PG&E Corporation (PCG) Q4 2012 Earnings Report, Transcript and Summary

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 settlement, the judge in the case recently took the trial off the court's calendar and encouraged the parties to continue settlement discussions on the remaining cases, and we continue to receive insurance payments. As we reported to you each quarter, we've also made substantial progress on gas operational needs. One area where our assessment is not complete is the encroachment issue on our gas pipeline rights of way, but we are including a range of costs in our guidance today and Kent will get to that later. We continue to be focused on that issue, as well as resolving CPUC and criminal investigations. We're starting to transition from the uncertainties of the past couple of years and we have taken steps to position the company for long-term success. As I've mentioned before, we've adopted a more rigorous multiyear planning process, which has put us on a positive trajectory towards operational and financial success. As part of our planning process, we established key operating metric target at the beginning of last year and we closed the year with strong performance against those metrics. Our continuous improvement program is up and running, and we filed our 2014 General Rate Case application, which is intended to re-baseline the company's distribution and generation operations. Our objective is to execute well on the programs outlined in the GRC, enabling us to earn our authorized return in 2014 with the exception of the Gas Transmission business. As I've said since arriving at PG&E, we can't rebuild our company without also rebuilding relationships and being a trusted partner. The first step is with meeting our operational commitments. In 2012, for the second year in a row, we executed an unprecedented level of gas work and we've gotten much better at communicating with our stakeholders about the work that we're doing. We've been collaborating with public officials in Sacramento on important policy issues such as residential electric rates and greenhouse gas emissions. We're also improving our relationships with the cities and towns across our service territory. Last year, we piloted an initiative to strengthen our local PG&E presence, and we're so pleased with the result that we're expanding those pilots across our system. In addition, the customer outreach and education effort that we won in 2012 is delivering results. We're seeing strong momentum in our customer satisfaction survey scores, and our brand favorability numbers have moved up sharply, but we recognize that relationships with our customers are still fragile. To continue to earn back their trust, we simply have to keep our focus on improving the safety and reliability of our system and our service. We believe that delivering strong operational results for our customers will lead to strong financial results over time. So now I'm going to turn things over to Chris, who will cover the regulatory and the operational items in a little more detail. Chris?

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 under order from FERC staff to use a much lower return on equity. We have filed a request for rehearing as we believe the resulting ROE is insufficient to attract capital. Moving on to operations. 2012 was a very busy year across the entire company as we executed on our plans to enhance the safety and reliability of our system. In the gas business, in 2012, we completed pressure tests on 175 miles of pipeline. This level of strength testing in a single year on pipes already in service exceeds anything any other utility has done before. We also replaced 40 miles of pipe and installed 46 remote or automatic shutoff valves across the system. This year, we will complete our comprehensive validation of the Maximum Allowable Operating Pressure on all of our gas transmission pipelines. As you know, we have brought in an experienced gas leadership team and tasked them with ensuring that we have a safe and reliable system. As part of their evaluation, they've identified additional work related to integrity management requirements and maintaining pipeline rights of way across our system, both of which we've discussed with you in the past. On the integrity management side, we've made some changes to our risk assessment methodology to better align with leading practices. So for example, we've strengthened our procedures associated with identifying manufacturing and construction defects in the internal corrosion on our pipes. We're now incorporating assessment and testing for these and other potential challenges into our integrity management program, where we'll also use the information for asset management and investment planning. Much of this work was not included in our last gas transmission rate case. The cost for the work we do this year and next will not be recovered, but we do plan to include this enhanced integrity management approach in our request for the next gas transmission case starting in 2015. With regard to the encroachment on our rights of way and the necessary mitigation we'll have to undertake, we're conducting a detailed survey to ascertain the exact coordinates of the pipeline within the rights of way across our entire service area. We expect to complete this survey later this year. Meanwhile, we've relied on aerial photography and other inputs to develop preliminary cost estimates. Our information thus far confirms that the encroachments are numerous and significant and because this issue arises from our ineffective patrolling in the past, we will not be able to recover these costs and rates. We expect the total cost for this right-of-way work to be on the order of $500 million over the next 5 years. Obviously, this is a significant cost, but it's work we're committed to get done and to get done effectively and efficiently. Shifting gears, we're really pleased with the work being done to provide reliable customer service in the electric operations and in energy supply. For example, in electric operations, installing smart grid technology such as intelligent switches on more than 100 distribution circuits helped us reach record reliability for PG&E for the fourth year in a row. While we're not yet at the first quartile level we aspire to be, our consistent improvements give me confidence that we're making good progress in that direction. At Diablo Canyon, we had another year of strong performance on safety in operations and ended the year with a 90% capacity factor overall. And earlier this month, we began a regularly scheduled refueling outage on Unit 2. Finally, we continue to progress on the renewables area and are on target to meet our commitment of having 33% renewable power by 2020. However, as part of that process, we have decided not to continue with our utility-owned solar PV program after this year as we are getting better pricing for our customers through competitive bidding. We're seeing the results of our focus on operations in planned incremental spending and capital investments, all of which continue in 2013. This year, the additional capital spending will support things like consolidating our electric and gas distribution control centers and installing more sophisticated technology. We believe it makes sense to continue these efforts going into the next General Rate Case given our progress in improving our operations across the board. Our customers are responding in these efforts. Last year, our customer satisfaction survey results were the highest they've been since 2009. This reflects our customers' appreciation for our team's commitment to restoring power quickly and safely. And with that, I'll turn things over to Kent.

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 bottom. That brings total insurance recoveries to $185 million during 2012 and $284 million since the accident. In terms of the items impacting comparability to environmental-related costs, which is back in the top part of the slide, we accrued an additional charge of about $0.02 per share in Q4, reflecting updated cost estimates related to property purchases and whole-house water replacement. Slide 5 shows the quarter-over-quarter comparison of earnings from operations including the main drivers that take us from $0.89 in Q4 2011 to $0.59 in Q4 2012. And most of these drivers are consistent with the items we've seen in past quarters. Planned incremental work across the utility totaled $0.11 negative and employee incentive compensation accounted for a $0.09 difference since the annual incentive in the prior year was well below target. In addition, increased shares outstanding drove a $0.05 decline, storm costs and litigation costs reached $0.02 negative and we had various other items that together totaled $0.06 negative. A few of these items include somewhat lower awards for our energy efficiency programs when compared to the prior year and in lower tax settlements. These factors were partially offset by a $0.05 increase in rate base earnings compared to a year ago. In terms of our equity issuance, we issued a total of $775 million of common stock during the year, bringing our year-end share count to 431 million shares. That's it for 2012 results and I'd now like to move on to our outlook going forward. I plan to walk through our guidance for 2013 and then I'll also provide some thoughts about 2014 and beyond. As we've discussed before, 2013 is going to be a down year for us due to the impact of our lower authorized return, the additional dilution from share issuance year-over-year and our continued incremental spend across the utility prior to a reset in our 2014 General Rate Case. Let's start by going through some of the key assumptions in our guidance, which are shown on Slide 6. First, we're assuming capital expenditures for the year of a little over $5 billion, somewhat higher than last year's level, and you can see the key components of the planned CapEx on the left. We're also assuming an average authorized rate base of about $26 billion in 2013. This reflects past regulatory decisions like our 2011 General Rate Case, as well as pending proceedings such as our current electric transmission case with the FERC. The authorized return on equity for most of our rate base other than electric transmission is assumed to be the 10.4% that we recently received from the California PUC. However, we are assuming an ROE of only 9.1% on the electric transmission business for guidance purposes given where we currently are with the FERC on that issue. Our authorized equity ratio continues to be 52% across the board. We assume that we'll continue to incur about $250 million of expenses across the utility in excess of levels authorized in recent rate cases in order to enhance the level of service we're providing customers. We requested recovery of most of these costs starting in 2014 in our next General Rate Case. There is roughly about $50 million of that total that relates to gas transmission, and that's expected to be incorporated in our next gas transmission case in 2015. Because the CapEx program described will exceed levels authorized in our last General Rate Case and other proceedings by about $1 billion this year, we expect to incur some additional financing and depreciation expense that won't be recovered in 2013. We do anticipate truing up rate base in our upcoming General Rate Case to include recovery of most of these investments beginning in 2014. As we've previously discussed, we expect our below-the-line costs in 2013 to fully offset CWIP earnings. So that's another assumption underlying our guidance. And as has been the case for the past couple of years, we continue to experience lower revenues for our gas storage business due to market conditions being less favorable than was assumed in our last gas transmission case. Roughly offsetting this last item is the assumption that we earn an incentive award for our customer energy efficiency program this year that approximates the one we earned late in 2012. Turning to Slide 7, you'll see that these assumptions lead us to provide a guidance range for earnings from operations in 2013 of $2.55 to $2.75 per share. The primary drivers year-over-year are the reduction in authorized ROE for both the PUC and FERC jurisdictional assets, the additional dilution due to share issuance year-over-year, the impact of below-the-line costs which are expected to fully offset CWIP earnings as compared to partially offset in 2012, and then planned CapEx in excess of authorized levels. These factors are partially offset by the growth in authorized rate base. Moving on to Slide 8, you can see our guidance for the item impacting comparability for gas matters in 2013. We're providing guidance for pipeline-related costs that we expect to incur but not recover during 2013 of $400 million to $500 million pretax. So let's go through each of those components. In terms of the Pipeline Safety Enhancement Plan, we wrote off the capital that was disallowed by the CPUC in Q4. So our guidance in 2013 includes the expenses that we expect to incur but not recover through rates. Our pretax guidance range for this component is $150 million to $200 million. In terms of the emerging work, we're looking at the cost to survey and begin clearing our pipeline rights of way and the higher level of activity we've undertaken on our integrity management program. Our pretax guidance for these emerging work categories is $175 million to $225 million. We expect the right-of-way work to represent more than half of this spend in 2013; as Chris indicated, to be carried out over a 5-year period. We do not expect to recover these costs for the rates. We'll continue to refine our estimates once we've completed the center line survey late in the year. We expect the integrity management work to represent less than half of the spend in 2013 and to continue in future years. However, we plan to seek recovery of these ongoing costs beginning in 2015 in the next gas transmission case. Finally, we're showing a range of $50 million to $100 million for legal and other costs since some costs we planned in 2012 were pushed out with the delayed proceedings at the CPUC. We would expect these costs to decline significantly after this year. You'll notice also that the guidance range we're using for total pipeline-related cost is somewhat narrower than just the sum of the ranges for each period. At the bottom of the slide are the other categories we've been tracking related to gas matters. As we've done in the past, we're not providing guidance for additional penalties coming out of the investigation and the range we show for third-party liabilities continues to reflect the difference between what we've accrued today, $455 million, and then the upper end of the estimate we've disclosed, which is $600 million. We're also not providing guidance for insurance recovery, but anticipate those to continue to follow from the resolution of the third-party claim. On Slide 9, you can see our estimated equity issuance of $1 billion to $1.2 billion for 2013. This range is consistent with our guidance assumption and does not reflect any equity issuance that would result from fines greater than the $200 million we're already accrued. Key factors driving our equity issuance in 2013 compared to 2012 are lower earnings from operations in 2013, somewhat higher CapEx and the PSEP capital charge at the end of last year. We'll continue to utilize various ways to raise equity efficiently and effectively including our dividend reinvestment 401(k) programs and our thermal [ph] program. Slide 10 summarizes 2013 guidance including earnings from operations and the gas matters item. As you can see, we're also including a modest guidance range for environmental-related costs in connection with the Hinkley cleanup. The range here reflects some true-ups we may experience on our whole-house water program during the year, as well as habitat protection activities we may undertake. You'll remember we've already accrued the expected costs associated with our proposed final remedy to clean up the groundwater. Our guidance does not include additional cost in the event of more onerous final remedy this quarter. I know many of you recognize that 2013 is an unusual year for us and you're interested in getting a read on what things might look like in 2014 and beyond. So while we're not providing earnings guidance beyond 2013 at this point, I do want to share with you our current view of our CapEx and our rate base going forward. Slide 11 shows a range of estimated CapEx for 2014 through 2016. The upper end of the range provided for each year reflects the CapEx level included in our 2014 General Rate Case and attrition request. It also represents our current view of future regulatory requests for electric transmission and gas transmission. The lower end of the ranges reflect current spending levels across the utility with some adjustments for known changes such as the end of the Cornerstone Program and the utility Photovoltaic Program. I should also point out that we've excluded the recently approved Oakley generating project from the 2016 CapEx numbers shown here just in the interests of being conservative. Our turnkey purchase of that plant will occur when it's ready to go operational and that could be as early as 2016. The level of CapEx I've described would provide for significant growth over the next few years. And as you'd expect, we continue to issue a meaningful amount of equity to support this growth. Slide 12 shows ranges for authorized rate base consistent with the CapEx numbers. Under these assumptions, average authorized rate base for 2014 ranges from $28.5 billion to $29 billion and would grow to between $32 billion and $35 billion in 2016. The compound growth rate over this period ranges from 6% to 10% excluding the Oakley plant. These numbers reflect our intent in the 2014 General Rate Case to true up our rate base in order to reflect the higher CapEx we're undertaking this year. In addition, we hope to true up our revenues to recover most of the incremental expenses we've been incurring across the utility-approved service both last year and this year. As a result, our objective is to earn our authorized return from the nonpipeline segments of our business starting in 2014. Slide 13 just addresses the fact that in future years, we still expect to incur some costs for gas pipeline work that will not be recovered. You already know that the PSEP decision did not sufficiently fund our planned expense work and that affects us through the end of 2014. After that, we anticipate incorporating our ongoing pipeline safety work into our 2015 gas transmission case. By then, there will be even more data to demonstrate the true cost of doing this work. In terms of the emerging work, Chris mentioned that our current estimate for the right-of-way activities is roughly $500 million over 5 years. So we expect those unrecovered costs to continue through 2017. We also expect our enhanced integrity management program to continue next year and beyond. Though we won't recover those costs in 2014, we do plan to incorporate them into our 2015 gas transmission case. And finally, we expect our legal costs to decline significantly in 2014. On this slide, we have not included things like third-party liabilities, insurance and penalties, and our objective is to resolve those as much as possible this year. Obviously, there may be some things that don't get fully wrapped up. We plan to continue to break out these costs so that you can keep track of the impact that they have on our GAAP results. I'm going to stop here. I know I've covered a lot. Hopefully, the information that we've covered today will be helpful to you in assessing our financial prospects going forward. Tony?

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.