PCG
#Sure, thanks, <UNK>.
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.
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.
$0.15 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.
I'm sorry, six-zero - $0.60.
That's right.
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 <UNK> <UNK> 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.
Oh, the bush fire.
Let me ask <UNK> to comment on that.
Hi, <UNK>, this is <UNK>.
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.
Let me let <UNK> <UNK> comment on where we are now on the penalty.
Hi, <UNK>.
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.
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.
Let me let <UNK> comment on the safety records case.
On the distribution records OII ---+ this is <UNK> <UNK> again ---+ as <UNK> 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.
That fine was $10.8 million.
This is <UNK> <UNK> 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 <UNK>.
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.
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.
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 <UNK>, 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.
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.
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.
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.
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.
I really don't think the numbers change in this case.
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.
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.
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.
As <UNK> <UNK> 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.
Yes, net metering doesn't hurt us.
It hurts our customers, or certain class of customers.
This is <UNK> <UNK> 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.
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.
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.
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.
We have not.
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.
We haven't picked up that any of them are demanding we spend more money right now.
And to just reiterate what <UNK> 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.
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.
I think that's a reasonable way to think about it.
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.
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.
I think I'll leave you to do that calculation.
Thank you, everyone, for joining us this morning, and have a safe day.
