Good morning, welcome to the PG&E Corporation fourth quarter earnings call. All lines will be muted during the presentation portions of the call, with the opportunity for questions and answers at the end. 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, thanks for joining us. Before you hear from Tony Earley, Christopher 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. With that, I'll hand it over to Tony.
Well, thank you, Sara, 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, our outlook for 2014 and beyond. I'll start off, 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 in the proceedings is closed, 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, 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 center line of all of our gas transmission pipes on schedule by the end of the year. 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. 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. 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 four you can see the progress we made in 2013 to make our pipeline safer. Over the past few years, we've tested or 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 center line 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 four 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 five-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 have responded to the improvement.
Our customer satisfaction survey scores for this year exceeded our goal and reached levels reflecting pre-San Bruno scores. Turning to regulatory matters, I'll spend a few moments on some of the highlights of our three 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 to 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 pipeline 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 first of 2015, even if the final decision comes later. The third rate proceeding is for electric transmission. In January, the FERC approved a settlement in the TO-14 case. With TO-15, we've just begun settlement discussions with the other parties.
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 results of our 2011 customer energy efficiency programs. Finally, last week, the court annulled the CPUC's decision approving the Oakley plant. We're currently working with our counterparty to determine the next steps for re-approaching the regulatory process. 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. Let's start on slide five, 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 pre-tax 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-$450 million.
During the quarter, we recorded $22 million of fines related to natural gas matters. These fines were associated with two 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 six 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 than 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. Higher shares outstanding also had a $0.03 impact. A number of other items totaled $0.07 negative compared to Q4 of last year. 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. 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.
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 investigations, today we won't be providing our traditional guidance for earnings per share from operations for 2014. We are providing some key building blocks for you to develop your estimates. We're also providing some thoughts on 2015 and 2016. Let's start with some of our key assumptions for 2014, which are shown on slide seven. 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, TO-15. 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's 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 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.
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 cap. 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. 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. 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 costs 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 receive 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 eight, you'll see the estimated range for our item impacting comparability for natural gas matters in 2014, which is $350-$450 pre-tax.
This is absent any further impact resulting from the outcome of the gas investigations. There are three components, and 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 and $175 for the year. Again, the primary work here is our extensive hydrostatic testing program. The second component's the work that falls outside the scope of the Pipeline Safety Enhancement Plan. 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 and $225 pre-tax for the year, and that it'll be split fairly evenly between the rights of way and the integrity management and other categories. This year, the rights of way work's going to shift from mostly survey work, as Chris said, to remediation.
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 costs, which we estimate will come in between $25 million and $50 million for the year. As you'd expect with the gas investigations taking longer, some of these costs were pushed from last year into 2014. The bottom is the reminder that these figures exclude future insurance recoveries, which would obviously net against costs, 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 nine, 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've 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. 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. 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. 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 three years. 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 our TO15 electric transmission case. It also reflects our current view of future regulatory requests for electric transmission. 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.
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%-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 plan. 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've put in place strong rate case filings to position us well for the future. I'm confident that we are lining ourselves up for success. Now let me open up the lines, and we'll be ready to answer your questions.
Certainly. We will now allow questions from the phone lines. Ladies and gentlemen, to ask a question, please press star followed by one on your touch tone keypad. If you'd like to remove that question, press star followed by two. If you're using a speakerphone, please pick up the handset before using the keypad. Again, if you'd like to ask a question, press star followed by one. We'll pause here briefly to allow questions to generate in queue. Our first question comes from the line of Brian Chin with Bank of America. You may proceed.
Hi, good morning.
Morning.
Morning.
On slide 18, the Gas Accord V costs changed a little bit since the last set of slides. Could you just talk about that a little bit more?
Brian, this is Kent. 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. You're correct, our total previously was around $2.4, and our updated total is $2.7. 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 newer vintage pipe, which had been an issue that had been already addressed by the California Commission in the PSEP case.
We decided for post- 1961 pipe that we weren't going to file for cost recovery of that testing going forward. That's roughly $25 million a year in 2015, 2016, and 2017 during the rate case period. 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'll continue through 2017, again, the GTNS rate case period. 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. Those are reflected in our 2014 numbers that I went through on the call.
Great. Thank you.
Thank you. Our next question comes on the line of Hugh Wynne with Sanford C. Bernstein. You may proceed.
Hi. I was going to ask a question about the power side. You're 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 state's power system under the circumstances?
Hugh Wynne, this is Chris. 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 2014 isn't off to a great start. 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 that we'll only be able to use our current hydro resources probably during high peak times and some emergency times. The rainfall, our understanding up north is still pretty much close to normal, and we do import a lot of hydropower 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.
We know in our territory, we still look like we're pretty good. Our nuclear facility's running well, and all our other resources are available to us, so we still feel pretty confident about this summer.
Would you expect roughly 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 hydropower available, we may need to utilize some of the gas resources to do that. Like I said, I think we're still pretty good.
Great. Thank you very much.
Thank you. Our next question comes on the line of Jonathan Arnold with Deutsche Bank. You may proceed.
Good morning, guys.
Morning, Jonathan.
Morning, Jonathan.
Just a quick question on what you said about underearning in 2014. I think you said that was because obviously the true-up comes in 2015, so I know it's going to contingent on the rate case outcome, but is there any reason to anticipate continued underearning beyond 2014?
Obviously, all of that depends upon the outcomes of the various rate cases. We feel good about how the general rate case went in. 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 and storage case done as well. Again, the caveat is we need a reasonable result. It is still our objective to, after those cases are done, to be able to earn our allowed return overall for the company.
How do the items that I think were the items you called out on the call last quarter that were also the answer to Brian's question on the numbers on slide 18, how do you anticipate treating those from an 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. No change there. They've been in our operations this year, and they will next year as well.
The $75 million on corrosion and post-1961 pipe, basically.
No, sorry, I was misunderstanding you. For the corrosion and the post-1961 pipe, those, once we get to the GTNS 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.
Oh, okay. Thank you. Then, Kent, you mentioned this comment, you commented when talking about equity, about depreciation. You're assuming current depreciation rates, but you've requested some changes in the GRC that would reduce needs if approved. I guess you're not likely to get a GRC decision on a timely enough basis to change this year. How should we think about that? Any quantification you can put around what that aspect of the ask would do to your equity needs?
Well, if we actually got all the change in depreciation that we requested, it could affect us $200 million in terms of equity needs. That depends on getting the full ask, and I think it'll really depend on where the Commission comes out. Obviously 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. Again, you're right, our guidance assumes no change in our depreciation rates.
Okay. That's it. Thank you.
Hey, Jonathan, last one thing, though, just to be clear on the earning the authorized rate of return on post 2015 does exclude the impact of our center line survey and clearance that we're doing on that. I just want to make sure everybody's clear.
Yeah, that's correct. That tail, as we said, is about $100 million a year through 2015. Excuse me, through 2017, and we know that that's out there for a few more years.
Right. Are you intending that will be an item impacting comparability, or is that something that'll hit your operating earnings?
That is my expectation, that that item we flagged as an item impacting comparability. It'll continue until we complete the project.
Thank you.
Thank you. Our next question comes from the line of Steven Fleishman with Wolfe Research. You may proceed.
Yeah. Hi, good morning. First, on the $0.10 of underearnings in 2013 that continue into 2014, that's all the gas underearnings net of the energy efficiency benefits. It's a net number of all that?
That's correct, Steve. It's all of our operating underearning. 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 till I actually see what plays out, My expectation would be that we're more likely to give guidance once we have both factors resolved.
Okay. 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?
Yeah, Steve, this is one that I know I've been talking with investors about for some time now. We tried 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. We thought this would be helpful. I think everyone's pretty clear that a fine that went to the general fund would not be tax deductible. 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.
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 half 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 non-cash write-off at that point. We just wanted to lay that out because some people were struggling with their equity issuance estimates, and we thought this might be helpful.
Okay. Thank you.
Thank you. Our next question comes from the line of Julien Dumoulin-Smith with UBS. You may proceed.
Hi, good morning.
Good morning.
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?
Yeah, this is Tom Bottorff. We have not yet made the request, but we expect to do so later this month. 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. 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. Then secondly, Oakley, what are next steps there as far as you're concerned?
Yeah, this is Chris. We're working with our counterparty right now to take a look and see how we're going to reapproach the regulatory process. We need to address what the court's ruled was a lack of evidence around the need. 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. Just to be clear, it's not in any of the rate base numbers, et cetera?
That's correct.
No, that's correct.
Great. Excellent. Let me just clarify one last time with regards to the equity needs. 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. This essentially reflects the guidance that I've provided today on our item impacting comparability for gas matters. To the extent there are other disallowed costs, could be fines, could be just disallowed costs, those would be incremental to these equity needs.
Right. Sorry, I should have framed that better, thank you.
Thank you. Our next question comes from the line of Michael Lapides with Goldman Sachs. You may proceed.
Hey, guys. First of all, thinking out past 2015, outside of the $25 million a year, the actually two 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 2016 or beyond timeframe?
Well, this is Kent, I guess I would say what still is a fact not in evidence is just the outcome of the gas transmission and 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 costs and revenues. That's probably the biggest issue that we just don't have a lot of visibility yet to just because the case is early on.
Got it. 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 2013, what was that CWIP balance?
I think it was roughly $1.8 billion. It's been fairly stable over the last year.
Got it. If we think about the $1.8 billion, maybe it grows a little, shrinks a little, in that direction. 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 tax payer or limited cash taxpayer in 2014?
This is Dinyar Mistry, the Controller. Yeah, 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. What happens after 2014? I know bonus depreciation goes away, are there other things that could keep you from being much of a cash taxpayer?
Actually, the NOL impact should carry over into 2015. I'm not sure that it will completely wipe out cash tax payments in 2015, it will have an impact in 2015. Going forward, we're back to normal.
Got it. Thank you guys. Much appreciated.
Thank you. Our next question comes from the line of Michael Goldenberg with Luminus Management. You may proceed.
Good morning.
Morning.
Morning.
Wanted to continue with the CWIP discussion. You said CapEx is higher, but rate base is lower because of timing difference. Does that mean some extra capital will be going into CWIP and at least temporarily increase your AFUDC earnings?
This is Kent Harvey. 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. I'm sure we're not unique in the industry in terms of those projects tend to be somewhat unpredictable timing-wise. That's really the area where there's been the biggest part of that phenomenon. 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. 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.
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?
Oh, sorry. 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. Our concern was that those are expenditures that we're making, obviously they affect our cash flows and everyone needs to understand that. They're not actually going to be in CWIP and go into rate base because of the PSEP cost cap. 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?
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. I think that's a 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. It was only in effect for a limited amount of time during 2013.
Right. Most of 2013, were you embedding a lower transmission ROE?
Yeah, 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. Yeah, we probably came in a little less than we would have liked to have from an authorized perspective.
Understood. Thank you very much.
Thank you. Our next question comes from the line of [Keith Conolich] with BGC Partners. You may proceed.
Good morning.
Morning, Kit.
Morning, Kit.
Kent, just to follow on the guidance to make sure I understood you correctly. 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?
Yeah, I think that's my current working hypothesis.
Right. How much of the uncertainty about 2014 is related to the GT&S case as opposed to those? Presumably you'd give guidance. Obviously, that'll be going on the whole year.
Yeah, that really won't get resolved till we get to the end of 2014 or 2015. I think it'd be unrealistic to expect that to be closed out for us.
Great. On the timeframe for the proceedings, you guys sounded pretty confident that the GRC proposed decision could come out in the first quarter.
I didn't hear any estimate of when the San Bruno proceedings might be concluded or even have a PD. Obviously, they're different proceedings. What gives you the level of confidence there, Tony?
Let me start off, and maybe Tom Bottorff might want to add to it. 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. That's out of our hands. I think we've got to take him at his word that that's the best estimate right now out there, 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, 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. 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 more money, 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?
Look, Kit, this is Chris. 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. 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, to the extension of the cost of capital mechanism, all of those things seem to be reasonable outcomes for us. So we feel pretty good that there's not going to be some overhang. Obviously, that doesn't mean that interveners won't come in and try to make some of those same arguments. We fully expect that they would.
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 upgrading our records, and that will be done and is not included in this new case. The commission also disallowed a lot of our contingency requests in the first case. Obviously now, after three years, we have a lot more insight into the costs. 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. 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. 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.
Great. Thank you.
Thank you. Our next question comes on the line of Anthony Crowdell with Jefferies. You may proceed.
Hey, good morning. 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 or record is still open.
Yeah, 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, may be an internal process that the judges have in place to notify the chief ALJ when they plan to be able to finish and complete their proposed decisions. That is just an internal process, and it may or may not apply to every proceeding. There's nothing beyond the existing rules of practice and procedure that identify that or discuss it. From our perspective, the proceeding was officially closed in mid-October of last year.
If internally they require it, is it public, or is there a notice given that a letter of submission was issued?
No.
Great. Thank you.
Thank you. Our next question comes from the line of Ashar Khan with Visium Asset Management. You may proceed.
My questions have been answered. Thank you so much.
Thank you. Next question comes from the line of Shar Parekh with Citigroup. You may proceed.
Good morning.
Morning.
Most of my questions were answered, on slide 20, question, on the unrecovered expenses as far as tax deductions, is there any historical precedence 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. It's not completely black and white. 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. That's where there's some question, would the IRS look through that and question, is it really just a fine? That's really where the issue comes up about whether or not it's tax deductible. 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. 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 5 tiers to 4 or 3 and where that is at?
Yeah, this is Tom Bottorff again. The current schedule calls for the utilities to submit their proposals and compliance with some of the directives called out in AB 327 to be submitted on February 28th. 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 utilities believe that's appropriate, and other alternatives. You should see those proposals again at the end of this month.
Okay, terrific. Thanks a lot.
Thank you. Our next question comes from the line of John Cohen with ISI Group. You may proceed.
Thanks. Good morning. Just had a question for Tony. It seems like some of your utility peers in California have been pretty aggressive about reducing O&M to help blunt 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? 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 the San Bruno related costs. In my almost two and a half years there now, one of the key drivers that were pushed is a very aggressive continuous improvement program. We're starting to deliver results in the organization. Our electric 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 that 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 had 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 cost down.
It's an area that we're intensely focused on, and I think these are programs that take multiple years, but we're starting to see the benefits, and you'll see the benefits going forward in the future.
Okay, great. Thank you.
John, we have time for one more call. One more question.
Thank you. Our next question comes on the line of James von Riesemann with CRT Capital. You may proceed.
Good morning, everyone.
Morning.
Morning, Jim.
There's been so many twists and turns in this whole San Bruno proceeding, including the Los Angeles Times article from late December regarding the February PD and this notice of submission. It might have gotten lost on me what the mechanics are and the processes 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. Every party in the proceeding can file an appeal if they so choose. After the end of the 30-day period, parties have 15 days to respond. Once that 45-day period passes, the decision is up to the Commission to issue. There's no specific timeframe on how long they have to issue it. 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, typically, those have been pretty much the standard.
Let's just say we're on this 30 plus 15, right, 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 or protests that are filed. Again, these are called appeals, 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 needs to address by modifying the decision, that could take a bit longer. 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.
Great. Thank you.
Thanks everybody for joining us. We're out of time. We really appreciate it. I hope you have a nice day.