Gabriel B. Togneri - Vice President of Investor Relations Anthony F. Earley - Chairman, Chief Executive Officer, President and Chairman of Executive Committee Christopher P. Johns - Former President and Director 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

Angie Storozynski - Macquarie Research Leslie Rich - J.P. Morgan Asset Management, Inc. Dan Eggers - Crédit Suisse AG, Research Division Jonathan P. Arnold - Deutsche Bank AG, Research Division Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division Brian Chin - Citigroup Inc, Research Division Michael J. Lapides - Goldman Sachs Group Inc., Research Division Anthony C. Crowdell - Jefferies & Company, Inc., Research Division Jonathan Cohen - ISI Group Inc., Research Division Travis Miller - Morningstar Inc., Research Division Kevin Fallon

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

Thank you, Jackie, and good morning, everyone. Thanks for joining us today. Before you hear from Tony Earley, Chris Johns and Kent Harvey, let me give you the usual reminders, and that being the discussion today will include forward-looking statements that are based on assumptions and expectations reflecting information currently available to management. Some of the important factors that could affect the company's results are described in Exhibit 1 that's located in the appendix for today's slides. And we also encourage you to review the discussion of risk factors that appears in the 2012 Annual Report and in the Form 10-K, both of which will be filed with the SEC later today. And with that, I'll hand it over to Tony.

So good morning, and thanks for joining us today. We have a lot to cover this morning starting with our results over the past year, and then we'll discuss our outlook for 2013 and beyond. I'll begin and then turn it over to Chris and Kent. Our focus continues to be on the areas that I outlined at the beginning of last year, resolving gas issues, positioning the company for long-term success and rebuilding relationships and partnering effectively with stakeholders. We've made significant progress in all of these areas in the last year. As you know, we've been working diligently to resolve the outstanding gas issues. Unfortunately, we reached an impact in settlement discussions with the other parties in the investigations, and we're now moving forward with the scheduled regulatory proceedings. We're committed to bringing this to a conclusion that is fair to all the parties involved including our shareholders. Since the San Bruno accident, we've spent 1.4 billion in shareholder dollars on unrecovered pipeline-related expenses and capital investment. And the total cost is $1.9 billion when we add the charge we've taken related to potential penalties, the contribution we made to the City of San Bruno and the incremental work we've done to improve our performance across the utility. While the investigations remain undecided, we are well on the path to resolving many of the other issues. The decision on the pipeline safety enhancement plan was an important step forward in closing out some of the cost uncertainties. While the result was not what we originally had in mind, it was an improvement over the proposed decision. We've also continued to make substantial progress on third-party liabilities. We've settled all of the most serious cases, and we're now focused on resolving the remaining cases. As a result of this…

Thanks, Tony. First, I'll start with our regulatory activity. In December of 2012, we saw resolution of several significant cases at the CPUC. First, the commission voted out the cost of capital case resulting in a 10.4% return on equity for 2013 and a capital structure of 52% equity. In addition, last month, the parties filed a settlement that would essentially extend the previous adjustment mechanism through the end of 2015. The CPUC also approved our application for the Oakley generating station, a 586-megawatt high-efficiency gas plant to be built in Contra Costa County. We expect to take ownership of the facility from the developer some time in 2016 or 2017. Also in December, the CPUC awarded us $21 million in energy efficiency incentive revenues associated with the successful results of our 2010 customer energy efficiency programs. As you know, the CPUC also voted out our pipeline safety enhancement plan, or PSEP. Although the vote provides certainty on how the plan will be implemented, the punitive disallowance is disappointing. The PSEP decision and the current gas transmission rate case remain in effect through the end of 2014 and will incorporate future pipeline spending in the 2015 Gas Transmission rate case. Looking at significant regulatory items in 2013. As Tony mentioned, we filed our $1.28 billion application for the 2014 General Rate Case in December. The administrative law judge on that case has approved a schedule that, if followed, would allow the case to be resolved by the end of this year. As part of this rate case, we are participating in a new CPUC process where a third party performs an independent safety overview of our filing. We also filed our Transmission Owner Case, or TO 14, with the FERC and refiled the application at the end of the year…

Thanks, Chris, and good morning. I plan to briefly go through Q4 and 2012 results and then spend most of my time on guidance going forward. Slide 4 summarizes the results for the quarter and the full year. Earnings from operations were $0.59 for the quarter and $3.22 for the year. GAAP results are also shown here and reflect the items impacting comparability for natural gas matters and for environmental-related costs. The natural gas item is laid out in pretax dollars in the table at the bottom. Pipeline-related costs came in at $106 million pretax for the quarter and $477 million for the year, well within our guidance range of $450 million to $550 million. We had been trending towards the upper end of the range during much of the year but some of our expected legal costs were pushed into 2013 given delays on the pipeline investigations while settlement discussions were underway. Importantly, during the quarter, we took a pretax charge of $353 million for the capital that was disallowed in connection with our Pipeline Safety Enhancement Plan. Going forward, we don't expect additional capital write-offs unless our costs trend higher than our current assumptions. During Q4, we accrued an additional $17 million for possible penalties related to the gas matters. Our original accrual of $200 million done in Q4 of 2011 included potential fines for missing maps in our gas leak survey program. Since those fines have been paid, we took an additional accrual in Q4 in order to restore the total accrual to $200 million. We continue to believe this represents the low end of the range for possible penalty. During the quarter, there were no additional accruals to third-party liability claims, but we did book additional insurance recovery for $50 million, which you see near the…

Thanks, Kent. Let me just reiterate some of the points from this morning's call. We weren't able to resolve all of the San Bruno issues last year as we had hoped to do, but we have resolved many of them, including the Pipeline Safety Enhancement Plan and much of the third-party liability and I'm pleased with that. Operationally, 2012 was a very productive year for us. We accomplished the work we set out to do and I'm proud of the employees who have been working hard toward our goal of becoming a safer, high-performing company. So challenges remain, our recovery is clearly underway, and our progress will continue in 2013. We have a good team in place, a solid fundamental operating plan and some successes under our belt. We're committed to becoming a high-performing gas and electric utility that our customers, regulators and shareholders deserve. So with that, let me open up the floor for your questions.

[Operator Instructions] Our first question comes from the line of Angie Storozynski from Macquarie.

I might have missed the statements about how much you've accrued for the potential penalty versus the $1 billion to $1.2 billion equity guidance. So your Slide 9 says that does not include potential penalties above the accrued level. So what's the accrued level?

The accrued level is $200 million.

Wow, so you're assuming that, that issuance is largely a function of basically unrecoverable expenses?

And our capital expenditure program.

Okay. And so -- okay. Now if you -- yes, I'm basically a little bit stunned that this is how much equity you would need in 2013. I would have assumed that this is partly a function of the penalty, but well in excess of the $200 million that you have already accrued for. But that's fine. Now can you talk a little bit more about the FERC transmission ROE? It seems extremely low.

Yes, we received a FERC staff order in our Transmission Owner Case that essentially ordered us to file with a 9.1% return on equity, so obviously something we don't think is adequate to attract capital. We think it's a very narrow way to actually consider what our true cost of equity is and we hope to be able to resolve it through some [indiscernible] discussions or else through the legal process, but that's going to take us a while to actually resolve. So we have assumed the 9.1% return on equity for the electric transmission component of our business in our 2013 guidance.

Okay. And then lastly, the pipeline-related expenses, if I look beyond 2014 where you have your legal expenses significantly down, is it fair to assume that the only expense, unrecoverable expense, that I should assume is the right-of-way payment of roughly $100 million, say, '15, '16, '17?

Yes. If you look at Slide 13, it really kind of lays out the natural gas matters beyond 2013. And you can see most of those items we would be either completing the expenditures on are pursuing them through our normal pipeline rate case so it really is the right-of-way encroachment that is the multiyear item that we do not intend to pursue recovery of.

Our next question comes from the line of Leslie Rich with JPMorgan.

Just a couple of quick questions. Can you remind me the purchase price for Oakley when you do have to pay for it and it goes into rates?

This is Chris. We have not put out the price for Oakley. It is under a confidentiality agreement and we still have to negotiate some of the pieces of getting the contract completed. But what I can tell you is it's 586 megawatts. It is a modern facility. It is dry cooled and it is in California with all our related regulatory costs that go with that.

Okay. And then on your comment on solar, you said that you would not continue with utility-owned solar investments beyond this year. And I recall you had a solar program for x number of megawatts over a multiyear period. Was that scheduled to finish this year? Or are you building less than you had originally thought?

Leslie, we completed the first 3 years of a 5-year program so basically we're not completing the last 2 years and as I said in my prepared remarks, we're just seeing prices that are much better through the contracting process.

Our next question comes from the line of Mr. Dan Eggers with Crédit Suisse. Dan Eggers - Crédit Suisse AG, Research Division: Tony, just kind of on the OII proceedings and kind of the outlook given, the fact that the settlement talks fell apart a little while ago, is this something from your perspective that's going to have to go through the full regulatory process to come to conclusion? Or do you think there is leeway or interest in finding a workable solution for all the parties, given what you guys have been through so far?

Yes, we made it clear that we are open to settlement. As I've said time and again, we need to get these proceedings behind us. That said, we've got to get the other parties to the same position. Disappointed toward the end of last year, we thought we were getting very close and it became apparent that we weren't as close as we had hoped, but we made it clear to everyone, we're ready to sit down. But what I don't want to do is go into extended settlement discussions and defer resolution of the proceedings. As we saw from the PSEP proceeding, while the result wasn't what we had wanted, it is a result we know where we are, we had the plan approved and we can now move forward and deal with it. So it's almost more important to us to keep the proceedings moving to get them done. But that said, these settlements can occur very quickly if, in fact, we get all the parties agree and that's what we want to do. Dan Eggers - Crédit Suisse AG, Research Division: Okay, got it. And then I guess on the encroachment issue, how did you guys come to the $500 million number you based on kind of what you surveyed so far? And how high is your confidence that's going to be the ultimate cost?

Dan, this is Chris again. Well, what we did is, as I said, we're going to go through a detailed center line project. But that project is going to take us through the end of this year to get completed. And so we wanted to be able to provide some overview of what we think the numbers would be. So we used a lot of our aerial photography capability to look over the lines and then we also used some inputs from testing that we've been doing over the last year, including some pilots that we had in place. And so what we tried to do was estimate based on what we've seen in the past, how many -- how much vegetation is out there around our lines, how many structures might be in and around them and then estimate what those costs would look like in doing that. And so as you can imagine, the large part of that $500 million is construction-type costs and vegetation management-type costs that are associated with that. So we feel like we've done a lot of due diligence around it. Obviously, we'll have to tweak it as we physically get out and walk the line to make sure, but we think we have a pretty good estimate there. Dan Eggers - Crédit Suisse AG, Research Division: Okay. I guess one last one. Kent, when you look at the range of CapEx, the high end to base case, can you just maybe help bucket a little bit more of that spend? How much of that is going to be pipeline-related versus electric transmission-related versus other stuff just so we can try and gauge the potential for the high versus low?

Dan, I think on the slide, we kind of at least for 2013 show our pipeline spend, broken out in the assumptions page, which was, I think, Slide 6. So you get a sense of our electric transmission CapEx for this year is about $800 million -- excuse me, are you saying electric or gas? I'm sorry. Dan Eggers - Crédit Suisse AG, Research Division: Both actually.

Okay. Yes, that slide shows you kind of how much is electric transmission. It shows about $850 million and then you see the gas transmission, which is in the $350 million range. So those are kind of -- then you want to add the PSEP down below, which is $450 million, so there are comparable sizes for those 2 parts of our business. Dan Eggers - Crédit Suisse AG, Research Division: Do you expect to continue at that rate? And does the sensitivity to that spending is going to affect the range?

Well, it's not exactly the same number in future years, but you'll see overall we are increasing, and those would be some part of those increases.

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

I'm just curious, I think Tony made the comment at the beginning that in 2014, you [indiscernible] earnings allowed return everywhere except the Gas Transmission business. And given that a lot of these merging were costs and other stuff so, if I'm understanding it rightly, are excluded from operating earnings, will you comment on the GAAP results or are there other things that are causing you not to earn that allowed return in '14?

Jonathan, this is Kent. In 2014, it's just that the GAAP pipeline profile is what it is. We're spending dollars in a lot of areas that weren't in our last Gas Transmission case. Our intent is, in 2015, to be able to true that up for the items other than the right-of-way work. And so that's really why 2015 is a really important year for us on the Gas Transmission business. The other lines of business, we would be addressing to our General Rate Case in 2014 and then our Transmission Owner Case for electric transmission, which we tend to do just about annually.

Okay. So it's really the integrity management and other work, or that's below the line kind of...

Well, the integrity management, you're right, we have been breaking out as a big, new category where we're spending a lot. But even within the Gas Transmission business, notwithstanding the item impacting comparability, I indicated that of our incremental spend across the utility of $250 million this year and last year, about $50 million of that is the Gas Transmission business. So that piece of the $250 million also wouldn't be trued up until 2015.

Okay, understood. And then on the equity, Kent, you've listed out the sort of various -- the drift, 401(k), dribble, can you just remind me what the reasonable expectations for how much you could raise through those programs collectively and at what level you'd be looking to step outside of those plans?

Well, if you look at our 2012 equity issuance, for example, which was $775 million, we did those in sort of 3 fairly equal pieces. So we got about 1/3 of that through our internal programs, our drift on our 401(k). We got about 1/3 of that through our dribble program and then the remaining 1/3, about $250 million, we did through a block transaction early last year. So that's not to put a cap on how much you could do, for example, through the dribble program. That's just how much we did last year. And we're going to continue to evaluate the options that make sense for us given our profile and the timing and so forth in 2013. Obviously, one factor will be when and how the pipeline matters get additionally resolved.

For sure, but I mean there's -- does it seem -- so is there a scenario where you could do the number you've put out? I guess the number's likely to be bigger, whatever, but is -- would you use the base assumptions from last year, about 2/3 of last year's number through the programs and the rest of the block? Is that a good working assumption?

Yes. Jonathan, I think the key will be we'll probably get up to about $300 million to our internal programs, and we'd want to optimize the rest of our issuance. Undoubtedly, the dribble will be a significant component of that, but we're going to really use the various options that we have in the way that makes the most sense so that we can have issuance that is both efficient and effective.

Our next question comes from the line of Hugh Wynne with Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Tony, as you know, I mean, the normal utility business model is you provide safe and reliable service, you get to invest a lot of capital doing it and you earn a nice return on that and then you pass through the operating cost to the customer. On the gas side, PG&E seems to be running kind of an anti-utility where the service isn't safe and reliable. You spend a lot of capital trying to catch up on the safety and incur a lot of integrity management costs and then you just write it off. It's kind of like burning $100 bills. How confident are you that this is over now or do you fear that there could be other items like the right-of-way clearance that are still looming ahead and might limit your ability to recover capital and operating costs in the future?

Well, we're clearly playing catch-up in investing in the system, but I think we're starting to see certainty emerge. So for example, Pipeline Safety Enhancement Plan, as we said, went through the proceeding. We had proposed that we recover about 85% of the plan. Some of the interveners in the case said, "No, you ought to recover nothing." We ended up in a 60% range or so, which is less than we want, but it gives us some certainty about what we are going to recover going forward in the future. In terms of what other expectations, one of the things that we've done is we've reviewed -- or in the process of reviewing, every single aspect of our gas business, kind of divided the system into asset classes, so gas transmission, rights of way, gas storage, and we prioritized based upon where we thought the largest risks might be. And we're comfortable that we think we've identified all of the large risks. We're not through all of the asset classes yet, but the ones that we're working through and we want to be through our top to bottom review certainly by the end of 2013. But since they're lower-risk areas, we don't expect numbers to emerge that would be anywhere near what we're seeing from the right-of-way clearance numbers. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Right. And if you've already said this, I apologize. But can you remind me what FERC ROE is assumed in the earnings guidance for '13?

Yes, Hugh, we're assuming the 9.1%, which was what we were ordered to refile with the FERC. So that is assumed for 2013.

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

Asked and answered, actually.

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

Kent, can I just ask what -- I might have missed this in your presentations, I apologize. Running -- what is the average shares outstanding in the '13 guidance?

I actually didn't provide a share count for the '13 guidance, but we have indicated that the year-end count was 431 million shares and that our guidance based on the assumptions we've provided is to issue equity of between $1 billion and $1.2 billion during 2013, and that all is based on our current accrual for the fine so if the fine ends up being an incremental amount above that, then you would want to adjust those estimates accordingly.

Okay. If I can then ask another related question, where did the book value per share end up for the corporation at the end of the year?

I don't have that with me, Ashar, but that will be available when we get our 10-K out later today.

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

A couple of questions. Looking at both Page 6 and Page 8, kind of the guidance on the natural gas matters. First question, I completely understand the moving all the PSEP and all the San Bruno items into the IIC. But just curious what went behind the decision to move things like the right-of-way work. I mean, doing work for the next 5 years strikes me as a recurring item a little bit. That's the first question. Second, can you clarify that second bullet point on financing and depreciation cost? Are you saying that's $1 billion and therefore you'd apply kind of whatever depreciation rate to that to get to what the earnings drag from that would be?

Yes, this is Kent. I'll take your second question first and you're interpreting the bullet on Slide 6 correctly. We expect our CapEx to be roughly $1 billion over what was authorized in our last GRC and other proceeding and so during this year, we'll incur the associated financing and depreciation costs on that. And then that's what we would true up in the 2014 General Rate Case, so that's the correct interpretation. Your other question about the natural gas matters is -- you're correct that the right-of-way work is for a long period of time. What we try to do with all the gas matters is give you the full picture of them because every -- all of this really relates to the recovery following the accident at San Bruno. And so what we're trying to do is give you as much transparency as possible so that you can understand what's in there as compared to just have it all blended into our overall GAAP results.

Got it. And when we look at your rate base guidance slide of the kind of through 2016, I think it's Slide 12, does that include or exclude the CWIP balance and can you just give us an update on what that CWIP balance is?

It does not include the CWIP balance and I've indicated in our guidance that we would expect our below-the-line costs that we normally incur to largely offset our equity AFUDC. So we've not included that on the slide. In terms of what CWIP has usually run for us, I would say over the last few years, it's probably averaged in the $1.5 billion range, something like that. So you could probably use that as a ballpark guesstimate.

Got it. And I guess one final question just when you think about financing and over the next 12 to 24 months, really the next several years, would you ever consider using anything other than just straight common, meaning converts or something like that? We've seen some other companies in the industry use that to help finance when they've got a multiyear kind of high growth in CapEx planned? Or does -- from a regulatory standpoint, does that make it harder to use instruments like that?

No, I would say those are instruments that we are definitely considering in the future. We have a lot of different alternatives, and we're really trying to figure out which ones make the most sense for us given our profile, sort of the timing and nature of our needs. But those are definitely on the radar screen.

Our next question comes from the line of Anthony Crowdell with Jefferies. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: I just want to know when I look at your -- the midpoint of your 2013 guidance, I look at your forecasted rate base, I calculate an earned ROE of somewhere like 5.0%, 5.1%. Can you break out what you think the earned ROEs will be in '13 for your electric and gas business? And going forward in '14 and '15, any comments on where you expect those ROEs to be?

This is Kent. I don't intend to break out earned ROEs that specifically, but I would point you again to Slide 6, which essentially shows you what our authorized returns are. And then in the lower right-hand corner, we have what we label as EPS factors. Those are the key items that will affect our ability to earn the authorized return. So we've been telling you for a while about our incremental spend across the utility and that includes both the gas and the electric parts of our business of $250 million. We just spoke briefly about the impact of higher CapEx for 2013. We talked about the fact that we're expecting our below-the-line costs to essentially offset our CWIP earnings this year. And then we have continued to have a little bit lower gas storage revenues that was -- than was assumed in our gas pipeline case and that's kind of comparable to last year, but it has been a bit of a drag compared to an authorized return. And then the offset to that is that we do assume that we get energy efficiency incentive as we got late last year. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: Okay. If I look then I guess past '14, and I just want to make sure I've heard the correct statements, I think Tony had said earlier in the call that in '14 you expect to earn your allowed return in electric. Is that correct? And possibly in '15, when you file your gas case, is it reasonable to assume that you earn your allowed return or I guess the only cost that you're not putting in there would be the right-of-way encroachment. Is that accurate?

Yes, I think that's right. When you say gas, in that case, what we're talking about is the gas pipeline part of our company. Gas distribution will be addressed in our General Rate Case in 2014. Anthony C. Crowdell - Jefferies & Company, Inc., Research Division: Okay. And it's reasonable to say that '14, you guys earn the allowed return in, I guess, gas distribution and electric, and '15, you hope to have all the gas pipeline costs except right of way in that rate case for new rates, January 1 of '15?

That's what our objective is.

Our next question comes from the line of Jon Cohen with ISI Group.

I just had a question about the timing of the equity issuance. So if we're standing at the end of 2013 and you would have issued the $1 billion to $1.2 billion, can we assume that all of the unrecovered costs through '13 are now going to be incorporated in your capital structure and you're going to be sitting at a 52% equity ratio and really beyond 2013, the only equity that you'll have to issue other than normal course of business CapEx and the fine is going to be for the integrity management, the PSEP, O&M in '14 and the integrity and -- sorry, and the encroachment beyond 2013?

This is Kent. I think you're thinking about it the right way. We don't really necessarily manage to be at exactly our authorized equity ratio of, say, December 31, 2013, but we do have to manage our capital structure over a period of time such that it averages to that level. So sometimes, we're slightly below. Sometimes, we're slightly above. But the intent of your statement is correct, which is that we try to keep up with our equity needs over time. And I think the way you articulated some of the cost beyond 2013 that we would need to fund with incremental equity sounds appropriate to me.

Okay. And then can you just let us know in that $1 billion to $1.2 billion, do you assume any incremental insurance recoveries above what's already been received?

We've not provided in our guidance any assumptions about insurance. When we do our internal forecasting and determine some of the ranges of our -- what financing needs we have, we usually try to come up with some assumptions about insurance proceeds, but we're not disclosing what those are baked in to our equity assumptions.

Okay. And then the last question is do you have some flexibility over when you issue the equity? So if you think that you might get closer to a settlement between now and year end, could you put off the equity issuance and sort of lean on short-term debt or the parent revolver and do one big equity issuance later in the year?

Yes, we do have flexibility about the timing. Although we do need to maintain our capital structure over time. So we wouldn't want to get too far off on that issue, but we do have some flexibility there and we do intend to issue it in a way that's efficient and to not be -- to have to be rushed to issue equity in a way that wouldn't make sense for our company and our shareholders. So we would try to manage that and I would anticipate if we needed to manage the timing of an issuance that we could do some short-term measures to give us that flexibility such as you describe.

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

I wonder if you could quantify the difference in the drop from 2012 EPS to 2013 midpoint guidance that came from that cut in the allowed ROE and then also perhaps the cash flow impact from that.

Well, that is the biggest item, Travis. There's no doubt about it. I think you can pretty much just get there by taking the rate base amounts, which we have broken up by line of business so you can take electric transmission, for example, and you could go from what was sort of implicitly in our guidance before for last year of 11.35% and take it down to 9.1% from 52% of that rate base. And then you could do the same calculation for the other lines of business going from 11.35% to our new assumption of 10.4% based on the PUC's decision. And I think you'll pretty much land with what we landed with.

Okay, great. And then, real quick, how much incremental debt do you expect to issue in 2013, I would say, for the equity above that?

We've been -- if you look over the last several years, we've been issuing long-term debt annually that probably averages about $1 billion and I wouldn't expect a significant difference in that in terms of an order of magnitude change or anything. So somewhere in that very rough range would probably be a reasonable expectation for 2013.

Our next question comes from the line of Kevin Fallon with SIR Capital Management.

Just a question, do your financing plans and your rate base guidance include the impact of bonus depreciation?

They do for this most recent bonus depreciation, but the reality of our situation is given the pancaking we've had from last several years of bonus depreciation, even before 2013 bonus was approved, we already were expecting to be in a net operating loss position for 2013. So it's really not going to be providing us any financing benefit incrementally in 2013. And we'll probably see that benefit actually next year just given our current situation.

Okay. And just to clarify, on Slide 12, the rate base slide, those are average rate bases or year-end rate bases for the shown years?

Those are average rate bases.

Okay. And finally, just if you could give some color on the FERC rate case process? As you go through the settlement talks, when you ultimately come to the endpoint, however it turns out, is the ROE adjusted for the change in the 10-year treasury? So if interest rates move higher, do they make adjustment or are you stuck at that base 8.6% for this proceeding no matter what?

This is Tom Bottorff, Senior Vice President of Regulatory Affairs. The rate of return has yet to be determined that we're seeking but if we settle the case, the rate of return is sort of [indiscernible], it's not explicitly adopted as part of the settlement. So as in prior rate cases, there really is no adopted rate of return. That would only happen in the event of going to litigation [indiscernible].

But that's what I mean. They gave you a point estimate to change rates on under the current to the 8.6% base ROE and that's what I'm asking. That was an administrative determination by the FERC and is there an administrative process x something in your settlement that changes that or is that 8.6% the base unless you reach a different number in the settlement?

If we reach a different number in the settlement, then the rate would we based on that adopted figure.

But if the case is litigated and rates move higher, is it adjusted upward or is it stuck at that 8.6%?

Right now, the issue is we had to submit our application with the 9.1%. It has the 8.6% plus the 50 basis point adder for the California ISO and that is based on data that was available when we did the filing. And essentially, we looked at a number of comparable utilities and it is prescriptive in that we're required to use the DCF model, which, of course, is particularly disadvantageous in this current economic environment and we don't think representative of our true cost of equity. So we would have to litigate that and unless the FERC ended up with something that was more reasonable, then we would have to seek legal review of that decision.

We have a follow-up question from the line of Ashar Khan [ph].

Kent, I just went back and looked at your 10-K from the third quarter, so I guess you were around $30 and then I've got the GAAP earnings and the dividend. Am I -- tell me if I'm doing my utility maths wrong or right. GAAP earnings, you're showing this year, $1.66 to $2. The dividend is around that level. So assuming we come out book value does not increase, it remains at 30 or so, then is it fair to look at it that if the company earns around 10% that by the end of '13 that the earning power is more like $3 a share or something like that?

I don't know. I can't follow your logic over the phone. So if you want to follow up with our IR team about your question, maybe we can handle it that way, Ashar.

I apologize for breaking in and if there are any questions remaining, but we do have some constraints on this end. Please call the Investor Relations line if you have any follow-up questions, and we wish you a great day and talk to you the next time. Thank you.

Ladies and gentlemen, thank you for attending the PG&E Corporation fourth quarter earnings conference call. This now concludes the conference. Enjoy the rest of your day.