PG&E Corp (PCG) 2016 Q4 法說會逐字稿

Good morning and welcome to the fourth-quarter PG&E Corporation earnings conference call.

(Operator Instructions)

At this time, I would like to introduce your hostess, Ms. Janet Loduca of PG&E.

Thank you and enjoy your conference.

You may proceed go, Ms. Loduca.

Thank you, Jackie.

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

Before I turn it over to Tony Earley, I want to remind 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 slide presentation.

The slide presentation also includes a reconciliation between non-GAAP and GAAP measures.

We encourage you to review the 2016 annual report on Form 10-K that will be filed with the SEC later today and the discussion of risk factors that appears there.

With that, I'll hand it over to Tony.

Thank you, Janet.

Good morning, everyone.

I'm glad you could join us.

2016 was a really pivotal year for PG&E.

We continued to deliver strong operational and financial results and resolved a number of important regulatory and legal matters.

We also announced that next month Geisha Williams will be taking over as CEO and President of PG&E Corporation, and Nick Stavropoulos will be taking over as President and Chief Operating Officer of our utility, Pacific Gas and Electric.

Both Geisha and Nick have done an outstanding job over the last several years, and have established proven track records for delivering results.

So, I couldn't be more thrilled about their appointments and look forward to continuing to work with them in my capacity as Chairman.

Today I'm going to spend a few minutes reviewing some of the highlights from 2016 and then I'll turn it over to Geisha for a few remarks, and then Jason will walk us through the financials.

Let me start with our safety and operational performance.

In 2016 we experienced some of the most severe storms we've seen in years.

While this was good news for our hydro generation and for the drought, it impacted our ability to meet our 2016 reliability targets.

Despite all the storms, however, we were still able to deliver the second best electric reliability performance in the Company's history.

This was in part due to our continued investments in a modern, self-healing grid that automatically isolates and minimizes customer outages.

We continued to strengthen our gas system by inspecting and upgrading hundreds of miles of transmission pipeline and replacing over 100 miles of distribution main.

We also continued to deliver industry-leading results on our gas and electric emergency response times.

On the customer side, I'm excited to share that our most recent JD Power results for our electric business customers improved to first quartile.

Customers continue to notice and appreciate the operational improvements that we made.

Turning to regulatory and legal issues, we made a lot of progress in 2016.

In December we received a final Phase 2 decision in our gas transmission and storage rate case, which gives us certainty on our gas transmission revenues through 2018.

In our general rate case, we're waiting for a proposed decision on our all-party settlement agreement.

If approved it will provide certainty on our gas and electric distribution and electric generation revenues through 2019.

We also reached a settlement agreement in our cost of capital case.

The terms include a two-year extension, which takes us through the end of 2019, a true-up for authorized cost of debt beginning in 2018, and reinstatement of the trigger mechanism for 2019.

We also agreed to reduce our return on equity from 10.4% to 10.25% beginning in 2018.

We're hopeful the settlement will be approved in the coming months.

I also want to acknowledge the recent decision in the criminal case.

In January the court sentenced us to a $3 million fine, a five-year probation period, oversight by a third-party monitor, and certain requirements related to advertising and community service.

As you recall, last year we announced we would not appeal the five integrity management counts.

We've also now decided not to appeal the obstruction of justice count.

As we focus on the future, I want to assure all of our stakeholders that the San Bruno incident has fundamentally changed the way we operate this Company.

We remain absolutely committed to ensuring that we meet the high safety standards that all of our stakeholders and we ourselves demand and expect.

As we look to the future of the industry, despite the uncertainty at the federal level, California will continue to lead the way in transitioning to a clean energy economy.

PG&E will be a critical partner in these efforts and is well positioned to help the state achieve its goals.

In 2016, nearly 70% of the energy we delivered was greenhouse gas free.

Nearly 33% of our portfolio was RPS-eligible, which puts us about four years ahead of the state's 2020 target.

We remain confident that we can meet or exceed our target of 55% renewable resources by 2031.

We continue to have more electric vehicles and private rooftop solar installations in our service territory than anywhere else in the country.

And with the transportation sector accounting for about 40% of California's greenhouse gas emissions, we expect to play a significant role in helping the state address these emissions by investing in the infrastructure necessary to enable electric vehicle adoption.

To that end, last December the Commission authorized $130 million over the next three years to install the infrastructure necessary to support about 7,500 EV charging stations.

In January we filed a request to spend an additional $250 million, primarily for the infrastructure to support electrification of medium- and heavy-duty vehicles like transit buses.

The request also includes infrastructure for fast chargers as well as some smaller pilots.

With the state targeting 1.5 million electric vehicles by 2025, we see the potential to expand these programs in the coming years.

In closing, I want to say how much I have truly enjoyed leading this Company over the last five and a half years.

The good news for me is that I will continue to work with one of the most talented executive teams in our industry as Executive Chairman.

Geisha and Nick are absolutely the right people to lead this Company into the future.

And we have recently restructured the team to better take advantage of the opportunities we have in the coming years.

So with that, let me turn it over to Geisha to share a few words.

Thank you so much, Tony.

And good morning, everyone.

First, I have to say, we've been so lucky that we've had Tony at the helm over the last five years or so.

And we're so fortunate that he's going to be continuing engaged with us as Executive Chairman.

He's done a tremendous job leading us through a challenging period and has really set us up for a successful future.

So thank you, Tony.

Really appreciate all you've done.

I also want to say how truly excited I am to lead this iconic Company at such an amazing time in our industry.

As we look forward I'm going to be focused on three areas -- first, and always first, continuing to build on the strong safety and operational progress we've made in the last several years; second, providing first-class customer service and maintaining affordable bills so that we can be our customer's preferred provider of choice; and, third, positioning PG&E for success within the changing utility industry because, as Tony said, California will continue to be at the forefront of this change.

So, it's really an exciting time to be in this industry, particularly here in California.

We are confident in our ability to execute on a strong growth plan through continued investments in upgrading and modernizing our system as we help the state achieve its clean energy goals.

I've enjoyed meeting many of you over the last few months and I look forward to meeting more of you throughout the year.

So with that, I'm going to turn things over to Jason to walk us through the financials.

Thank you, Geisha, and hello, everyone.

Before I review our financial results, I know that tax reform has been top of mind for many of you so I thought I would share at a high level how we're thinking about it.

Given that we don't know the scope or timing of reform, there is still a lot of uncertainty around what the final legislation will include.

I'll base my comments on the House Republican blueprint which includes a 20% corporate tax rate, no interest deductibility and 100% expensing of capital.

Overall, we believe we're well-positioned to address the impacts of tax reform.

Income taxes are part of our regulated cost of service.

And we would expect that the net benefit or cost of any of the proposed changes would largely flow to our customers.

With respect to the reduction in corporate tax rate, customers would benefit in a couple of ways.

First, the lower tax rate creates excess deferred taxes that would be refunded to our customers over time.

As indicated on slide 5, utility has about a $10.5 billion net deferred tax liability.

This balance would be reduced by about one-third if the corporate tax rate is lowered to 20%.

Second, customer rates would be reduced to reflect the net impact of the lower tax rate going forward.

At the Holding Company, our net deferred tax assets are about $300 million.

A reduction in the federal tax rate to 20% would reduce the value of these assets by about 40%.

While this amount would not be recoverable from customers, it also would not increase equity needs as these balances are not factored into the utility's equity ratio.

Finally, the lower tax rate will be a net positive from a rate base perspective as it will result in slower future growth of deferred taxes.

The next component I'll cover is the additional tax expense created from the elimination of the interest deduction, which would be passed to customers through the cost of capital.

We don't expect a material shareholder impact from the loss of the interest expense deduction given that we don't have significant outstanding debt at the Holding Company.

Turning to the component that would allow for full expensing of capital, we expect the impact to be minimal in the near term given our net operating loss.

Longer term, we would expect this to moderate our rate base growth.

We're not quantifying the potential rate base impact at this point as we're still very early in the process and there are a lot of variables that could impact certain tax deductions in our NOL.

Finally, just a few words on cash flows.

On a net basis we do not expect these proposed tax reforms to have a significant near-term impact on cash flows.

On the tax payment side this is because of our NOL.

On the revenue side, this is because we're currently expensing about $1 billion in capital via repairs and flowing that benefit back to customers.

The revenue reduction from the lower federal tax rate would be mitigated by the reduced flow-through benefit.

The bottom line is we're in a good position with respect to various tax reform proposals.

We believe that the net impact of these reforms will create bill capacity that may provide opportunities to increase our capital spend related to incremental infrastructure and grid modernization benefits, which we will balance with our goal of maintaining affordable service for our customers.

Let me shift to our fourth-quarter and year-end results, which are on slide 6. Earnings from operations came in at $1.33 for the quarter and $3.76 for the year.

GAAP earnings including the items impacting comparability are also shown here.

Pipeline-related expenses were $33 million pretax for the quarter and $113 million pretax for the year.

We incurred legal and regulatory related expenses of $18 million pretax for the quarter and $72 million pretax for the year.

These last two items are consistent with the guidance we've previously provided.

Fines and penalties came in at $170 million pretax for the quarter and $498 million pretax for the year.

This is primarily related to the San Bruno penalty decision and disallowances imposed for the ex parte communications in Phase 2 of the gas transmission and storage rate case decision.

Butte fire-related costs, net of insurance, were $46 million pretax for the you quarter and $232 million pretax for the year.

As you'll recall, in the first quarter of last year we took a charge for $350 million pretax which represented the low end of the range for third-party property damages.

It did not include any cost for fire suppression, personal injury or other damages that PG&E could be liable for if we were found to be negligent.

While our position continues to be that we were not negligent, this question would ultimately be decided by a jury if we were to go to trial.

This quarter we've increased the low end of the range to $750 million pretax, which takes into account the risk of all known claims including negligence.

We continue to be unable to estimate the high end of the range at this time.

We also incurred legal costs related to the fire of $27 million pretax.

We've increased the insurance receivable to $625 million, which represents the low end of the range for insurance recoveries.

As we noted last year, we expect to seek full recovery for all insured losses, so this amount should not be viewed as a ceiling on recovery.

Finally, as a reminder, last year we took charges totaling about $80 million for cleanup and repair costs that are not recoverable.

Moving to the next item, we recorded $29 million pretax for the quarter and $219 million pretax for the year related to the capital disallowances ordered in the Phase 1 gas transmission rate case decision.

As you'll recall, the Phase 1 decision included a number of cost caps and one-way balancing accounts, and we took a charge in the second quarter to reflect our best estimate of capital program costs that would exceed authorized amounts over the rate case period.

The increase this quarter reflects our updated estimate of these costs based on more detailed project planning.

Lastly, we booked revenue of $325 million pretax for both the quarter and year, which reflects recognition of gas transmission revenues n excess of our 2016 cost of service.

We had originally estimated $350 million based on high-level revenue assumptions.

The actual out-of-period revenues were slightly lower.

On slide 7, you'll see our quarter-over-quarter comparison of earnings from operations of $0.50 in Q4 of last year to $1.33 in Q4 of this year.

With the final Phase 2 gas transmission decision we were able to record revenues that were $0.48 higher compared to the same quarter last year.

As a reminder, we'll be recovering the gas transmission under-collection over 36 months and can record only 29 months of that revenue in 2016.

The remaining 7 months of the under-collection will be recorded in the first quarter of 2017.

Timing of taxes was $0.20 positive for the quarter and results in a net zero impact for the year.

We had $0.06 favorable as a result of the Diablo Canyon refueling outage in 2015 that we didn't have in the same period in 2016.

Rate-based earnings increased $0.05 for the quarter.

We had $0.01 negative for the increase in outstanding shares and $0.05 favorable for a number of miscellaneous items.

Miscellaneous includes the full severance charge for the organizational changes we announced in January.

This was partially offset by lower contract costs as a result of efficiency measures in the fourth quarter and lower incentive compensation in 2016 compared to 2015.

Transitioning now to slide 8, we are reaffirming 2017 earnings from operations guidance of $3.55 to $3.75 per share.

Our underlying assumptions are on page 9. While our overall capital expenditures in 2017 are consistent with what we shared last quarter, we've had some movement between planned rate cases.

Capacity related project delays have reduced our electric transmission spend.

These projects weren't slated to come online for several years, so you'll notice that our rate base is unchanged.

These reductions were offset by incremental plan spend, primarily in our gas distribution and transmission businesses.

It remains our objective to earn the CPUC authorized return on equity across the enterprise as a whole.

Moving to slide 10, we have two updates to our 2017 items impacting comparability.

First, fines and penalties now reflect $15 million for the portion of the ex parte penalty imposed in the gas transmission Phase 2 decision that we will recognize in the first quarter of 2017.

This item does not include an estimate for potential future fines that may result from other proceedings including the ongoing ex parte order instituting investigation.

Second, the gas transmission revenue timing impact has been reduced by $10 million for a total of $150 million.

This will also be recorded in the first quarter.

As I mentioned, actual out-of-period revenues were slightly lower than what we had forecasted.

On slide 11 we're reaffirming our 2017 equity needs with a range of $400 million to $600 million.

In 2018 and 2019 we still expect our equity needs to be met largely through internal programs, which historically have contributed approximately $350 million annually to our equity needs.

Finally, on slides 12 and 13 we're affirming our CapEx and rate base guidance through 2019.

While we're still targeting 6.5% to 7% rate base growth through 2019 there are a couple of changes to the underlying assumptions, on slide 13.

The base case now incorporates the final electric vehicle infrastructure decision that we received last December.

It does not yet include our recent filing to support medium- and heavy-duty vehicle electrification.

While we're not providing longer-term EPS guidance, it remains our objective to earn our CPUC authorized return on equity across the enterprise in 2018 and 2019.

Assuming the Commission approves the cost of capital settlement, our authorized return on equity will be10.25% in 2018.

I'll close by saying it's been a strong year for the Company.

As Geisha said, our focus on upgrading and modernizing our system to support the state's clean energy goals provides a strong growth trajectory in the future.

Assuming the cost of capital settlement is approved, we'll have certainty on our cost of capital structure and return on equity through 2019.

And we continue to target 6.5% to 7% rate base growth and a 60% dividend payout ratio by 2019.

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

(Operator Instructions)

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

Please proceed.

Hi, good morning everyone.

Well done.

I wanted to follow up on your cost-cutting announcement of late.

I wanted just to understand a little bit on how that gets factored into not just 2017 guidance but beyond and your ability to earn at or above your authorized or your new authorized ROE during the pendency of what should be new rates, in effect.

Hi, Julien, this is Geisha.

How are you?

You should think of the first $300 million cost efficiency measure that we've put in place as being part of our plan to actually meet our guidance in 2017.

So, I wouldn't really expect there to be additional upside from that.

What you should also expect, though, is that, like any other great company out there, we're going to be really focused on managing our costs.

We're going to be looking at how to improve our processes.

And you should think of the $300 million, the first initiative, as just that, a first step in what's going to be a long-term affordability journey.

We're really proud of the fact that our customer bills are below national average, and we want to work really hard to make sure that continues to be the case because we have a strong capital plan and that could put upward pressure on customer rate.

So, we're doing everything in our power to keep our bills affordable and to drive efficiencies as we move on.

Great.

And then a quick second question, I'd just be curious -- obviously, Geisha, you've had a few months here -- in terms of hard asset acquisitions outside of the core rate base utility, what's your latest thinking on that prospect, and, maybe more importantly, the parameters, to the extent to which you are looking at something that you would evaluate looking outside of rate base?

I think as you look at where we are today, we've put a lot of things behind us.

We have a very strong balance sheet.

Our focus is really on executing what we think is a strong growth plan.

We've got a lot of work to do.

And with $6 billion or so in capital additions every year we think getting that done, getting that done efficiently is really going to serve us well.

Notwithstanding, though, to answer your questions, we're building the muscle, we're building the discipline internally so that should something come up that, frankly, is accretive, that makes sense, that makes sense for our shareholders, that's consistent with our core operations, et cetera, that we'd be ready to be able to act.

But I wouldn't expect us to come out of the gate looking for M&A activity.

We don't feel like we need to.

We really have a strong growth profile, and our focus is really going to be about executing and doing a great job for our customers.

Excellent.

Well said.

Thank you.

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

Please proceed.

Hi, guys.

I just wanted to see if you wouldn't mind framing some of the things on slide 13 that maybe aren't in your current rate base guidance.

For example, can you talk a little bit about the first two items, directionally where you see FERC electric transmission spend needing to go over the next couple of years, and getting out to the 2019-2020 tame frame, where G&S spend.

I know you're not going to put hard numbers on this but I'm just trying to think about it.

Is it flat, up or down?

Good morning, Michael.

This is Jason.

As it relates to the electric transmission business, there's a couple of competing pressures on that business.

One, load is moderating in the state, so that would reduce the need for incremental capacity projects.

That being said, we are increasing our renewable portfolio standard so there will be more large-scale utility renewable projects coming online and needing to be connected to the grid.

We think currently today, our conservative assumption around holding 2018 and 2019 spend flat to what we've received in the 2017 rate case and what we requested in the 2017 rate case appears reasonable.

In the gas transmission and storage business, we really stepped up our spending quite a bit in the 2015 rate case that we just received.

When I look at 2019, there's still a lot of work that needs to be done on the system.

The drivers that we see supporting that CapEx expend are very much longer term in nature.

But I will say that 2015 rate case was the first time that we really stepped up our revenues post San Bruno.

I think that increase was a bit of an anomaly and I wouldn't factor that in going forward.

I do think the real opportunity is in helping the state facilitate its longer-term carbon goals, particularly around electrification.

As Tony mentioned, we recently filed an initial application for medium- and heavy-duties vehicles.

But, really, we think that helping support further electrification in the state provides upside to these plans longer term.

Got it.

And just thinking about the Butte fire, can you talk -- I want to make sure I've got the numbers right here -- about how much cash you've spent since this occurred, meaning what's the net total of cash that's gone out the door for this?

And I'm just trying to compare that to the insurance receivable.

So, I'm not looking just for the 2016 amount or the last quarter amount, just the total.

There's a couple of different components here.

We took about an $80 million charge for cleanup and repair cost.

Obviously that was cash that was previously spent.

In terms of claims that we've encountered to date, it's about $60 million that we've paid out.

And we brought in insurance roughly of about $50 million.

You really have to look at those individual components.

But you mentioned the insurance receivable of $625 million.

Was that for other items unrelated to this or is that predominantly related to the Butte wildfire?

The $625 million, I would look at it as offsetting the claims associated with the Butte wildfire, plus legal costs.

So, we've incurred roughly $27 million in legal costs to date.

And we have now assumed that the low end of the range for the Butte fire will be $750 million.

The combination of those two -- we're going to seek recovery from insurers from those two costs.

We took a conservative assumption of about an 80% recovery, which is the $625 million that we recognized as an insurance receivable this quarter, for the full year.

Got it.

Thank you, Jason.

Much appreciated.

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

Please proceed.

Yes, hi.

Just a couple quick questions.

First, on the cost of capital settlement, are you getting any indications if anyone will be opposing the settlement?

Hi, this is Steve Malnight from the regulatory team.

The settlement was actually conducted with most of the active parties in that proceeding.

So, at this point in time we expect that we've addressed most of the parties.

We don't think we've actually lapsed the full time for others to potentially raise their hand but we feel pretty good about the coalition we put together there.

Okay.

Great.

And then, also, I think at the last meeting there was some stories about Commission meeting and some press stories about just people complaining about their bills.

I assume that's probably just the GT&S case having been delayed and over time hitting bills.

Is that what it would be?

And is there anything that you're doing to address concerns there?

Yes, just to give a little clarity to that, we have definitely seen an uptick in concerns around winter bills, particularly for gas usage for some of our customers.

Just to give a little context for that, in August of last year we actually implemented an increase in the gas transmission rate to incorporate the Phase 1 decision from GT&S.

That accounted for about a 19% increase for the average residential customer.

As we've talked about, there was a substantial step-up in spending in that case and it was delayed pretty substantially from the initial time period when the rates would go into effect.

To help moderate that, in January we actually implemented a reduction in rates of about 8%, which is the reflection of the Phase 2 decision, where they then implemented the San Bruno penalty and the ex parte fine in that proceeding.

So, we really think that will help to moderate it.

Obviously we had a stronger winter here in California this year than prior years, which has also led to increased usage.

It's something we pay a lot of attention to.

We're very focused on it.

We are really committed to, as Geisha said, make sure we keep our bills affordable for our customers.

So, we work with them when there are concerns to help them understand how they can reduce their usage through efficiency programs and other things and help save.

So, it's something we pay a lot of attention to.

Great.

Thank you very much.

Our next question comes from the line of Praful Mehta with Citigroup.

Thanks so much.

Hi, guys.

Quickly, on the electrification, just wanted to understand a little bit more in terms of context.

I know the near-term programs you've talked about on transportation electrification.

Longer term, how do you see growth coming from that?

And how do you offset that against either energy efficiency or behind-the-meter storage that may shape peaks?

Some context would be helpful.

From a load standpoint, in terms of the puts and takes there, in our service territory an electric vehicle represents an average household of consumption, about half an average household of consumption.

So, you can think of, for every two electric vehicles we add to the system, essentially we're offsetting the decline that we see from distributed generation.

So, that's, I think, an easy rule of thumb to think about load from that standpoint.

From a growth standpoint financially, the state has a goal of having a 1.5 million electric vehicles on the road in California by 2025.

That would equate to about 600,000 vehicles in our service territory.

We and the state thinks that we need distributed charging stations for every four vehicles that are on the road.

So, that would be a need for approximately 150,000 charging stations in our service territory.

We think we're best positioned to facilitate that buildout and provide that service to our customers in our service territory.

So, this initial application, which we just recently had approved, that was only for 7,500 charging stations.

So, we see the opportunity for fairly significant growth over the next several years to help enable the state to meet its overall policy goals.

Got you.

That's really helpful context.

Thanks.

And then, secondly on CCAs, I know this is a topic that keeps coming up.

I think Chairman Picker was talking about 40% target, or potentially 40%, that could be reached in terms of loads served through CCAs.

How do you see that transition of CCAs?

And is there any risk for stranded assets sometime in the future?

Hi, this is Geisha.

I think when I saw the same number, the 40% from President Picker, I think he was thinking about it in the state-wide context.

Our service area is a little bit different.

Our service area is made up of many small municipalities and counties.

In our case, we think that transition to higher levels of CCA adoption are going to take a little bit longer.

But we think the number is generally right, it's just going to happen over a longer period of time.

What we're doing in terms of preparing for that, of course, is, the first and most important is we have a really flexible energy supply portfolio.

So, for example, about 55% of the energy that we deliver to our customers is actually procured from third parties.

And those contracts tend to be a combination of both long-term and spot-market purchases.

So, of the 55% that we have now under contract, nearly 40% represents megawatt hours that we do not have a contractual obligation to take in 2021.

The reason I bring that up is, as CCA adoption grows, we're really executing on our very flexible energy portfolio.

So, we believe we've got the triggers that we need to be able to meet the load over time.

I hope that answers your question.

Yes, that's really helpful.

Thank you.

Our next question comes from the line of Paul Patterson with Glenrock Associates.

Please proceed.

Good morning.

How are you?

There was a transmission complaint case that was filed by the California PUC and others regarding Order 890 on the transmission planning process.

I was just wondering if you could maybe address your thoughts about that complaint and this apparent desire to have input on transmission planning to a greater degree on the part of the California parties.

Yes, hi, this is Steve Malnight again.

Let me give a little context for that.

In early February, the CPUC and other parties, as you said, they filed a complaint at FERC seeking, really, to establish a process for stakeholders to be more involved in the portion of our transmission planning spend that's not subject to the ISO review here in California.

Just to help clarify that, the ISO currently reviews our planned work for capacity and reliability projects but they don't review other work such as our normal maintenance activities and things like that.

This is a complaint that the parties are filing.

We're going to be replying to that here shortly in a few weeks and we'll see how that proceeds.

As we said, we have gone through several TO cases over the last several years and continued to put them forward under the current framework and settle those cases.

So, we'll work our way through this issue, as well.

Okay.

I don't want you to necessarily preempt your filing.

I just was wondering if you had a general response to the questions that were raised in it.

It seems a little bit more than what the TO cases were in the past.

That's all I was trying to get at.

Again, I don't mean to ask you to tell us what you're going to file in response, but if you could follow what I'm saying.

Just any sense as to what's necessarily driving this, other than, of course, the PGM complaint that we saw in the summer, or anything else?

I would say this -- the cost components that are at issue here in this complaint, these are cost components that we have sought recovery for through the TO case and settled for multiple years.

I think I'm going to leave it at that.

We'll just see how this plays out at FERC as we move forward.

Fair enough.

And, Tony, is this your last earnings call?

Last one where I'll be speaking.

I'll be listening in.

Okay.

Well, congratulations and good luck on the future.

(Operator Instructions)

Our next question comes from the line of Travis Miller with Morningstar.

Please proceed.

Good morning.

Thank you.

Real quick, the ROE settlement, how would that, if at all, impact the transmission earnings and ROE?

From an earnings standpoint it's our objective to earn the CPUC authorized return on equity on a whole for the enterprise.

The reason why we say that is because the FERC rate cases have historically been settled, and as part of the settlement it's essentially a black box where we don't specify directly the return on equity in those rate cases.

So, I think it's a fair assumption from a modeling standpoint just to apply the CPUC authorized return on equity across all of our rate base.

We separately will look at, when we file the next TO rate case, the support for the cost of capital at that time, particularly the return on equity.

We'll have to see what the factors are at that point.

Okay.

And then if you're able to say here in terms of that black box, how much do those negotiations and FERC's view depend on a state level ROE plus adder type of framework there?

The last filing we filed for 10.4 as the base with a 50 basis point adder.

We continue to believe that 50 basis point adder is appropriate.

We'll continue to file for that.

That obviously -- the return on equity is a component that is negotiated as part of the overall settlement.

But, again, we don't individually negotiate final settlement terms.

It's just an overall black box settlement.

Okay.

Got it.

And then a broader question -- given the work that you guys did, the success you had resolving things in 2016, what's the next big regulatory hurdle for you guys?

Does it go all the way out to the next GRC or is there something here that presents some material risk on the regulatory side in the next two years or so?

Assuming all the settlements go through, and that's obviously still a risk.

But assuming those go through, what's the next big risk?

Assuming that all -- and we do assume that all the settlements will go through -- our next big rate case filing will actually be the gas transmission storage rate case for 2019.

We typically file most of our rate cases late summer, early fall.

From a rate case standpoint that's the next big one on the horizon.

I will say, we need to close out the OII associated with our ex parte violations.

So, from a standpoint of a risk, that is one that we need to resolve here, and we are actively in settlement negotiations to resolve that here, hopefully shortly.

Okay.

It sounds like 2018 is, I hate to say it, I'll use it in my words, not yours, in the books, if you don't have any pending rate cases -- right?

-- and other regulatory activities.

If all that is resolved, the settlement's resolved in 2017, then really not a whole lot that would jeopardize 2018.

Is that fair?

I will say that we do with the FERC annually.

But I do believe we have good charity on our plan given the fact that we have either settled rate cases or all party settlements supporting the majority of our spend over the planning horizon, as well as the settlement that we discussed with the cost of capital proceeding.

We think we have really strong line of sight to the rate base growth that we have articulated today, and we have a strong path to the dividend payout ratio of 60% by 2019.

This is Tony.

This is the theme that we've been talking about over the last couple months and why I said 2016 was really a pivotal year.

We now are able to focus on the future far more intensely than we have been in the past where we were just dealing with the various cases.

As Jason said, we still have one OII, we've got our Diablo Canyon settlement case that, that's still out there, that has to be resolved.

But, yes, when you're talking about our revenue stream coming forward, we've got the two big cases and hopefully we get the rate case settlement approved.

We now are focusing on the changes that are going on in the industry and the opportunities that we have to invest in a clean energy future in California, which is clearly part of this governor's objective and the legislators' objectives and the Commission's objectives.

That's why I think we're really well set up to align with those desires.

That's great.

Appreciate it.

Okay.

This is Janet.

I just want to thank everyone for participating today and we'll be talking to you in the future.

Thanks.

Ladies and gentlemen, thank you for attending the fourth-quarter PG&E Corporation earnings conference call.

This now concludes the conference.

Enjoy the rest of your day.