investigations.

Have you -- is that something that's essentially happened already? Or is it a little too early in the game for that?

I think it's early in the game. Although the judge at the pre-hearing conference, which was held this Tuesday in the San Bruno investigation, they strongly encouraged parties to agree on issues where they could and actually offered himself up as a potential mediator to help facilitate some discussions.

Your next question comes from the line of Steve Fleishman with Bank of America Merrill Lynch.

A couple of questions. First, if you add the penalty accrual, the PSEP now being, kind of, rolling through as well as this additional $120 million, altogether, that's a lot less than the -- a lot more than the additional equity issuance. Is the difference just the -- this penalty issue that you're not actually having to spend the money yet, when you add all those up, I think you'll probably get $500 million, $600 million of additional hit to the balance sheet.

Yes, Steve, this is Kent. It is that in that -- that's why I elaborated a little on that issue earlier that it's not as simple as saying you accrue $200 million and you immediately issue $200 million. We actually, as you know, have to actively manage our capital structure, and we do, really, monthly forecasting to do that. And so you really do have to consider both when you book things and, therefore, affect your retained earnings, but also when the cash goes out the door. And that does affect that, as well as you want to think about the expenditures that are now going to be unrecovered for gas pipeline matters occurring throughout the year rather than all at the beginning of the year. And as a result, that tends to also affect the timing of the equity issuance.

Okay. Second question is just if you now take this update and go back to the beginning of the San Bruno, what is the total cost that shareholders have now borne?

Steve, we can easily now get up to costs that are well in excess of $1.5 billion, and I'll just kind of recap them. You saw in our press release that cumulative to date, we've spent around $550 million that is not going to be recovered, that is at a shareholder cost. And obviously, our guidance indicates that we could spend nearly that much in 2012 on pipeline-related items. We accrued a $200 million penalty. So when you add all that up, that brings you to about $1.2 billion to $1.3 billion that shareholders have incurred. As you know, we've also committed to spend $200 million this year and $200 million next year on all of our operations, which is not going to be funded by customers, but in fact at shareholders' cost. And that's how you can get to $1.6 billion to $1.7 billion, which, obviously, is a very significant price tag. In fact, that's actually approaching the total net investment in our pipelines that we built up over decades. And I would also say that this business typically is authorized to earn about $100 million a year. So the cost here that shareholders have now incurred represents 15 to 20 years of earnings, basically.

Okay. One last question. There was the testimony on the San Bruno OII that, I guess, that audits, so to speak, talked about underspending and over-earnings over a long period of time, at least alleged that. Could you just go through, kind of -- my sense is some of those issues you might not exactly agree with. Could you go through some of the issues in that analysis?

Yes, this is Chris. There's a couple of things that you have to take into consideration when you look at that. First of all is that for the most part, most of our gas transmission rate cases were settled. So there were settlement agreements. And when you have a settlement agreement, you don't necessarily do a line item by line item tracking of the different types of costs. And in a lot of times, you also don't address how costs are allocated between years. And so there's a lot of judgment that goes into trying to determine what were the authorized amounts of cost to be spent in any one of those given years. And so when you go back and look at the findings or the assertions, if you will, in that audit, you can see that there's a lot of different assumptions that they're making that, quite frankly, we disagree with. And that -- and we will dispute as we move forward in the process. The second thing, though, that you really need to focus here on is that the majority of the costs that they're alleging that we did not spend, the $400 million out of the $500 million, relates to the programs that are, quite frankly, at-risk programs, and it generally is around our gas storage and our ability to utilize those funds. Many years ago, the CPUC decided that they did not want the customers to have the risks around that, and so we were -- the shareholders then were the ones that would suffer the consequences of a marketplace that didn't have activity in it or could have the rewards of it. And in fact over the last couple of years, we've seen very little in terms of rewards and income off of those businesses. And so what they're asserting is that we should have taken at-risk revenues that were designed to incent or penalize shareholders and apply them elsewhere. And then finally, when you look at the totality of our returns over the last 15 to 20 years, you'll see that in general, they're pretty much right around our authorized return in total for the company. And so it's not like all of that went and caused it to have a company-wide excessive earnings. We were utilizing that for other parts of the business. And so there's a lot there that we will -- that will come out and be asserted differently by us as we move forward in the regulatory proceedings.

The next question comes from the line of Hugh Wynne from Sanford C. Bernstein & Co. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: I also had a question related to the Consumer Protection and Safety Division's report. What struck me most about that report were not so much the details of the audit, but the line of argument that the division was presenting, which I think you could paraphrase as something along these lines: that PG&E had a legal obligation to run its gas pipeline system in a safe, reliable fashion. It requested and received most recently, through a settlement, the revenues that it deemed necessary to do so, the events at San Bruno. And the record presented in the report indicate that the company failed in its obligation to provide safe and reliable service. Now the company is coming back and saying our large portion of our PSEP budget, which relates to more onerous regulatory standards, should be recoverable. And the amounts that are being requested for recovery are comparable to the rate base of the system. And the argument seems to say, "Didn't we pay you once for the assets and the O&M necessary for safe and reliable service? And if you failed to provide it given that we've paid for it already, why should we pay for it again?" And it seemed to me an argument that would strike a chord with intervenors. Obviously, it has with commission staff. It might strike a chord with commissioners themselves. So I wanted to ask you, how have you seen that argument received at the commission? And secondly, perhaps most importantly, how do you rebut it?

Well, we can't comment on where the commission is on this because the proceedings are going on. We'll see how they come out. But I think you have to look at it in the overall context. When you're talking about safe and reliable systems, it's measured against what are the standard practices in the industry. And I think what we've said in response, there are some places where we weren't following standard practices. And to the extent that, that was the case, then we ought to absorb those costs. But to the extent that the standards are being changed and being increased, those new requirements ought to be recoverable from our customers through our rates. And I think you're going to see across the country, as we see new national pipeline standards, I think other states will start to look at what happens here in California, you'll see the same thing that while people were following accepted practices in the past, technology has changed, the understanding of the risks have changed, and, therefore, these new standards should be recoverable as part of a normal course of business.

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

Yes, first 2 questions. First, Kent, other uses of cash likely in 2012 when I think about what's embedded in your guidance, and maybe even 1 or 2 sources? Can you comment on Hinkley-related costs? Can you comment on expected funds to be paid out due to the generator settlements and some of that kind of that liability that's sitting there on your balance sheet? And then can you talk about the short-term debt balance? Because the short-term debt balance is at a level we haven't seen in a long while. They're about $1.6 billion. And normally, at this time of year -- normally, the peak in short-term debt balance is third quarter not fourth quarter. So it's not -- so not all funds or proceeds being utilized, it seems for fuel and power procurement. It's for, obviously, the gas side. Can you touch on those 3 items?

Sure. So first of all, in terms of Hinkley, we did, as you know, accrue a liability in the third quarter for Hinkley. Those are, in terms of a cash impact, those are activities that are going to take place over many years. And we have guidance out there for a potential increase in the liability this year. And again, most of those activities would take place over many years. So I don't see that as a significant driver of short-term cash. In terms of generator settlements, we don't see a lot of activity there this year. I think that's a little bit further out. So again, kind of same answer. That's not a big driver of our short-term cash needs. And in terms of where we ended up the year with short-term debt, we do have a fair amount of collateral posted, which we do as part of our normal activities related to energy procurement as well as hedging. And when you have low gas prices as we currently have, while that reduces the cash outlay for procuring fuel and gas for customers, it does cause us to have the post collateral to security arrangements we have with counterparties. And that's a big driver of what you're seeing at the end of the year.

Meaning that the short-term debt balance is higher this go around versus, let's say, a year ago or 2 years ago from now at the same quarter because the lower commodity price required an increased collateral posting?

That's correct.

Okay. finally -- and, Tony, this one is for you. Total cost related to San Bruno getting close to the actual rate base in the pipeline business. Is there a point -- what's, kind of, the breaking point? What's the tipping point where it's gone too far, meaning that it's too detrimental to shareholders? Or is there not a number that can be assigned to that?

Well, my personal view is shareholders have paid a lot of money, and I really believe that the commission needs to take that into account when they're assessing how much additional penalty ought to be involved. Because I will tell you that right now we are doing everything we can. We're not going to do anything differently or more depending on what the size of the penalty is. In fact, I think everyone, including the commission, recognizes this company needs to be financially healthy to be able to keep the investment going because we're going to be working on this for a number of years. That said, we're totally committed to whatever it takes to meet the commitments that we've made in the PSEP program and to make sure that we have the safest possible gas system. I can't put a number on that. And the reality is, we don't have a choice. We're committed to doing that. You can't just say, "Well, we're not going to make this safe." We need to build credibility with our customers. And I think the way we build it is by showing we're serious with our actions.

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

I have a question on the capital structure's parent utility in that accrual along with that equity issue. Does the accrual go to the utility or will that stay at the parent?

No, the accrual does go to the utility.

So how does that affect the capital structure then? The accrual ends up staying through and the cash impact doesn't come into effect during the year. When you guys go in for that capital structure review, is that going to change the equity share?

What happens is, for rate-making purposes, the capital structure at the utility is affected in the short-term by the accrual because you're reducing retained earnings by that amount. As we've indicated, our plans are to maintain a balanced capital structure consistent with our authorized capital structure. And that does require that we issue additional equity to offset the accrual. It eventually becomes a one-for-one impact, but because it's a non-cash accrual initially, there's a little bit of a less of an impact in the near term. But over time, it becomes a 1:1 impact.

Okay. So then if we think back to that $300 million extra, but then you had the, correct me if I'm wrong, the $200 million accrual plus the $120 million, so $420 million of extra costs, is that -- am I hearing that correct?

Yes. You want to remember that the accrual for the penalty is not tax-deductible. Our ongoing gas costs, which would include the higher estimate now by $120 million, those are larger, unrecovered costs, which over time gradually will affect what would have been our retained earnings. And so again, we displace, essentially, the after-tax amount of that over time with additional equity.

Okay, I got it. So the $600 million gets you back to the 52% based on your expectation?

That's correct.

We have the line of Andy Levi with Caris. Andrew Levi - Caris & Company, Inc., Research Division: Just an insurance question. So just remind us again how much insurance you guys have?

Yes. At the time of the accident, for third-party liabilities, we had $992 million of insurance. Andrew Levi - Caris & Company, Inc., Research Division: $992 million and you've gotten back about $100 million so far?

That's correct. And obviously, we don't intend to have the liability. We don't expect the liability will reach that full level. Andrew Levi - Caris & Company, Inc., Research Division: Okay. Can you give us any idea of, kind of, how much you've requested or filed for from insurance side thus far and whether that number changes or that's kind of what you're asking for?

Well, we have estimated publicly we've accrued $375 million total for the accident. We've said that the maximum liability based on our estimates is in the $600 million range. The way it works with our carriers is that as we resolve claims with third parties, then we take those claims to our insurance carriers. And our insurance policy represents a tower of insurance companies at different layers in the coverage. And so we are in the process of working through that with the first several layers of our insurance coverage, and those are the proceeds that you've seen so far. Those are for claims that have been resolved with third parties that we brought to our first few layers and have resolved the recovery with them. Andrew Levi - Caris & Company, Inc., Research Division: Okay. But it sounds like the maximum amount that you're kind of looking to receive is about $600 million?

That's what we estimated is the maximum likely liability. But we have currently accrued the low end of our range which is $375 million. We just have not resolved that level yet of third-party claims, so we have not yet brought that magnitude to the insurance carriers.

All right. I'd like to thank everybody for being on the call today and your interest. And have a great day. Bye now.

Ladies and gentlemen, thank you for attending the PG&E Fourth Quarter Earnings Conference Call. This now concludes the conference. Please enjoy the rest of your day.