Morning, and welcome to the 4th Quarter PG and E Corporation Earnings Conference Call. All lines will be muted during the presentation portions of the call with an opportunity for questions and answers at the end. At this time, I would like to introduce your hostess, Ms. Janet Leduca of PG and E. Thank you, and enjoy your conference.
You may proceed, Ms. Leduca.
Thank you, Jackie, and thanks to those of you on the phone for joining us. Before I turn it over to Tony early, 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 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 ks 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, and good morning, everyone. I'm glad you could join us. 2016 was a really pivotal year for PG and E. We continue 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 and E Corporation and Nick Stavropoulos will be taking over as President and Chief Operating Officer of our utility Pacific Gas and Electric.
Both Gayshia 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. So 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 of the storms, however, we were still able to deliver the 2nd 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. And we continue 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 continue 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 J. D. Power results for our electric business customers improved to 1st quartile. Customers continue to notice and appreciate the operational improvements that we've made. So 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 2 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 $3,000,000 fine, a 5 year probation period, oversight by a 3rd party monitor and certain requirements related to advertising and community service. As you recall, last year we announced we would not appeal the 5 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 and 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 greenhouse gas free. Nearly 33% of our portfolio was RPS eligible, which puts us about 4 years ahead of the state's 2020 target. We remain confident that we can meet or exceed our target of 55% renewable resources by 2,031. 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 $130,000,000 over the next 3 years to install the infrastructure necessary to support about 7,500 EV charging stations. In January, we filed a request to spend an additional $250,000,000 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 1,500,000,000 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 1 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 Geshia 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 5 years or so, and we're so fortunate that he's going to be continuing engage 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, really appreciate all you've done.
I also want to say how truly excited I am to leave this iconic company at such an amazing time in our safety and operational progress we've made in the last several years. 2nd, providing 1st class customer service and maintaining affordable bills so that we can be our customers' preferred provider of choice and third, positioning PG and 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 rates, 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, the utility has about a $10,500,000,000 net deferred tax liability.
This balance would be reduced by about 1 third if the corporate tax rate is lowered to 20%. 2nd, 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 $300,000,000 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 impacts 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 1,000,000,000 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.
So 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 build 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. So let me shift to our Q4 and year end results, which are on slide 6. Earnings from operations came in at $1.33 for the quarter $3.76 for the year. GAAP earnings including the items impacting comparability are also shown here.
Pipeline related expenses were $33,000,000 pre tax for the quarter and $113,000,000 pre tax for the year. We incurred legal and regulatory related expenses of $18,000,000 pre tax for the quarter $72,000,000 pre tax for the year. These last two items are consistent with the guidance we previously provided. Signs of penalties came in at $170,000,000 pre tax for the quarter and $498,000,000 pre tax 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 $46,000,000 pre tax for the quarter $232,000,000 pre tax for the year. As you'll recall, in the Q1 of last year, we took a charge for $350,000,000 pre tax, which represented the low end of the range for 3rd party property damages. It did not include any costs for fire suppression, personal injury or other damages that PG and 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 $750,000,000 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 $27,000,000 pretax. We've increased the insurance receivable to $625,000,000 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 $80,000,000 for cleanup and repair costs that are not recoverable.
Moving to the next item, we recorded $29,000,000 pre tax for the quarter and $219,000,000 pre tax 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 2nd 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 $325,000,000 pre tax for both the quarter year, which reflects recognition of gas transmission revenues in excess of our 2016 cost of service. We had originally estimated $350,000,000 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 Q1 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 to $0.05 for the quarter. We had a $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 4th 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 dollars 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 planned 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 2 updates to our 2017 items impacting comparability.
First, fines and penalties now reflect $15,000,000 for the portion of the ex parte penalty imposed in the gas transmission Phase 2 decision that we will recognize in the Q1 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 instituted investigation. 2nd, the gas transmission revenue timing impact has been reduced by $10,000,000 for a total of $150,000,000 This will also be recorded in the Q1. 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 $400,000,000 to $600,000,000 In 2018 2019, we still expect our equity needs to be met largely through internal programs, which historically have contributed approximately $350,000,000 annually to our equity needs.
Finally, on Slides 1213, we're affirming our CapEx and rate base guidance through 2019. While we're still targeting 6.5 percent 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 filings 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 2019.
Assuming the commission approves the cost of capital settlement, our authorized return on equity will be 10.25 percent in 2018. I'll close by saying it's been a strong year for the company. As Geshia 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.
Certainly. Our first question comes from the line of Julien Dumoulin Smith with UBS. Please proceed.
Hey, good morning, everyone. Well done. I wanted to follow-up on the cost cutting announcement of late. I wanted to just understand a little bit on how that gets factored into not just 2017 guidance but beyond and your ability to kind of earn at or above your authorized or your new authorized ROE, sort of during the pendency of what should be new rates in effect?
Julien, this is Geisha. How are you? So you should think of this first $300,000,000 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 sort of 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 this $300,000,000 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 that continues to be the case because we have a strong capital plan and that could put upward pressure on customer rates. 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, Geisha, obviously, you've had a few months here. In terms of hard asset acquisitions outside of the kind of core rate base utility, what's your latest thinking on that prospects? And maybe more importantly, your the parameters to the extent to which you are looking at something that you would evaluate looking outside of rate
pay? 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 on what we think is a strong growth plan. We've got a lot of work to do and with $6,000,000,000 or so dollars in capital additions every year, we think that just getting that done, getting that done efficiently is really going to serve us well.
Notwithstanding though, to answer your question, 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, etcetera, that we'd be ready to be able to act. But I wouldn't expect us to sort of come out of the gate looking for M and 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.
Thank you, Mr. Smith. Our next question comes from the line of Michael Lapides with Goldman Sachs. Please proceed.
Hey, guys. I just wanted
to see if you wouldn't mind kind of 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 kind of directionally where you see FERC electric transmission spends needing to go over the next couple of years and getting out to the 2019 2020 timeframe where GT and S spend? I mean, 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. 1, load is moderating in the state and so that would sort of reduce the need for incremental capacity projects. That being said, we are increasing our renewable portfolio standards, so there will be more large scale utility or renewable projects coming online and needing to be connected to the grid.
And so we think currently today, our conservative assumption around holding 2018 2019 spend flat to what we've received in the 2017 rate case and what we've requested in 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. And so 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 spend are very much longer term in nature. But I will say that that first that 2015 rate case was the first time that we really stepped up our revenues post San Bruno.
So 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 helping state facilitate its longer term carbon goals, particularly around electrification. So, as Tony mentioned, we recently filed an initial application for medium and heavy duty 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 the cash that's kind of gone the door for this? And I'm just trying to compare that to the insurance receivable. And so I'm not looking just for kind of the 2016 amount or the last quarter amount, just kind of the total?
Sorry, Michael. Just kind of digging that number out. There's a couple of different components here. So, we took about an $80,000,000 charge for cleanup and repair cost. Obviously, that was cash that was previously spent.
In terms of sort of claims that we've encountered to date, it's about $60,000,000 that we've paid out. And we brought in insurance roughly of about $50,000,000 So you really have to look at those individual components.
But you mentioned the insurance receivable of $625,000,000 Was that for other items unrelated to this? Or is that predominantly related to the Butte wildfire?
Yes. So the $625,000,000 I would look at it as offsetting the claims associated with the Butte wildfire plus legal costs. So we've been at roughly I think roughly $27,000,000 in legal costs to date and we have now assumed that the low end of the range for the Butte fire will be $750,000,000 The combination of those 2, we're going to seek recovery from insurers for those two costs. We took a conservative assumption of about an 80% recovery, which was the $625,000,000 that we recognized as an insurance receivable this quarter for the full year. Got it.
Thank you, Jason. Much appreciated, guys.
Thank you, Mr. Lapides. Our next question comes from the line of Steven Fleishman with Wolfe Research. Please proceed.
Yes, hi.
Just a couple of quick questions. First on the cost of capital settlement, are you getting any indications if anyone will be opposing the settlement?
This is Steve Melny 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, there was I think at the last meeting, there was, I think, some stories about commission meeting and some press stories about just people complaining about their bills. I assume that's probably just the GT and S case having been delayed and over time kind of hitting bills. Is that what it would be? And is there anything that you're doing to kind of address concerns there?
Yes. Just to give a little clarity to that, we have definitely seen 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 rates to incorporate the Phase 1 decision from GT and 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 to kind of 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 car day fine in that proceeding. So we really think that will help to moderate it. Obviously, we've 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 Geshia 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 something we pay a lot of attention to.
Great. Thank you very much.
Thank you, Mr. Fleishman. Our next question comes from the line of Sifu Mehdi with Citigroup. Please proceed.
Thanks so much. Hi, guys.
Good morning.
So 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 shave peaks? Some context would be helpful.
So from a load standpoint, in terms of kind of the puts and takes there, In our service territory, an electric vehicle sort of represents an average household of consumption, about half an average household of consumption. So you can think of for every 2 electric vehicles we add to the system, essentially we're offsetting the decline that we see from distributed generation. So that's sort of, I think an easy rule of thumb to think about load, from that standpoint. And I think from a growth standpoint financially, the state has a goal of having 1,500,000 electric vehicles on the road in California by 2025. That would equate to about 600,000 vehicles in our service territory.
We think and the state thinks that we need distributed charging stations for every 4 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 build out and provide that service to our customers in our service territory. And 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 Peker was talking about 40% targets or potentially 40% that could be reached in terms of load 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. So I think when I saw the same number, the 40% from President Picker, I think he was thinking about it in a statewide context. Our service area is a little bit different. Our service area is made up of many small municipalities and counties. So in our case, we think that 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 3rd 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 obligation to take in 2021. And 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. And I hope that answers your question.
Yes. That's really helpful. Thank you.
Thank you, Mr. Mehta. Our next question comes from the line of Paul Patterson with Glenrock Associates. Please proceed.
Good morning. How are you?
Good morning.
Good morning, Paul.
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 part of the California parties?
Yes. Hi, this is Steve Melny again. Let me give a little context for that. So 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. So just to give to help clarify that.
So 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. So 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. I think, as we said, we've had 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. And I don't want to necessarily preempt your filing. I just was wondering if you had a general sort of response to sort of the questions that were raised in it. I mean, it seems a little bit more than what the T. O.
Cases were in the past. And that's all I was trying to get. Again, I don't mean to ask you if you're going to file a response, but if you can 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?
Well, I guess I would say this. I mean, the cost components that are at issue here in this complaint, these are cost components that we have saw recovery for through the T. O. Case and settled for multiple years. So I think I'm kind of going to leave it at that.
I think we'll just see how this plays out at FERC as we get as we move forward.
Okay. Fair enough. And then Tony, is this your last earnings call?
Last one where I'll be speaking at, I'll be listening in.
Okay. Well, congratulations and good luck on the future. Thanks.
Thank you, Mr. Patterson. Our next question comes from the line of Travis Miller with Morningstar. Please proceed.
Good morning. Thank you. I was wondering real quick the ROE settlement, how would that if at all impact the transmission earnings and allowed ROE?
From an earnings standpoint, it's our objective to earn the CPUC authorized return on equities on a whole for the enterprise. 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. So 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 JITO rate case, kind of the support for the cost of capital at that time, particularly the return on equity, and 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 kind of a state level ROE plus adder type of framework there?
In the last filing, we filed for 10.4 as the base with a 50 basis point adder. And we continue to believe that 50 basis point adder is appropriate. We'll continue to file for that. That obviously return on equity is a component that is negotiated as part of the overall settlement. But again, we don't individually negotiate final settlement turns.
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 2 years or so? Assuming all the settlements go through, right? And that's obviously still a risk.
But assuming those go through, what's the next big risk?
Yes. 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. And we typically file most of our rate cases sort of late summer, kind of early fall. So 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. And so from a standpoint of a risk that is one that we need to resolve here and are actively in settlement negotiations to resolve that here hopefully shortly.
Okay. And it sounds kind of like 2018 is, I hate to say it, I'll use it in my words, not yours, but it's kind of in the books if you don't have any pending rate cases, right, and other regulatory activities. If all of that is resolved, the settlements are resolved in 2017, then surely not a whole lot, right, that would jeopardize 2018? Is that fair?
I will say that we have we do file with the FERC annually, but I do believe we have good clarity on our plan given the fact that we have either settled rate cases or all party settlement supporting the majority of our spend over the planning horizon as well as the settlement that we discussed with the cost of capital proceeding. So we think we have really strong line of sight to the rate base growth that we've articulated today. And we have a strong path to the dividend payout ratio of 60% by 2019.
So this is Tony. This is kind of the theme that we've been talking about over the last couple of 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 now. As Jason said, we still have 1 OII. We've got our Diablo Canyon settlement case there 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 2 big case 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 legislators' objectives and the commission's objectives. And 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.