PG&E Corporation (PCG) Q4 2013 Earnings Report, Transcript and Summary

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

Thank you, Rochelle. Good morning, everyone and thanks for joining us. Before you hear from Tony Earley, Chris Johns and Kent Harvey, I'll remind you that our discussion will include forward-looking statements about our outlook for future financial results based on assumptions, expectations and information currently available to management. Some of the important factors that could affect the company's actual financial results are described on the second page of today's slide deck. We also encourage you to review the discussion of risk factors that appears in the 2013 annual report that will be filed as an exhibit to the Form 10-K, which will be filed with the SEC later today. I also want to acknowledge that we have folks on the call in a few different locations today, so please be patient as we coordinate that. And with that, I'll hand it over to Tony.

Well thank you, Sara, and good morning, everyone. We've got a lot to cover today, including the current status of our regulatory matters, our results from the past year and our outlook for 2014 and beyond. So I'll start off and then turn it over to Chris and Kent. In the regulatory area, we're still awaiting resolution of the gas investigations, which are taking much longer than we had ever expected. The record and the proceedings is closed and I believe all parties understand the importance of a timely resolution. I want to repeat an important point that I've said before. We believe it's vital that the final decision in these proceedings recognize the improvements we've made, the significant costs our shareholders have borne without recovery from customers and that the victims have been fairly compensated through the civil proceedings. While we await the commission's decision, we are moving forward with our plans to operate a leading utility and I want to give you a few examples. Our 2013 operational metrics show good results and a positive trajectory in much of our business over the past year. I continue to be really proud of the work our team is doing in the field as we improve the safety of our system and rebuild the culture of our company. A notable accomplishment in 2013 was completing the survey of the Centerline of all of our gas transmission pipes on schedule by the end of the year. And Chris will provide additional details about our operational performance in just a few minutes. In December, we filed our 2015 Gas Transmission and Storage Rate Case. Our request there incorporates the results of our integrated planning process and the risk-based approach we're taking with our operations. In our General Rate Case, we expect a proposed decision in the first quarter. Turning to financials, I'm pleased that our results for the year are in line with our expectations and our guidance. And Kent will provide the details shortly. Looking ahead, our objective continues to be superior execution of the work outlined in our rate cases and earning our authorized return, with the exception of the Gas Transmission business, in 2014. We have solid plans in place to deliver strong results and I'm confident that we'll bring PG&E back to the position of strength we know the company can achieve. So with that introduction, let me turn it over to Chris to go through some of the details. Chris?

Thanks, Tony, and good morning, everyone. I'll begin my remarks with our operations and then touch on regulatory developments. Starting with gas operations. On Slide 4, you can see the progress we made in 2013 to make our pipelines safer. Over the past few years, we've tested and replaced hundreds of miles of carefully engineered and executed work to directly improve safety across the state. As Tony mentioned, at the end of 2013, we completed a comprehensive study to validate the Centerline of all 6,700 miles of our transmission pipelines. We've identified structures and vegetation encroaching on our rights-of-way, which we plan to clear over the next 4 years. We now have a much better sense of the number of units of work involved. As a result, we have greater confidence that we won't exceed the $500 million estimate for the program and we're reaffirming our guidance of $500 million over the 5-year period from 2013 to 2017. 2013 was largely about the survey work and we've only begun the remediation work. As we get more experience with remediation in the field during the first half of 2014, we'll continue to validate and refine our unit cost estimates. Next, I want to highlight some of the progress we've made in the rest of the business. You can see a report on our operational performance metrics in Exhibit C in today's slide deck, which gives you a sense of some of our accomplishments as a company over the past year. Starting with safety. Public safety is an important component of the way we measure our performance as a company and an integral part of the lives of our customers. We exceeded our 2013 targets for public safety metrics in both the electric and gas businesses. That means that last year, we significantly improved our response time to 911 calls and reports of gas odors. We also improved our performance on both the number of gas leaks awaiting repair and the number of downed wires. On the reliability side, our electric reliability scores for 2013 set yet another company record. That makes 2013 the fourth consecutive year where we've set a PG&E record for reliability and I'm really proud of the team's work to get those results. Our customers responded to the improvement. Our customer satisfaction survey scores for this year exceeded our goal and reached levels reflecting pre-San Bruno scores. Now turning to regulatory matters. I'll spend a few moments on some of the highlights of our 3 pending rate proceedings. The first is our General Rate Case. We anticipate a proposed decision in the first quarter, and we'd like to see a final decision in the second quarter of this year. Once the PUC issues a final decision, the revenue requirement change will be retroactive through the first of the year. The second case is our Gas Transmission Rate Case, which as Tony said, we filed in December. The requested revenue requirement reflects a significant increase, though the amount we requested is less than 15% above the spending level we planned for this year. The rate case proposal reflects the work necessary to operate our pipelines safely and the impact of the new higher regulatory and legislative standards in California. We've proposed a schedule for the Gas Transmission Rate Case proceeding consistent with the decision by the end of this year but the assigned administrative law judge has not yet set a schedule. Given the size and complexity of the Gas Transmission Rate Case request, the decision may be delayed beyond the beginning of 2015. We do plan to file a motion with the commission to request that the revenue requirement for the Gas Transmission Rate Case be retroactive to January 1, 2015, even if the final decision comes later. The third rate proceeding is for electric transmission. In January, the FERC approved the settlement in the TO14 case. With TO15, we've just begun settlement discussions with the other parties. Also in the electric transmission business, the California ISO has opened up some transmission projects for competitive bidding. We successfully participated in a bid for a 230-kV line across about 70 miles in the Central Valley. We're looking forward to constructing, owning and operating this project in our service territory, along with our partners, MidAmerican and Citizens Energy. Our electric transmission cases and rate base expectations are included as part of our assets. Two final regulatory items to cover. First in December, the CPUC awarded us $21.6 million in incentive revenues given the successful result of our 2011 customer energy efficiency programs. And finally, last week the court annulled the CPUC's decision approving the Oakley plant. We're currently working with our counter party to determine the next steps for re-approaching the regulatory process. And with that, I'll turn it over to Kent.

Thanks, Chris, and good morning. I plan to briefly go through our 2013 results and then cover our outlook going forward. So let's start on Slide 5, which summarizes the results for the quarter and the full year. Earnings from operations were $0.42 for the quarter and $2.72 for the year. GAAP results are also shown here and reflect the items impacting comparability for natural gas matters and for environmental-related costs. As usual, we've given the details on the natural gas item in pretax dollars in the table at the bottom. Our pipeline-related expenses came in at $138 million for the quarter and $387 million for the year, well within our guidance range of $350 million to $450 million. During the quarter, we recorded $22 million of fines related to natural gas matters and these fines were associated with 2 citations received during the quarter, the largest of which was the recent order to show cause. As you know, we believe that fine is excessive and have requested a rehearing. We did not book any additional insurance recoveries in the fourth quarter. Slide 6 shows the quarter-over-quarter comparison for earnings from operations, including the main drivers that take us from $0.59 in Q4 2012 to $0.42 in Q4 2013. Most of these drivers are consistent with items we've seen in past quarters. Our lower authorized cost of capital resulted in a reduction of $0.08 compared to Q4 of last year, higher CapEx and authorized resulted in $0.03 negative. We took a $0.03 charge related to the termination of some projects and leases that were not economic, and higher shares outstanding also had a $0.03 impact. A number of other items totaled $0.07 negative compared to Q4 of last year and these included things like accruals related to our benefits plans, our past tax equity investing at the corporation and charitable contributions. These negative factors were partially offset by higher rate base earnings worth $0.05 compared to Q4 of last year, as well as the timing of our planned incremental work across the utility, which resulted in a $0.02 increase quarter-over-quarter. And in terms of our equity issuance, we issued a little under $1.1 billion of common stock during the full year. This was consistent with our guidance and brings our year-end share count to 457 million shares. So that's the overview of our 2013 results. Now I'd like to walk through the outlook we're providing today for 2014, as well as provide some thoughts about the next few years. Given our pending General Rate Case and the commission's delays in resolving the gas investigation, today, we won't be providing our traditional guidance for earnings per share from operations for 2014. But we are providing some key building blocks for you to develop your estimates. We're also providing some thoughts on 2015 and 2016. So let's start with some of our key assumptions for 2014, which are shown on Slide 7. First, we're updating our range for 2014 CapEx, which is between $5 billion, and $6 billion. The breakdown by line of business is included here, as well. The upper end of that range reflects the CapEx level requested in our regulatory filings such as our 2014 General Rate Case and our most recent Electric Transmission Rate Case, TO15. The lower end of the range reflects recent spending levels across the utility with a few adjustments for known changes such as the conclusion of our Cornerstone program and the utility Photovoltaic program. On the top right of the slide is the corresponding range for 2014 weighted average rate base, which is roughly $28 billion to $28.5 billion. Again, you'll see the numbers broken out by line of business. When you compare the CapEx range and the rate base range to our previous estimates, you'll see that the CapEx numbers are about $500 million higher than the rate base -- excuse me, higher than before, and the rate base estimates are about $500 million lower. So I want to spend a minute on that so you understand what's going on. The increase in CapEx from our prior estimates is mainly due to the fact that this time, we included all the Pipeline Safety Enhancement Plan capital in our estimate, even though some of it won't go into rate base because of the cost count. Including the total CapEx here, helps you in modeling our financial needs. The decrease in rate base from our prior estimate is mainly driven by slower capital additions for electric transmission. So this is mainly a timing issue with 2014. We expect to catch up on those the next few years. To a lesser extent, the decrease in rate base is also driven by the lower allowed PSEP capital that resulted from the replan we did last fall. At the bottom left of the slide, we lay out the return on equity, as well as equity ratio authorized by the CPUC for 2014. Assuming a reasonable outcome in our General Rate Case, we're targeting to earn our authorized return of 10.4% this year for the portions of our business covered by the General Rate Case, that's electric distribution, electric generation and gas distribution. And I think it's reasonable for you to assume that we'll target to earn a fairly comparable return for our electric transmission business, which is regulated by the FERC. Finally at the bottom right of the slide, we highlight some factors that have affected 2013 results and are expected to affect 2014 as well. For example, we expect to continue to under-earn on our Gas Transmission and Storage business since we won't have the opportunity to true up our cost and revenues there until 2015. As was the case last year, we anticipate higher-than-authorized expenses and CapEx and lower market revenues for gas storage services. Another example is our customer energy efficiency programs where we received incentives for our performance as we did late last year. The net effect of these items in 2013 was about $0.10 negative, and our objective for 2014 will be to target keeping the impact on the business at roughly the same level. Finally, a reminder that we expect earnings on construction work in progress to continue to be offset by below-the-line costs such as our advertising, charitable contributions and so forth. That was our expectation last year, as well. Turning to Slide 8, you'll see the estimated range for our item impacting comparability for natural gas matters in 2014, which is $350 million to $450 million, pre-tax. This is absent any further impact resulting from the outcome of the gas investigations. Now there are 3 components. I'm going to walk through them. The first is unrecovered Pipeline Safety Enhancement Plan expenses, which we estimate will come in at between $125 million and $175 million for the year. Again, the primary work here is our extensive hydrostatic testing program. The second component to is work that falls outside the scope of the Pipeline Safety Enhancement Plan. So this is the rights-of-way and the integrity management work that we have previously referred to as emerging work. We estimate this will come in at between $175 million and $225 million pretax for the year and that it will be split fairly evenly between the rights-of-way and the integrity management and other categories. This year the rights-of-way work is going to shift from mostly survey work, as Chris said, to remediation. And the integrity management and other work will include a continuation of the pipeline work we embarked on last year, as well as some work at our compressor stations. The third component is legal and other cost, which we estimate will come in between $25 million and $50 million for the year. And as you'd expect, with the gas investigations taking longer, some of these costs will push from last year into 2014. At the bottom, the reminder that these figures exclude future insurance recoveries, which would obviously net against cost, and any additional fines or penalties from the gas investigations that we haven't accrued to date. We've also removed third-party liability claims as a line item on this slide because we've now settled virtually all the claims and believe we have adequate accruals in place. Moving on to Slide 9, we're providing an estimate of 2014 equity issuance absent the impact of the gas investigations. Our range is $800 million to $1 billion. I want to be very clear here about the assumptions that underlie this range. First, the range reflects the estimated gas matters' costs that we provided today but does not reflect any additional fines or penalties that could come out of the gas investigations. We're going to leave that up to you to make those calls when you estimate total equity needs. Second, we're assuming we get a reasonable and timely decision in our General Rate Case and are able to earn our authorized return for this year other than the Gas Transmission business. Third, we're assuming no change in our current depreciation rates. We've requested some changes in our General Rate Case, which would reduce our equity needs if they are approved. And fourth, the range is based on the midpoint of our CapEx estimates for 2014, or about $5.5 billion. Deviations from that would obviously impact our equity needs. This slide also just highlights some factors that we expect will increase or decrease equity needs in 2014 when you're comparing to 2013. We'll continue to use the various tools that we've relied on to issue equities in an efficient manner and, in fact, tomorrow we plan to file a new $500 million continuous equity offering program, or dribble program, to replace the previous program we completed late last year. And finally, I just want to spend a little bit of time at the tail end here to briefly look beyond this year. In particular, we're providing updated estimates of CapEx and rate base through 2016, which is consistent with the period covered by our pending General Rate Case. On Slide 10, we've refreshed the range for estimated CapEx for each of the next 3 years. Again, the upper end of the range we're providing for each year reflects the CapEx level included in our 2014 General Rate Case and attrition requests, our 2015 Gas Transmission Rate Case and TO15 electric transmission case. It also reflects our current view of future regulatory requests for electric transmission. And the lower end of the range is based on recent spending levels across the utility with a few adjustments to the conclusions of certain programs I mentioned earlier. We've excluded the Oakley generating project from the numbers shown here. And as you can see, the overall level of CapEx we're providing would give us significant growth over the next few years. Slide 11 shows the ranges for our authorized rate base consistent with the CapEx numbers. Under these assumptions, average authorized rate base would grow to between $32 billion and $35 billion in 2016, which is unchanged from our prior estimates. The compound average growth rate over this period ranges from 7% to 11%. This profile represents growth potential well above average for our sector over this period. I know I've covered a lot, so I'm going to stop there. And I'll turn it back to Tony for some closing remarks.

Great. Thanks, Kent. In closing, I just want to reiterate some of the points from this morning's call. First, operationally, 2013 was a good year for us. We made a lot of progress in many areas and we're establishing PG&E as a high-performing gas and electric utility. Second, on the gas issues. We executed on the critical gas work in our plant. Although we weren't able to resolve all of the San Bruno-related issues last year, we settled the claims of the victims and compensated them fairly. Now we'd like to see the regulators come to a final decision soon. Third, we put in place a strong rate case filings to position us well for the future. So I'm confident that we are lining ourselves up for success. And so now, let me open up the lines and we'll be ready to answer your questions.

[Operator Instructions] Our first question comes from the line of Brian Chin of the Bank of America.

On Slide 18, the Gas Accord 5 costs. Changed a little bit since the last set of slides. Could you just talk about that a little bit more?

Yes. Brian, this is Kent. Yes, we have this overall estimate that we've had of unrecovered gas costs. That includes both past, as well as going forward that we've committed to. And you're correct, our total, previously, was around $2.4 billion and our updated total was $2.7 billion. And I'll just say this number is prominent in our press release because we want to make sure that everyone understands the level of expenditures that we have and continue to make. The biggest piece, really, in the change was triggered by our Gas Transmission and Storage case filing that we made late last year. We made the decision when we did that filing to not seek recovery of 2 types of costs. One is hydrostatic testing for new or vintage pipe, which had been an issue that had been already addressed by the California Commission in the PSEP case, and we decided for post-61 pipe that we weren't going to file for cost recovery of that testing going forward. And that's roughly $25 million a year in 2015, '16 and '17 during the rate case period. And then, we also made a similar decision to not seek recovery of some remedial corrosion work that we identified that we're actually doing this year but it will continue through 2017, again, the GT&S rate case period. And that is roughly $25 million a year as well. So those are really the biggest drivers of the change. We have also updated some other items in our estimates here and there as we do each quarter and those are reflected in our 2014 numbers that I went through on the call.

Our next question comes from the line of Hugh Wynne with Sanford Bernstein. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: I was going to ask a question about the power side here. Coming off a year of very poor hydroelectric generation, I think the lowest since 2001, and it's looking like 2014 will also be a historically low year. Could you comment on the adequacy of PG&E's thermal and nuclear fleet to meet the shortfall in hydroelectric generation and, for that matter, the adequacy of the states' power system, under the circumstances?

Hugh, this is Chris. And for PG&E, you're right, we had a really tough hydro year last year. I think it was the worst drought we've had in over 100 years here, and '14 isn't off to a great start. But when we look out for this summer, we still feel like there's plenty of adequacy of supply. What it really means to us is just that we'll only be able to use our current hydro resources probably during high peak times and some emergency times. But the rainfall, our understanding, up north, is still pretty much close to normal and we do import a lot of hydro power from the north. In terms of the entire state, the ISO is probably a better person to ask, or group to ask, in terms of adequacy of power throughout the state. But we know in our territory, we still look like we're pretty good. Our nuclear facility's running well and all other resources are available to us. So we still feel pretty confident about this summer. Hugh Wynne - Sanford C. Bernstein & Co., LLC., Research Division: Would you expect roughly a similar level of natural gas deliveries across your system this coming year as you did last year?

Right now, it is maybe a little bit more. Again, just because with a little less hydro power available, we may need to utilize some of the gas resources to do that. But like I said, I think we're still pretty good.

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

So just a quick question on what you said about under-earning in 2014. And I think you said that's because the true-up comes in 2015. So I know it's kind of contingent on the rate case outcome, but is there any reason to anticipate continued under-earning beyond '14?

Obviously, all of that depends upon the outcomes of the various rate cases. We feel good about how the General Rate Case went in. And given any kind of reasonable result there, we think on the things that's covered by that rate case, we can earn our allowed return. The reason we say, we won't fully be earning our allowed return until 2015, we've got to get the Gas Transmission & Storage case done, as well. And again, the caveat is we need a reasonable result. But it is still our objective to, after those cases are done, to be able to earn our allowed return overall for the company.

And how do the items that I think what you -- with the items you called out on the call last quarter, that they were also the answer to Brian's question on the numbers on Slide 18, how will you anticipate treating those from a sort of earnings guidance perspective?

Jonathan, this is Kent. The items that you're referring to, the other factors I was describing, those we plan on just continuing to handle through our operations. So no change there. They've been in our operations this year and they will next year, as well.

$75 million on corrosion and post-61 pipes, basically?

No. Sorry, I was misunderstanding you. For, yes, for the corrosion and the post-61 pipe, those -- once we get to the GT&S case for next year, we'd expect those to be in operations. The corrosion already is in operations. We haven't been putting that in our item impacting comparability. We see that as just our normal operations there.

Okay. And then, Kent, you mentioned this comment. You commented when you talked on equity about depreciation, your assuming current depreciation rates, but you've requested some changes in the GRC that would reduce needs if approved. But I guess, you're not likely to get a GRC decision during -- on a timely enough basis to change this year. But could you just -- how should we think about that or any quantification you can put around what that aspect of the ask would do to your equity needs.

Well once -- if we actually got all the change in depreciation that we requested, it could affect us a couple of hundred million dollars in terms of equity needs. That depends on getting the full ask and I think it will really depend on where the commission comes out. And obviously, we -- it's not going to be at the beginning of the year but once we get into the year, we would start making the adjustments. But again, you're right, our guidance assumes no change in our depreciation rates.

Jonathan, last -- one thing, though. Just on -- to be clear on earning the authorized rate of return post-2015 does exclude the impact of our Centerline survey and clearance that we're doing on that. I just want to make sure everybody's clear.

Yes, that's correct. That tail, as we've said, is about $100 million a year through 2015. And we know that -- excuse me, through 2017, and we know that, that's out there for a few more years.

Right. And are you intending that will be an item impacting comparability or is that something that will hit your operating earnings?

That is my expectation. That, that item we flagged as an item impacting comparability. It will continue until we complete the project.

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

First on the $0.10 of under earnings in '13 that continue to '14, that's all the gas under earnings, net of the energy efficiency benefits. So it's a net number of all that?

That's correct, Steve. It's all of our operating under earning. It excludes, obviously, the item impacting comparability.

Okay. Second question on guidance, do you need the outcome of both the GRC and San Bruno penalties to then give guidance or to get one or the other, do you think you'll give it?

Steve, I never know until I actually see what plays out. But my expectation would be that we're more likely to give guidance once we have both factors resolved.

Okay. And then, can you maybe just spend a quick second on Slide 20, and what you're trying to highlight there in terms of how to think about equity issuance?

Yes, Steve. This is one that I know I've been talking with investors about for some time now. We try to just put in the slide, a summary of how different factors have different impacts on equity issuance because we sense that some people have struggled with this, and so we thought this would be helpful. So I think everyone's pretty clear that a fine that went to the general fund would not be tax-deductible so it's a one-for-one impact on our equity issuance and that's why we show 100%. I think most people expect that our unrecovered expenses will be tax-deductible and, therefore, you see a 60% impact on our equity issuance. The capital write-off, which is a phenomenon we've experienced lately has confused people. And in this case, when we've already spent capital, as we did previously, and then had to write it off, as in the PSEP, because we'd already financed the capital itself, it actually has 1/2 the impact. So you're getting down to only a 30%. In other words, it's both tax-deductible but we'd already financed the cash, so it's essentially a noncash write-off at that point. And so we just wanted to lay that out because some people were struggling with their equity issuance estimates and we thought this might be helpful.

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

So first, going back to the GT&S case, could you talk a little bit about -- is there a precedent for receiving recovery before the case has actually been decided? I suppose you mentioned that you were going to seek such a filing in the near term.

Yes, this is Tom Bottorff. We have not yet made the request but we expect to do so later this month. And the precedent for doing so has really been established in General Rate Cases, where we did just in this last case, made a similar request and the commission authorized retroactive approval, assuming a delay would be in effect. So we are going to follow the same process with the GT&S proceeding and file that motion, and we'll see if the commission approves it in the same way.

Excellent. And then, secondly, Oakley. What are next steps there as far as you're concerned?

Yes. This is Chris. We will -- we're working with our counterparty right now to take a look and see how we're going to re-approach the regulatory process. We need to address what the courts ruled was a lack of evidence around the need, and so we're going to work with our counterparty to try to put the best case we can together to be able to address what the court's concerns were.

Got you. But just to be clear, it's not in any of the rate based numbers, et cetera?

That's correct.

No, that's correct.

Great, excellent. And then, let me just clarify one last time, with regards to the equity need. Outside of a final fine number, is there anything that's not encompassed in that range you just provided?

Well, Julien, what's not encompassed is the resolution of the gas investigations in general. So this essentially reflects the guidance that I provided today on our item impacting comparability for gas matters. But to the extent there are other disallowed costs -- could be fines, but could be just disallowed costs, those would be incremental to these equity needs.

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

A handful of questions. First of all, thinking out past 2015. Outside of the $25 million a year that are actually 2 separate tranches of $25 million a year that you'll incur on the gas side from 2015 to 2017, what else is out there that could keep you from earning authorized in the '16 or beyond timeframe?

Well, this is Kent, and I guess I would say, what still is a fact not in evidence is just the outcome of the Gas Transmission & Storage case. Those are the costs that we have not sought recovery of. Now we actually need to get a balanced outcome out of that proceeding so that we can actually true-up our cost and revenues. And that's probably the biggest issue that we just don't have a lot of visibility yet, too, just because the case is early on.

Got it. And in the rate-base slide you show going out to 2016, is the CWIP included in that rate base number?

No, that's only rate base. It's not construction work in progress.

At the end of '13, what was that CWIP balance?

I think it was roughly $1.8 billion. It's been fairly stable over the last year.

Got it. So if we think about the $1.8 billion, maybe it grows a little, shrinks a little in that direction, and assume kind of a 50 -- basically assume your pre-tax cost of capital. That's kind of what the corporate, the advertising, the donations, the other costs are that you're not necessarily recovering in rates?

I think that's a fair way to go about it.

Got it. Last question, cash taxes versus GAAP taxes. Do you expect to be a significant cash taxpayer or a limited cash taxpayer in 2014?

This is Dinyar Mistry, the Controller. Yes, we do expect to not have much in terms of cash taxes for 2014 because we have a net operating loss carryover as a result of the bonus depreciation.

Got it. And what happens after '14? I know bonus DNA goes away, but are there other things that could keep you from being much of a cash taxpayer?

Actually, the NOL impact should carry over into '15. I'm not sure that it will completely wipe out cash tax payments in '15 but it will have an impact in '15. And then going forward, we're back to normal.

Our next question comes from the line of Michael Goldenberg with Luminus Management.

I wanted to continue with the CWIP discussion. Now you said CapEx is higher but rate base is lower because of timing difference. Does that mean some will be going, some extra capital, will be going into CWIP and, at least, temporarily increasing your AFUDC earnings?

Well I think what -- this is Kent. I think what's really been going on, the area where we've had kind of a delay in the capital additions has been electric transmission, and I'm sure we're not unique in the industry in terms of those projects tend to be somewhat unpredictable, timing-wise. And that's really the area where there's been the biggest part of that phenomenon. And that can have some impact on CWIP, there's no doubt about it, but I wouldn't say that, that's going to be dramatic. And again, it's kind of a nearer-term issue, it's not an ongoing issue that we see in our numbers in terms of the true-up.

But what I'm trying to understand is if you're showing higher numbers than before in CapEx and rate base numbers that are lower, where is that capital going?

Sorry, so what I was saying about the higher capital expenditures is previously, when we showed our capital expenditures for 2014, we didn't have the unrecovered PSEP costs in there. And our concern with that, those are expenditures that we're making and so, obviously, they affect our cash flows. And everyone needs to understand that, but they're not actually going to be in CWIP and go into rate base because of the PSEP cost cap. And that's really the biggest driver that caused the capital expenditure change for 2014.

Got it. I know you're not giving guidance but one thing I wanted to understand is transmission. When you do issue guidance, can you talk about the embedded ROE for transmission for 2014 and what it was in 2013?

Well, what I would say in terms of how you ought to think about it for 2014 was just, in general, I think it's reasonable for you to assume that, roughly, we target a similar ROE for the electric transmission business as we do have authorized for the rest of our business by the California PUC. So I think that's the reasonable assumption.

What was it in 2013?

I don't think it was dramatically different from our authorized levels at the PUC. Same order of magnitude.

I thought for some reason, in 2013, it was lower because you got that decision on the transmission part?

We ultimately settled that prior transmission owner case so -- and it was only in effect for a limited amount of time during 2013.

Right. So most of 2013, were you embedding a lower transmission ROE?

Yes, you're right. The first part of the year, we probably earned somewhat less than our authorized return. You're correct, Michael, as I dial back to the beginning of the year. So yes, we probably came in a little less than we would've liked to have from an authorized perspective.

Our next question comes from the line of Kit Konolige with BGC Partners.

Kent, so just to follow on the guidance, to make sure I understood you correctly. Are you saying the -- I think I heard you say, you'd be more comfortable giving guidance after both the GRC and the San Bruno proceedings were completed, is that correct?

Yes, I think that's my current working hypothesis.

Right. And how much of the uncertainty about '14 is related to the GT&S case as opposed to the -- so I mean presumably, you'd give guidance -- obviously, that will be going on the whole year?

Yes, that really won't get resolved until we get to the end of 2014 or 2015. So I think it'd be unrealistic to expect that to be closed out for us.

Great. And on the timeframe for the proceedings, you guys sounded pretty confident that the GRC-proposed decision could come out in the first quarter but I didn't hear any estimate of when the San Bruno proceedings might be concluded or even have a PD, is that -- obviously, they are different proceedings. What gives you the level of confidence there?

Kit, let me start off and maybe Tom Bottorff might want to add to it. But with respect to the San Bruno proceedings, there the real indicator was comments that President Peevey made publicly that he expected a proposed decision sometime towards the end of February. And so that's out of our hands. I think we we've got to take him at his word that, that's the best estimate right now out there. That, that decision would come out from the ALJ in that timeframe. The GRC proceeding, we went through that proceeding. We thought it went in very well. And I think just based upon feedback that we've gotten -- that we still think we're going to get something in the first quarter. I don't know, Tom, whether you want to add anything to that.

No. That covers it, Tony.

Great. And finally, also regulatory-related, when you made the GT&S filing, there was a kind of flurry of activity in the press along the lines of PG&E asking for a lot of more money, et cetera, et cetera. Do we have any indication at this point that this proceeding is going to be able to get done without having too much interference from thinking along the lines that you still owe a lot for San Bruno and earning a fair return on invested capital in the gas business would be a problem and you ought to be still paying? In short, how confident can we be that the San Bruno proceedings, currently, can wrap it up and lead to a reasonable regulatory regime afterwards?

Well, Kit, this is Chris. And I think that we've seen a lot of evidence already that the commission has said that they're going to focus any penalties and anything associated with San Bruno in those proceedings. And I think if you look at some of the rulings that we got last year related to our energy efficiency program, to our economic development rate, through the extension of the cost of capital mechanism, all of those things seem to be reasonable outcomes for us, and so we feel pretty good that there's not going to be some overhang. Now obviously, that doesn't mean that interveners won't come in and try to make some of the same arguments. We fully expect that they would. But when we look at our case, I think there's a big difference between this case and what was in the PSEP and some of the arguments that were made there. The first case, the PSEP case, had a lot of costs associated with doing -- upgrading our records and that will be done and is not included in this new case. And the commission also disallowed a lot of our contingency requests in the first case and obviously now, after 3 years, we have a lot more insight into the costs. And so I think that this case is really focused on increasing the safety and complying with the new regulatory and legislative rules that are in place in California, and so we feel it's a pretty compelling case. As I said though, I'm sure that there will be a few interveners that will try to bring back some of the old things. But I think when you look at what the commission's done, we feel pretty good that they want to put everything into the hearings that are going on now and then move forward.

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

Just a regulatory question. Early in the call, you had stated that, or I believe you stated, that the record for the San Bruno proceeding was closed. Did that require a letter of submission to be closed and was that public? Just because I'm hearing mixed things from other people that it requires a letter of submission and a record is still open.

Yes, this is Tom Bottorff. According to the commission's rules of practice and procedures, the proceeding was closed officially in mid-October of last year. What you're referring to, a letter of submission, maybe an internal process that the judges have and have in place to notify the Chief ALJ when they plan to be able to finish and complete their proposed decisions. But that is just an internal process and it may or may not apply to every proceeding, but there's nothing beyond the existing rules of practice and procedure that identify that or discuss it. So from our perspective, the proceeding was officially closed in mid-October of last year.

If internally, they required it, is it public or is there notice given that a letter of submission was issued?

No.

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

Most of my questions were answered but on Slide 20, question, is there -- on the unrecovered expenses as far as tax deductions, is there any historical precedents where the IRS has not allowed a tax deduction for unrecovered expenses or is the tax code pretty black and white?

This is Kent. It's very fact-specific and so it's not completely black and white. And the issue happens when, in our case, if you had a regulator that essentially put forth unrecovered expenses as the equivalent or in lieu of a fine. And that's where there's some question. Would the IRS look through that and question, is it really just a fine. And that's really where the issue comes up about whether or not it's tax-deductible, and so that's why it's very fact-specific.

Okay. But you're confident enough by assuming the 60% multiplier?

That's our sort of working thought about this. It really is going to ultimately depend on the commission's final decision.

Got you. And then, just on another minor note, on the retail rate structures, is there a status on where you're at as far as changing the rate structure from, I think a 5 tiers to 4 or 3, and where that is at?

Yes. This is Tom Bottorff again. The current schedule calls for the utilities to submit their proposals in compliance with some of the directives called out in AB 327 to be submitted on February 28. So at that point in time, you'll see proposals to probably reduce the number of tiers, change the differentials between the tiers, introduce fixed charges if the utility believes that's appropriate, and other alternatives. So you should see those proposals, again, at the end of this month.

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

Just had a question for Tony. It seems like some of your peers, your utility peers, in California, have been pretty aggressive about reducing O&M to help blunt the impact, the rate impact, to customers. How much room do you think there is to cut O&M at the utility and also at the corporate level and has that not been a focus of yours just given what's been going on with San Bruno?

Oh, it absolutely has been a focus of ours. A lot of what we've done kind of gets masked by all of the San Bruno-related costs. But in my almost 2.5 years there, one of the key drivers that I pushed is a very aggressive, continuous improvement program and we're starting to deliver results in the organization. Our electrical organization has done some terrific work in trying to get costs down so that we eat inflationary costs as they occur. You'll start to see our efficiencies in our gas business have improved. The first year, we were doing our PSEP program, we were really scrambling to get work done. Because we have kind of the commitment to get it done now, we've got a long-range plan. We've got partnerships with a number of different contractors that's bringing our unit costs down. So it's an area that we're intensely focused on. And I think these are programs that take multiple years but we're all starting to see the benefits, and you'll see the benefits going forward in the future.

Our next question comes from the line of Jim von Riesemann with CTR (sic) [CRT] Capital.

Can you -- there's been so many twists and turns in this whole San Bruno proceeding, including like the LA Times article from late December regarding the February PD and this notice of submission, but it might have gotten lost on me what the mechanics are and the process is once that PD is actually released and sort of the timeline from there. Can you refresh our memories on that?

Yes, this is Tom Bottorff. Once the PODs are issued, parties have 30 days to respond, those are called appeals. So every party in the proceeding can file an appeal if they so choose. And then after the end of the 30-day period, parties have 15 days to respond. Once that 45-day period passes, then that decision is up to the commission to issue and there's no specific timeframe on how long they have to issue it. So that's where the timeframe becomes a bit more uncertain.

Is there anything with respect to this 30-day window that could be elongated to, say, either 45 or 60 days. Are these hard and fast rules, or not?

They, historically, have been pretty hard and fast. I can't recall of an example where those have been changed. That doesn't mean they can't be but, typically, those have been pretty much the standard.

So let's just say we're on this 30 plus 15, right, as the response period. What do you think is a reasonable timeframe it's going to take for the commission to opine?

That depends probably on the level of comments and protests that are filed. Again, these are called appeals. But certainly if there are no comments or appeals, the decision can move out very quickly. If there are complicated issues that the commission feels it need to address by modifying the decision, that could take a bit longer. So it's hard to predict right now but it's going to take, at least, a month after the PODs and it's hard to predict how much longer than that.

So thanks, everybody, for joining us. We're out of time. We really appreciate it. I hope you have a nice day.

Thanks.