PG&E Corp (PCG) 2015 Q4 法說會逐字稿

Good afternoon and welcome to the PG&E 2015 fourth-quarter earnings call.

(Operator Instructions)

At this time I'd like to turn it over to our host, Janet Loduca. Thank you and enjoy your conference. You may proceed.

Thank you, Matt. And thanks to those of you on the phone for joining us.

Before I turn it over to Tony Earley I want to remind you that our discussion today will include forward-looking statements about our outlook for future financial results, which is based on assumptions, forecasts, 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 slides deck. We also encourage you to view the 2015 Annual Report that will be filed with the SEC later today and the discussion of risk factors that appears there.

With that, I will hand it over to Tony.

Thank you, Janet. Hello, everyone. Thanks for joining us today. 2015 was a really strong year for us, both operationally and financially. We continue to improve the safety and reliability of our gas and electric systems, while delivering really solid financial results.

Our earnings from operations in 2015 were $3.12 a share, which is slightly ahead of our guidance range. I'm going to spend a few minutes reviewing the operational and regulatory progress we've made and then I'm going to turn it over to Jason Wells to review our financial results in more detail.

We continue to believe that focusing on three key areas: positioning the Company for a clean energy economy; delivering on customer expectations; and addressing outstanding issues, will provide the foundation for operational and financial success. So, let me start with how we're positioning the Company for a clean energy economy.

PG&E continues to be a recognized leader in supporting the nation's goals around clean energy. In December several PG&E team members and I joined Governor Brown for the Global Climate Summit in Paris. We participated in a number of events and panels where we shared the actions PG&E and California are taking to reduce carbon emissions, advance clean energy technologies, and spur economic growth. We were very proud to represent the California utility perspective at such a significant global forum.

In 2015 nearly 30% of PG&E's electric deliveries came from qualifying renewable resources. And even more meaningfully, nearly 60% of the energy that we delivered was carbon free.

We know that as our energy mix continues to evolve so do the needs of our electric grid. To deliver on California's low carbon future we need to continue investing in a smarter, more resilient grid. And we need to ensure that rate structures are keeping up with these changes.

Although we didn't make as much progress on rate reform last year as we would've liked, the Commission has started to address the issue through flattening our residential tiers and moving toward mandatory time-of-use rates. And they've committed to review the rate structure again in 2019. We look forward to continuing to work with all the parties to develop the appropriate rate structure to meet our customers' changing needs.

Turning to customer expectations, on the electric side of the business, last year we delivered a seventh straight year of improved electric reliability. Our outage duration and frequency are now in the second quartile for the industry. We also delivered first-quartile performance in both our 911 emergency response and our wire-down metrics.

On the gas side of the business, we delivered top-decile emergency response performance, and broke ground on a new state-of-the-art gas training facility, which we expect to open in 2017. We were also the first Company in the United States to be certified in meeting the American Petroleum Institute's recommended practice 1173, which is a new standard related to pipeline safety and safety culture. We now have three external certifications recognizing the quality of our gas asset management and safety culture programs.

We also continue to make progress towards resolving our outstanding issues. I'm pleased to report that we've closed out another one of the NTSB's recommendations by installing more than 200 automated and remote shutoff valves across our gas transmission system. And we are well on the way to completing the final recommendation to strength test nearly 1,000 miles of transmission pipe.

In an important step forward, the Commission has officially closed out the San Bruno investigation. We've also completed hearings in the gas distribution record-keeping investigation, and look forward to resolution of that case this year. In the criminal proceeding, we received some positive rulings from the court late last year that narrowed the scope of the case. Most significantly, the court dismissed the government's Alternative Fines Act claim based on alleged losses. The court is still considering whether to allow the government to proceed with an Alternative Fines Act claim based on alleged gains. That determination will be made after the first phase of the trial where the government will have prove that PG&E employees knowingly and willfully violated the law. We continue to believe that the evidence just does not support the charges.

So, to sum up, we had a really strong year in 2015 and we're committed to making additional progress in 2016. Before I turn it over to Jason I want to reconfirm that we expect to address the dividend in 2016. I'm committed to doing that this year, although I don't have any specifics on timing for you yet.

I'm excited to continue to work with Jason in his new role as CFO. He has been working closely with our finance and operational teams for a number of years so he knows the Company extremely well. And he provides a wealth of experience and will be instrumental in helping us move forward.

Jason, welcome and let me hand it over to you to discuss our financials.

Thank you, Tony. Hello, everyone. I've enjoyed meeting many of you already and I look forward to meeting more of you this spring. I will begin my remarks today by going through our Q4 and full-year 2015 results and then I'll provide some insights regarding our 2016 outlook.

Slide 5 shows our 2015 results for Q4 and the full year. We had solid results in 2015, coming in slightly above our guidance range for the year due to some smaller positive miscellaneous items.

Earnings from operations came in at $0.50 for the quarter and $3.12 for the year. GAAP earnings, including the items impacting comparability, are also shown here. All items impacting comparability came in within our guidance ranges.

Pipeline-related expenses came in at $39 million pretax for the quarter and $103 million pretax for the year. Our legal and regulatory-related expenses were $14 million pretax for the quarter and $58 million pretax for the year. Fines and penalties were $137 million pretax for the quarter and $907 million pretax for the year.

The Q4 amount represents our estimate of the disallowed capital work coming out of the final San Bruno penalty decision, which we are accruing as we complete that work. Finally, our annual results show insurance recoveries of $49 million pretax. As we mentioned last quarter, we have now resolved all insurance claims related to San Bruno, recovering a total of $515 million.

Slide 6 shows our quarter-over-quarter comparison from earnings from operations of $0.53 in Q4 last year and $0.50 in Q4 this year. You have seen most of these drivers in previous quarters so I will cover them briefly. The biggest item, a decrease of $0.10, is associated with lower cost recovery in 2015 because we did not receive a decision in the gas transmission rate case during the year. So, we incurred those expenses but did not collect the associated revenues.

Next, a nuclear refueling outage in the fourth quarter drove a $0.05 decrease over the same period last year. There was a penny for regulatory and legal matters and $0.02 negative resulting from additional shares quarter over quarter.

These negative drivers were partially offset by three positive items. First, we had $0.05 of rate growth in rate-based earnings. Second, timing of taxes was also a small positive for the quarter, and for the full year, as we have said, this item nets to zero. And, finally, we had $0.09 of smaller miscellaneous items for the full year as [refined netted] to $0.02 positive. More detail around the annual results is available in the appendix of today's slide deck.

Moving to slide 7, today we are introducing guidance for 2016 earnings from operations of $3.65 to $3.85 per share. We are also providing ranges for items impacting comparability, which I will come back to in a minute.

First I want to cover the assumptions behind the guidance on slide 8. Starting in the upper left corner, you'll see we are assuming capital expenditures of roughly $5.6 billion this year. The breakdown by line of business is also included. Importantly, the gas transmission line assumes a range of $500 million to $700 million for the year. And, as you know, we are still waiting on a proposed decision in that rate case. This range includes about $300 million of safety-related capital expenditures that we estimate will be disallowed as part of the CPUC's penalty decision last year.

In the upper right of the slide you'll see that our estimate of weighted average authorized rate base is about $32.6 billion for the year. Both the CapEx and rate-based assumptions are consistent with ranges we've previously provided.

In the lower left you'll see that we continue to assume a CPUC authorized equity ratio of 52% and a return on equity of 10.4%, which we now have certainty on through 2017. Finally, at the bottom right we list some other factors we believe will affect 2016 earnings from operations. Our objective is to earn the authorized return on rate base for the enterprise as a whole plus the net impact of the factors listed here.

Many of these probably look familiar to you from 2015 so I will cover them briefly. In terms of the gas transmission rate case, the first bullet highlights a key assumption underlying our guidance, which is that will receive a reasonable outcome in the case this year.

The second bullet is a reminder that we haven't sought cost recovery for certain corrosion control and strength testing work in the gas transmission rate case. We previously indicated these operating expenses should average a total of roughly $50 million annually over the three-year rate case period, although the amount may vary year to year.

Next is the tax benefits associated with repairs [reduction]. The net impact of this continues to be roughly $0.25 per share in 2016. The last item is incentive revenues for things like our customer energy efficiency programs. Finally, we continue to expect earnings on construction work in progress to be roughly offset by our below-the-line costs, which include advertising, charitable contributions, some environmental costs and other items.

One more point before I move to the next slide, since we do not yet have a proposed decision in the gas transmission rate case, we do not expect a final to decision until at least the second quarter. So, while the timing should not affect our annual earnings from operations in 2016, it will continue to have an impact on our cash flows and quarterly results, as you saw last year. In 2015 that impact was roughly $0.60.

Turning to slide 9, the guidance for the items impacting comparability is $565 million to $665 million pretax. You can see that most of these categories are consistent with last year. Pipeline-related expenses, legal and regulatory-related expenses, and fines and penalties.

We will also have a new positive category relating to the 2015 portion of revenues from the gas transmission rate case. We expect a final decision in the case this year with revenues retroactive to January 2015. Since we will be booking two years worth of revenues in 2016, we will pull out the 2015 portion as an item impacting comparability once we get that final decision.

The estimated range for pipeline-related expenses is $100 million to $150 million pretax. This component relates to clearing our pipeline rights of way. We're entering the fourth year of that program, which we've estimated will not exceed $500 million from its start in 2013 through its planned completion in 2017.

The second component is legal and regulatory-related expenses, which we estimate to be between $25 million and $75 million pretax for the year. This component represents costs incurred in connection with enforcement, regulatory and litigation activities regarding natural gas matters and regulatory communication. The third component is potential fines and penalties, again related to natural gas matters or regulatory communications.

As you can see in the table at the bottom of the page, our 2016 guidance of $440 million pretax for fines and penalties reflects our estimate of the remaining portion of the $850 million of safety-related spending that the Commission disallowed as part of the San Bruno penalty decision last year. This range does not include any other potential fines or penalties. And, last, we have the new positive item for 2015 gas transition revenues, which we will update after we receive a decision in that case.

Turning to slide 10, we assumed equity issuance of $600 million to $800 million in 2016. That compares to equity issuance last year of right about $800 million. The 2016 range reflects a number of assumptions including the timing and amount of revenues we will receive in the gas transmission rate case.

Moving to slides 11 and 12, we are providing updated CapEx and rate-base ranges through 2019. First, on slide 11, as I mentioned earlier, we are estimating about $5.6 billion in CapEx in 2016. This is a little higher than the $5.4 billion we spent in 2015. As you will recall we had to defer some of our planned work last year due to wildfire response.

For 2017 through 2019 the $6.5 billion high end of the range is the same as you saw last quarter. As a reminder, the high end reflects the full request in our pending rate cases, which are the 2017 through 2019 general rate case, the 2015 through 2017 gas transmission rate case, and the electric transmission TO17 rate case.

For the outer years of the gas and electric transmission rate cases where we have not yet filed a request, we've kept the high end of the range flat with our current request. At the low end of the range we simply assumed that capital expenditures through 2019 stay flat with 2015 spending of $5.4 billion.

Slide 12 shows our estimated rate base levels from 2016 through 2019. Next week we will formally update our 2017 general rate case forecast to reflect the impact of the recent five-year extension of bonus depreciation. The ranges shown here incorporate that update.

Before I go into the numbers, I want to briefly discuss the impact of bonus depreciation on rate base and earnings per share. While bonus depreciation results in higher deferred taxes, which lowers rate base, it also reduces our equity needs. So, while bonus depreciation has a noticeable impact on rate base, it has a small impact on earnings per share because of the lower equity needs.

In 2016 bonus depreciation will not impact rate base because we're already in a net operating loss position through the end of the year. In fact, we now expect to be in an NOL at the enterprise level through 2019. However, we are also required to perform separate NOL calculations for each our rate cases.

As you know, we've had significant unrecovered costs in our gas transmission business which has contributed to the enterprise-level NOL. But when we look at the lines of business covered by our general rate cases, which are our electric and gas distribution and electric generation businesses, we do not expect to be in an NOL position beyond 2016. As a result, bonus depreciation will impact our rate-base request in the GRC beginning in 2017.

The cumulative impact of bonus depreciation in 2019 is a rate-base reduction of approximately $1 billion at the low end of the range and about $1.5 billion at the high end of the range compared to the guidance we provided in Q3. There's a smaller impact in 2017 and 2018. The majority of that relates to the 2017 through 2019 general rate case. A smaller amount of that reduction relates to the electric transmission assets which are covered by our FERC transmission owner rate case.

The result is rate-based growth at a compound annual growth rate of 5% to 7% from 2017 through 2019. And, again, because bonus depreciation also reduces our equity needs, that mitigates the impact on future earnings per share.

To help you with this we're providing a simple rule of thumb to estimate the net impact on earnings per share from both the reduction in authorized rate base and the lower equity needs. On the margin, a $500 million reduction in authorized rate base equates to roughly $0.02 in earnings per share.

One last note on CapEx and rate base before I open it up for questions. Remember that the high end of our CapEx range reflects only our currently filed rate cases, so there is some potential upside as we file future rate cases.

Let me close by saying that happy to be in the CFO role and I look forward to working with all of you. This is an exciting time for PG&E as we continue to see strong growth driven by California's policies and our focus on enhancing safety and reliability.

With that, let's open up the lines for questions.

(Operator Instructions)

Dan Eggers, Credit Suisse.

Good morning. Jason, just going back into this bonus depreciation discussion a little bit, you guys will adjust the rate base, as the slides show, for the treatment at the utility level but you will not be able to recover the cash until you get out of your NOL position at the corporate level?

Good morning, Dan. Yes, that is a fair assumption.

So, how do you get net cash in to avoid the equity issuance if you're not going to be able to generate more cash in this interim three-year rate planning cycle?

It's already factored in in the guidance that we've provided. The impact is really small in 2017 and 2019, so it's really the 2019 period to concentrate on.

When you would actually start getting more bonus cash or perpetuate the cash tax position.

That is correct.

Okay. So, the equity issuance, the $600 million baseline, the blue bar in the slides for 2016, and then you have the shaded area for contingencies, does that $600 million become the ongoing run rate number, is your expectation in this guidance, or does that number come down?

We're not giving longer-term equity guidance beyond 2016. But what I will point to is the two main drivers of our equity needs. And that really has been our strong CapEx profile, which we've given you ranges where you can make your own assumptions. The second driver has been our need to finance our unrecovered costs. One of the biggest drivers in 2016 for the unrecovered cost is financing the remainder of the San Bruno penalty decision, which will be completed here in 2016.

In the past what we have said, and as a quick reminder, we've talked about the fact that our gas transmission right-of-way program will extend into 2017. That was a five-year program that we said will not exceed $500 million and will end in 2017. We've also said we're not seeking approximately $50 million a year in certain costs as part of the gas transmission rate case, so that will extend into 2017. You'll need to make your assumptions around the unrecovered factors, but that is what I would principally concentrate on as the drivers for our longer-term equity needs.

Okay. Tony, I know the Board is going to consider the dividend as normal course, but what factors do you think you and the Board are looking at to help find a place where you're going to be comfortable to address the dividend, things we can follow along to think this will check off some boxes to get more comfortable?

Dan, I think there are a couple of things to think about. One is, we don't want this to be a one-off decision. So, we want to make sure it is sustainable.

Second, as you look at the changes that are going on in the utility business, we don't want to look backward at what historical payouts have been but we want to try and figure out what ranges are companies going to use in the future, and we will be looking to then get ourselves in a comparable range. So, we're trying to figure that out.

And then the third thing on timing is, obviously we still have a lot of things going on and we want to make sure that we don't make the change at a time that would not be appropriate, given all the things that are going on. I think they are looking at all those things. I think the principal thing is making sure that our decision is sustainable.

Tony, just on that payout ratio, it seems like the industry has dropped the payout ratio over the last 5 to 10 years. Is that suggestion that you think the current level is where dividends should be? Or are you going more to the camp of, say, Duke today who talked about payout ratio structurally higher than that 60% level?

I think you're right. The payout ratios have come down. Years ago when I started in the business 80% was considered where you ought to be. That obviously has come down. So, we want to try and anticipate where things are going to be and what is appropriate.

We will be trying to sort that out. Our Board has asked for a number of different analyses. But clearly we want to get ourselves to where we're comparable with some of our fellow utilities that are out there.

Okay, got it. Thank you.

Michael Weinstein, UBS.

Good morning. I was wondering if you could comment a little bit more about the impact of the distribution rate plan, DRP plan, on possible increasing the CapEx forecast going forward and offsetting some of that bonus depreciation impact. As well, just wondering how much spending are you planning on doing under the rider that you currently have between rate cases?

A couple of questions there. As it relates to the DRP I wouldn't necessarily look to that as a separate source of incremental capital. As we've said in the past, our plans around modernizing our electric grid are incorporated in that 2017 through 2019 rate case and are reflected already in the CapEx that we filed.

As it relates to the mechanism, something to consider there, that regulatory mechanism, which we call TAMA, has really allowed us to spend additional capital previously to offset the extension of bonus. That was really intended to address situations where the extension occurred after a rate case decision, not when it's extended before the decision, as it is in this case. So, that mechanism is not necessarily analogous to the situation we have here.

Got you. And another question about time of use rates, and the recent approval of net metering rules. Just wondering, is it possible that the time of use rates might actually make net metering less valuable to the solar players in your jurisdiction? I'm just wondering what you think the impact of time of use might have on solar growth in your jurisdiction.

Hi, this is Steve Malnight from Regulatory Affairs. Let me comment quickly on that. There are several components of what we feel the rate structures need to move towards in the future, and time of use rates is one of them. So, we were pleased to see in the NEM decision that we will be moving solar customers to time of use rates.

It's not the silver bullet that solves all the problems. In total that NEM decision, we feel, didn't really go far enough in addressing the issues that are caused by subsidization that happens with a NEM rate. But we will continue to look at that decision.

The Commission did decide that they will be revisiting it in 2019. And I would just remind you between now and 2019 we have a lot of changes that are happening in base rates in California with collapsing of the tiers and with the potential to move customers, all customers, to time of use rate. So, we will look forward to that conversation in 2019, as well.

All right. Thank you very much.

Hugh Wynne, Bernstein.

Thank you for taking the question. Just going to page 6 and the quarter-over-quarter comparison, the miscellaneous items this year, this quarter of $0.09 are equivalent to almost 20% of the Q4 earnings. Just wondered if you could give us a little more clarity as to what the bigger items are in that.

Sure, thanks, Hugh. Just as a quick reminder, for the year miscellaneous items is roughly about $0.02. What I will say is, miscellaneous items generally have a number of factors, both timing and non timing related.

A couple of the things that have driven the Q4 results were higher gas transmission revenues as a result of the colder weather we experienced in the fourth quarter, as well as we experienced some favorable settlement and employee benefit costs during that quarter, which are reflected in those numbers. But, again, these are really timing items and over the course of the year they netted out to a small amount.

Great. And then on the item on the right, the $0.10 GT&S cost recovery item, those are basically increased GT&S costs that you've not been able to recover due to the delay in any revenue increase being granted in the case. There's nothing in that number for rate base growth and return on equity associated with your request in the case, right? That is excluded here.

That is correct. That $0.10 really relates to our operating expenses for which we are not receiving a recovery through the GT&S rate case because of the delay in the decision. But the full impact on a quarter basis is roughly $0.15 when you include the lack of return on rate base depreciation, et cetera. As I mentioned, it's a total of roughly $0.60 for the full year, is the full impact of not having the GT&S decision.

$0.50 including the rate base growth and return on equity.

$0.15 for the quarter, includes both the unrecovered cost, of which that's $0.10, and then $0.05 is roughly the impact of the lack of the rate base return.

Okay. And your number for the year of five-zero? Is that right, or did I miss you?

I'm sorry, six-zero - $0.60.

And that's including both, as well.

That's right.

Okay. And then, Tony, I wonder if I could just ask you for a quick update on where we stand in the distribution safety records case, what we should be anticipating there, what downside risks there might be. And, to the extent that there is any new information that is worth bringing out on the federal indictment or the investigation into the bush fire, I would appreciate that, as well.

Okay we will walk through those. And I may hand off some of them for some more detail. The distribution records cases, it's in process. There's been testimony given in the case. We've got a consultant's report. And in a minute I'll let Steve Malnight just comment on exactly where that is.

With respect to the criminal case, the trial has been pushed back to the end of March. We continue to believe that there is no basis to conclude that any PG&E employee willfully violated the Pipeline Safety Act, and we are proceeding on that basis. Obviously when it goes to trial there's going to be negative publicity but we still firmly believe that we've got a solid case there going forward. And then you had one other case.

The bush fire.

Oh, the bush fire. Let me ask Geisha to comment on that.

Hi, Hugh, this is Geisha. As we've previously reported, that CAL FIRE is investigating whether in fact a live tree made contact with some of our power lines in the vicinity and near the ignition point. It is a very detailed investigation. It's continuing. We haven't heard anything additional, so we really don't have any further updates at this point. Obviously cooperating with them, providing them lots of information. We are hopeful that we will hear something soon but our experience shows that this could take a while.

Okay. And then just a quick follow up on that. Tony, remind us of the maximum amount of the penalty that the government could now seek on the federal indictment. And if you have any similar guidance on the safety distribution records case, I'd appreciate that.

Let me let Hyun Park comment on where we are now on the penalty.

Hi, Hugh. The court issued an order late last year basically eliminating the loss-based Alternative Fines Act allocation. It could have been up to $1.13 billion and that fine possibility has now been eliminated.

The other question that is under consideration right now is whether or not the Alternative Fines Act allegations based on gross gains can be admitted. And the court just recently deferred decision on that and basically said that the court wants to see how the case comes in. If the company is convicted, and if the alternative gains evidence is not going to unduly complicate the trial, then the court will bifurcate the trial and consider that as a second case.

What's the max there?

That is $562 million. That is what has been deferred. But you have to also recall that the court dismissed 15 counts, so we are now down to 13 counts. And if you don't have the Alternative Fines Act allegations that come in, and the government doesn't prevail on that, then each count has a fine of $500,000. So, 13 counts would amount to $6.5 million.

Great. And any similar guidance on the safety records case, or is that not possible?

Let me let Steve comment on the safety records case.

On the distribution records OII -- this is Steve Malnight again -- as Tony said, we concluded the hearings in January. I think we had a good and successful hearings in that case. So, the case is now concluded.

I would just highlight a few things. I think it's worth noting that, even in SED's testimony they acknowledged that PG&E has made a lot of improvements in our distribution record-keeping, and commended us for some extensive use of internal and external audits.

And we had the opportunity through the hearings to really comment about a number of the industry best practices that we've been implementing, including our multi-year efforts to consolidate and digitize gas distribution records, providing crews in the field with additional tools, including electronic maps and tablets, and really multiple layers of safety protections in place when we do work in the field. So, we thought that getting those things out was a successful conclusion to that case.

The next steps, just to highlight for you, next week we expect parties to file. They will be filing open briefs next week, including SED, so we will see what that says. And just the last reminder is that we already were fined for the Carmel incident so we'll see what comes out after, that remains.

Carmel with how big?

That fine was $10.8 million.

Thank you for your time. I appreciate it very much.

Chris Turnure, JPMorgan.

I just wanted to follow up on the criminal trial question. Maybe you guys could elaborate on the timing there and the different scenarios of what could play out. Are you saying that the gross gains fine could potentially be thrown out by the judge? Or is it just best case scenario there would be together with the current trial as opposed to separated out into a separate proceeding? And in all those cases what would we look at in terms of changes to the calendar?

This is Hyun Park again. The court has not decided whether to admit the gross gains evidence. That is still under consideration. The trial is scheduled to start on March 22. And barring any further continuance, the parties have submitted an estimate, and the estimate that has been submitted is that it may take approximately six weeks -- four weeks for the prosecution and two weeks for the defense. But that's, I think, a very rough estimate at this point.

This is Tony. One other thing on the issue around the alternative fines, because it's a criminal case it has to be proven beyond a reasonable doubt. And I have trouble figuring out how there would be any gains shown. In fact, the Company sustained huge losses as a result of that. The suggestion that they are going to be able to prove beyond a reasonable doubt that the company had $500 million in gains resulting from San Bruno is hard for me to understand.

Okay. And they could still throw out the idea that there was $550 million of gains but still prove you guys guilty of having a deliberate attempt to thwart the law to achieve gains.

They have to prove that first. That's the first step, is that they would have to prove that there was a willful and deliberate violation of the law, that somebody decided -- I know what the law is but I'm just going to violate it any way. And then you don't even get to the alternative gains consideration unless you get that. And then they would have to prove beyond a reasonable doubt that the number was the number, whatever number they want to push.

Okay, got you. And then what would be the potential final jury decision point here in terms of when that would occur? And then is there still a chance at this point in the process for a settlement to occur?

Let me comment on the settlement. We are always open to a settlement if someone wants to make an offer. We have made efforts in the past that have not gone anywhere. We would be open to it Hyun, why don't you comment on the timing.

I gave you the current estimate of how long the trial might take. And then, of course, it's a question of how long it takes for the jury to deliberate and reach a decision. I can't tell you how long that will take.

But given a late March start, you'd be looking at some time in probably the May time frame.

Okay. And then my second question relates the GT&S ALJ decision and final decision, whenever that may finally come here. Is there a way that we can think about different buckets of CapEx that you have requested here? And any color into how those could come out in terms of approval or disapproval? And just how to think about the various scenarios of the outcome here, even though you probably wouldn't want to forecast what actually happens.

I really think it's probably premature to forecast what the decision will look like before we have it in hand. What it will say, though, is that capital expenditures forecast for the year that we've included, the $700 million reflects what we filed in that case. So, you'll have to make your own assumptions around where that case will ultimately end up.

Okay, great. Thanks.

Michael Goldenberg, Luminous Management.

Good morning. I wanted to understand better the issue of bonus depreciation. I understand mathematically how it works but I also do know that you have a mechanism that you currently have that you can reapply for. Does this take that, the announcement that you put forward take into consideration the fact that you may again get this mechanism and reinvest the CapEx and you just don't have somewhere to invest it, or are you just assuming you're not going to get it, or are you being conservative and just not incorporating it in?

The ranges we provided do not reflect any incremental capital from that mechanism we've had in the past. I really think it's important to point out that regulatory mechanism, which has allowed us to spend that additional capital when bonus was extended in the past, it was really intended to address those situations where that extension occurred after we received a rate case decision. In this case, bonus was extended before we have a decision so it's not necessarily applicable in this case.

Are you not going to apply for it?

We have requested the extension of that mechanism as part of our original 2017 GRC filing. But, again, it really is intended to address situations where bonus was extended after we received a decision in the case.

So, are you saying you're unlikely to get the treatment again?

I would say that is a fair assumption. It could be extended but since bonus has already been extended for five years, I think that's a fair assumption.

And if you were to get it how would the numbers change?

I really don't think the numbers change in this case.

I got you. Thank you.

What it will point out, though, in the comment that I made, the high end of our ranges reflect what we've currently filed in our rate cases. Just as a quick reminder, over this 2016 through 2019 period our currently filed rate case for our electric transmission assets is only through 2016. So, we will have to file an annual case for 2017, 2018 and 2019.

As well, our GT&S case only covers up to 2017 so we will file an additional rate case covering the period of 2018 and 2019. There is the opportunity where we may spend additional capital or request additional capital in those rate cases that are not reflected in these ranges here.

Okay.

Praful Mehta, Citigroup.

A quick question on slide 12 where you talk about your updated rate base. It seems like, effectively, because you are mitigating the need to issue equity or reducing the need to issue equity, in your base case plan there was equity need literally in each of the years of 2017, 2018, 2019. Is that fair? And, secondly, is it possible that due to bonus now you probably don't need any equity in any one of those areas? How should we think about that?

What I will come back to is the two main drivers of our equity needs have really been our CapEx program. So, we've provided ranges here. You're going to have to make your assumptions about where we fall out in that range and what that incremental equity will be needed to fund those levels.

The other driver of our equity needs, as I've mentioned before, is our unrecovered costs. As I mentioned, the majority of the unrecovered costs that are driving our equity needs in 2016 really relate to the financing of the remaining penalty for the San Bruno penalty decision. We will complete the financing of that penalty this year in 2016. So, you can make your assumption about what those unrecovered costs will be post 2016.

Got you. And then, secondly, from a retail rate perspective, as bonus depreciation reverses over time and rate base grows, is there any concern that there is a concern for retail rates going up in the 2019 timeframe and what that means for pushback in terms of further CapEx spend?

We're constantly focused on affordability of our service. But there's a number of factors that are going to play out over the period of time with which bonus depreciation reverses. So, I don't think we can isolate that today as a driver or concern about our rate levels.

Okay, great. Thanks, guys.

Paul Patterson, Glenrock.

Good morning. Just a few quick ones. The community choice aggregation and net metering issues, are those resolved now one way or the other? Or do you expect further actions in those areas?

As Steve Malnight mentioned earlier, net energy metering is not fully resolved. The Commission issued a decision in what we call net energy metering 2.0, but in 2019 they're going to take the issue up again. There is still this issue of cross subsidization. We think there's still work to do to get the rate structure right so we don't have one group of customers subsidizing another. And we are going to be continuing to work with not only the Commission but all the parties on this. So, more to come on net energy metering. That is something we are going to be working on.

The other part -- CCAs, that gives local communities the right to aggregate. Now, they are still PG&E customers. We deliver the energy to the customer. The energy costs are a pass-through, so we don't make money or lose money on CCAs. One of the frustrations that we have is we want to make sure that customers understand what they're getting when they go to a CCA. We want to make sure that, from a cost standpoint and a clean energy standpoint, we are very competitive, and we think we are. But in the end right now it does not have an impact on our bottom line.

Theoretically net metering wouldn't either, right?

Yes, net metering doesn't hurt us. It hurts our customers, or certain class of customers.

Right. I was just wondering if community choice aggregation -- I think the Commission acted on this, or at least one of the issues related to this, whether or not that cost shifting is an issue similar to net metering or if that's been resolved. Do you follow what I'm saying?

This is Steve Malnight again. I think you're referring to the PCIA proceeding that occurred last year in our [ERA] case. And the Commission, they finalized the ERA case in December and that sets our rates for this year.

They did announce they're going to have a workshop to look at the PCIA methodology going forward. It's a very complex methodology by which we calculate what are the costs that when customers leave, bundled customers have already procured on their behalf. As a part of the CCA mechanism, they retain those costs when they go to CCA service.

We will have a workshop on that here coming up very shortly, actually. And we'll continue to work through that during the year. But there's not another formal proceeding that has been opened on that.

Okay. And then, as you're well aware, there is all this effort for CPUC reform. We've had legislation that's passed unanimously, was vetoed last year, and it looks like it is again showing up, I think, just recently, similar legislation. And apparently they don't override vetoes with the governor but there are ballot initiative efforts, et cetera. Just if you could comment a little bit on that, what opportunities or risks you see with these rather -- I don't know, it just seems that there is a big push legislatively, obviously, to pass it unanimously for some form of reform, and how we should think about that and how you guys are handling it.

In California there are always lots of pieces of legislation and it's hard to handicap which ones are going to make it through the process and which ones aren't. And, quite honestly, we have stayed out of that issue. However the State wants to structure the CPUC, we will work with it.

The bottom line, though, from a regulatory standpoint in California, we still have really good regulatory structures in place. And there's nothing that leads any of us to believe that the fundamental positive regulatory structures that we have in California is going to change.

Okay. So these efforts and what have you, it's a lot of noise but you don't see that as a threat or risk to any potential change in that good constructive regulatory environment that you have. I don't mean to put words in your mouth but am I understanding it correctly?

Yes. We think from the utility standpoint, we will work within whatever regulatory structure. And a lot of the proposals are around governance at the CPUC. But no one is proposing we change some of these very positive structures and the trends that we've had, such as going to clean energy, which means we've got to modernize and make the grid more flexible, which means we've got a lot of investments which is driving our capital needs.

Okay, fair enough. And then, just finally, on the criminal case, I'm a little bit confused. It seems like they are asking or they are seeking -- the way you described it is that they are asking for a finding of willful deliberate deceit. And I would assume that would be on the part of individuals. But it doesn't seem like they're charging any individuals. They're charging the Company as a whole, if I understand it correctly.

Is that unusual to be saying -- hey, we are making a charge that there was a deliberate attempt to do something, but not actually charging individuals with it? I'm just a little bit confused about how that works. Is that typical in these cases? I just don't know.

That is something that we've obviously been pointing out to the court. The requirement is knowing and willful violation of the Pipeline Safety Act regulations. And there's also an obstruction charge, as well. There is a theory out there called collective knowledge and we believe that is what the government is looking to.

But, as you know, corporations are entities, and corporations as legal entities don't commit actions. It's the individuals. These are issues that are very much at play and they're before the court right now.

Okay, thanks so much.

Anthony Crowdell with Jefferies.

Good morning. Quickly, earlier in the San Bruno proceedings you had reserved some funds for the State fine. Have you reserved any funds for the potential of a federal fine?

We have not.

Okay. And also I wanted to follow-up on Mike Goldenberg's question just on bonus. And if I follow it correctly and understand it, it lowers rate base. Is there an appetite with intervenors or the regulators for maybe the Company to spend more than it historically has, because customers -- there's some type of shield -- it minimizes the rate impact with bonus there. Is there any appetite for that with intervenors or the regulators?

I want to continue to emphasize that TAMA account, or that regulatory mechanism that we had to increase our capital expenditures in the past really isn't applicable in this case for the extension of bonus. What I would really concentrate on is the potential opportunity for additional spending in our transmission rate cases, which we will file over the next couple of years.

No, I follow that mechanism is not going to be -- it doesn't really work here. But when you make those filings, do you get a feeling with intervenors now that they would be willing to maybe spend more on CapEx because of bonus?

We haven't picked up that any of them are demanding we spend more money right now. And to just reiterate what Jason said, in these later cases that we file we're going to be evaluating what our needs are, and that will then be the subject of a hearing. But no one is out there saying, that I've heard, has said yes, because of bonus depreciation being extended you guys ought to be spending more money.

Great. Thanks for taking my questions.

Travis Miller, Morningstar.

Thanks. I want to go back on the GT&S. I think I heard you correctly that there's $0.60 cash benefit that you expect in 2016, obviously pending that decision. If that is correct and I heard you correctly, how much of that is going into that equity reduction bucket? And then how much would go to other uses, perhaps reducing short-term debt or whatever financing you took out last year?

I want to clarify that $0.60. That really is the full impact of not having a rate case decision. The placeholder that we put in terms of a driver of our equity needs, there are a number of assumptions that are going to go into that. It includes things like what are the overall level of revenues that are going to be authorized in that case, the timing of the decision, when we will collect those additional revenues.

We are not providing guidance to the specific factors. I will leave that up to you. But I wanted to point out that one of the drivers for the reduction in equity needs year over year is the fact that we anticipate the GT&S decision this year.

Okay. Would it be fair to assume it's somewhat in line with your authorized capital structures such that you expect roughly half of that to go to equity and half to pay down whatever debt or other financing you used?

I think that's a reasonable way to think about it.

Okay. The second for Tony. Strategically, you're looking ahead a couple years, you've talked about clean energy, talked about next generation grid stuff. What is your appetite for investing outside of utility in some of those projects, whether it's secondary, third-party or even you guys yourselves directly?

That is a really good question. Over the four and a half years I've been here the focus has been on really focusing on back to basics, getting the Company running well, getting through the regulatory proceedings -- things we've talked about on these calls.

We do think that there are opportunities. I will tell you the affiliate rules here in California make that very difficult. In many states you can have your experts in various areas spend part of their time looking outside the utilities to divvy up their time and make sure their time is being charged to the right place. Whereas in California it's very difficult to use the expertise you've developed in utility to work on things outside the utility. You have to have a big enough opportunity to say -- all right, I'm going to bite the bullet, set up a whole separate organization to pursue these things.

But that said, I don't think a week goes by where one of us on the team doesn't have somebody coming in and having some ideas about how technology can improve this business. We actually look at them, can we incorporate them within the utility structure and be successful and help us there. It wouldn't help the bottom line necessarily but it might lower our costs to our customers, which in the long run I think is a very positive thing.

So, we are looking at those opportunities because we really do believe that we are as far, if not farther, along than most other utilities incorporating some of these technologies into the grid. As I said, we've crossed over 30% on renewables now, and that's with a 33% requirement by 2020. So, we are way ahead of the curve. Going to 50% renewables -- we're confident that we can manage 50% renewables. Many of our colleagues in the industry are struggling with how do you handle 10% or 15% renewables on your system. We've put in place the mechanisms and the technology to do it.

Thank you very much.

Ashar Khan, Visium.

Good morning and congrats. It would really help us, because you gave us the rate base, which was very helpful -- one thing would be very helpful if you can just tell us what would the 2016 equity needs have been on a normalized year if there was no funding of penalty or the extra costs that you incurred this year? What would that number have been for the year 2016? That would help us to clear a lot of confusion regarding the growth rate.

We are not providing those individual factors. But what I would say is we provided rate base out there so you have the inputs to calculate it yourself. And, in addition, we've got a couple of slides in the back of the deck which highlight the equity needs for the San Bruno penalty decision, which you can also use to back out the equity needs related to that component of our equity drivers. So the factors are there but we are not providing specifics.

So, is my math correct if I do that? It would have been nearly half, like $300 million to $400 million, if you take all those extraneous factors out?

I think I'll leave you to do that calculation.

Okay.

Thank you, everyone, for joining us this morning, and have a safe day.