Good morning, welcome to the PG&E Corporation third quarter earnings conference call. All lines will be muted during the presentation portions of today's call, with an opportunity for questions and answers at the end. At this time, I would like to introduce your hostess, Ms. Janet Loduca. You may proceed.
Thank you, Monique, thanks to those of you on the phone for joining us. Before I turn it over to Tony Earley, I want to remind you that our discussion today will include forward-looking statements about our outlook for future financial results, which are 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 pages of today's third quarter earnings and business update presentations. We also encourage you to review our quarterly report on Form 10-Q that will be filed with the SEC later today, and the discussion of risk factors that appears there and in the 2015 annual report. With that, I'll turn it over to Tony.
Well, thank you, Janet, thanks to all of you for joining us. We're going to do something a little different on today's call. As you know, we've resolved a number of regulatory and legal issues over the last several months. With the gas transmission storage rate case decision, the all-party general rate case settlement, and the resolution of most of the San Bruno-related proceedings, we wanted to step back and review where we are and where we're heading. We plan to spend about half the time on today's call with our prepared remarks, and we'll start with a quick overview of our third quarter results and then share our vision for where the company is headed. We're also initiating 2017 earnings guidance today. Our presentation will take a little longer than usual, but we still expect to have about 30 minutes for questions at the end.
With that, let me turn it over to Jason to cover the third quarter results, then I'll talk more about our longer-term vision.
Thank you, Tony, and good morning, everyone. I'm going to start with the third quarter earnings presentation that we issued this morning. Then we'll move to the business update presentation. Slide three shows our results for the third quarter. Earnings from operations came in at $0.94. I know this is lower than many of you expected, but we are reaffirming our guidance for earnings from operations for the full year. As I'll discuss more in a minute, the Q3 results are largely driven by timing items. Our third quarter GAAP earnings, including the items impacting comparability, are also shown on slide three. Pipeline-related expenses were $31 million pre-tax this quarter. The charge for legal and regulatory-related expenses was $23 million pre-tax, and fines and penalties were $67 million pre-tax and are primarily related to the San Bruno penalty decision.
We're showing $16 million pre-tax for the Butte Fire-related costs net of insurance, which are largely for legal costs associated with the Butte Fire. We did not adjust our insurance receivable this third quarter. However, we do intend to seek recovery of all insured losses from our insurance carriers. As a reminder, the current receivable should not be viewed as a ceiling on insurance recoveries. Moving to slide four, you'll see our quarter-over-quarter comparison of earnings from operations of $0.84 in Q3 of last year to $0.94 in Q3 of this year. As a result of the phase one gas transmission storage rate case decision, we increased our rates in August to begin recovering the higher approved revenues. This resulted in $0.11 of higher revenues compared to Q3 of last year.
We also continue to see $0.05 positive for growth and rate base earnings. Regulatory and legal matters totaled $0.05 positive for the quarter. This item includes some incentive revenue awards. Timing and taxes was $0.04 negative for the quarter. As a reminder, this is purely a timing item that will net to zero by year-end. As a result, you can expect to see a $0.20 pickup in the fourth quarter. It'll fully offset the amount recognized through Q3. We also had $0.03 negative for an increase in outstanding shares and $0.04 negative for a number of miscellaneous items. Turning to slide five, we are reaffirming our guidance from earnings from operations of $3.65-$3.85 per share. GAAP guidance is shown here as well. We're also reaffirming our expectation of roughly $800 million in equity issuance this year. Slide six shows our updated guidance assumptions.
We assume capital expenditures of roughly $5.7 billion, which is slightly higher than our second quarter projection of $5.6 billion. We've increased the gas distribution number to reflect our best estimate of spend through the end of the year. Our assumption for weighted average rate base is $32.4 billion, consistent with last quarter. In the bottom right, we've updated the other factors affecting earnings from operations to reflect the proposed phase two decision we received earlier this week in the gas transmission rate case. Our guidance assumes that the proposed decision is approved this year without any material modifications. If we do not receive a final phase two decision before the end of the year, our earnings will be reduced by about $0.25.
We continue to target earning our 10.4% CPUC authorized return on equity across the enterprise, plus the net impact of the other earnings factors listed here. Moving to slide seven. We've updated the ranges for several of the 2016 items impacting comparability. The range for pipeline-related expenses is the same as last quarter. For legal and regulatory-related expenses, we've updated this line to reflect our expectation that we'll come in at about $75 million, which is the high end of the previous range. Fines and penalties increased by $15 million pre-tax, reflecting a number of updates, which I'll cover in a minute. We've also updated the Butte Fire-related cost to reflect a charge of $16 million pre-tax in Q3, largely driven by legal costs. We remain unable to estimate the high end of the range at this time. The remaining items are unchanged from last quarter.
The table at the bottom of the page shows our updates to fines and penalties. First, the charge for disallowed capital has increased by $6 million. We have now fully accrued for all of the safety-related capital we expect to be disallowed in the phase two gas transmission decision. Second, we incurred $4 million charge for the ex parte penalty associated with the higher gas transmission revenues we collected in August and September. Assuming the proposed phase two decision is approved this year, we'll record an additional $54 million in Q4 to reflect the full 2016 impact of the ex parte penalty. Third, we increased the gas distribution recordkeeping fine by $2 million to reflect the modified presiding officer's decision. The total is now $26 million. Finally, we've included a $3 million charge as a result of the federal criminal verdict. That concludes the Q3 earnings update.
We continue to have confidence in our ability to achieve our guidance this year, assuming the proposed phase two decision in the gas transmission rate case is approved in December. With the resolution of a number of significant issues over the last several months, we have much greater clarity on our future operational and financial performance, which we've laid out in the business update. With that, let me turn it back over to Tony.
Thanks, Jason. Let me turn to the business update presentation that we issued earlier this morning. I'd encourage all of you to have the presentation in front of you as I share my comments because I think it'll be a little easier to follow along. As you can see on slide three, we're going to cover three areas today. First, I'm going to review the progress we've made over the last six years because we have come a long way. We know we still have more work to do, but I am really proud of what the team has accomplished, and I want to share some of those results with you. Second, I'm going to talk about some of the things that really provide PG&E with a strategic advantage. Third, I'm going to talk about what's driving growth going forward.
Part of that, Jason is going to review the 2017 earnings guidance as well as our updated CapEx and rate base guidance through 2019. Between our six and a half to 7% rate base growth and our above-average dividend per share growth, we expect to deliver strong returns over the next several years. Let me start with the progress that we made. Slide five provides a high-level overview of the company. As you can see, over 90% of our revenues are set by the California Public Utilities Commission, with the remainder set by FERC. Nearly half of our revenues are pass-through for things like energy procurement costs and public purpose programs. Turning to slide six, one of the things I'm most proud of is how we've embedded safety into our core governance structures. Safety is really the foundation of everything that we do.
When I joined the company in 2011, we began a back-to-basics strategy with safety at the forefront. Let me give you some examples of that. At the leadership level, we've supplemented our team with new board members and executives who bring significant utility experience. At the board of directors, we've brought on a number of former utility CEOs like Anne Shen Smith from Southern Cal Gas, Dick Kelly from Xcel Energy, and Fred Fowler from Spectra Energy. We brought in a whole new leadership team on the gas side of the business, starting with Nick Stavropoulos, who brings more than 35 years of experience in the gas industry. We've included bios for some of our leadership team in the appendix.
In 2012, we became the first utility in the industry to publish a dashboard that tracks how we're performing on key public safety metrics, such as emergency response times and reduction of gas dig-ins and electric wire downs. That focus has driven significant operational improvements, as I'll discuss in just a minute. Several years ago, we also restructured our short-term variable compensation plan so that 50% is now tied to our performance on public and employee safety. This incentive program applies to all of our management employees, as well as some of our union-represented employees. Finally, we've done a lot of work on our safety culture. This is probably the most critical piece because it's our culture that ultimately drives the performance that we're looking for.
Part of our strategy has been to install a continuous improvement mindset by encouraging employees to identify gaps and opportunities and then close them through benchmarking and process improvement. We also wanted to make sure that every employee felt comfortable raising concerns, no matter how big or small. We made a number of changes to encourage all employees to speak up when something doesn't seem right. For example, we work with our unions to develop a non-punitive self-reporting policy. We've also adapted the nuclear industry's corrective action program across the company to make it easy for employees to report things that need to be fixed. In fact, employees can now report corrective action items through a simple app on their smart devices. We've created a number of awards to publicly recognize employees when they do speak up so that we're encouraging and reinforcing that behavior.
All of these efforts have really paid off. As you can see on slide seven, we've achieved industry-leading performance on a number of gas safety metrics. We've reduced our emergency response time and gas dig-ins by about 40%, and we virtually eliminated our leak backlog by completely redesigning our approach to finding and repairing leaks, including deploying sophisticated new technologies that are 1,000 times more sensitive than traditional detection equipment. We've also replaced or upgraded hundreds of miles of distribution and transmission pipeline. We're the first utility in the country to be certified under PAS 55, ISO 55001, and RC 14001 for our asset management programs. We're the first company in the U.S. to meet the rigor of the American Petroleum Institute 1173 standard for pipeline safety and safety culture. I couldn't be more proud of how the team has turned the gas business around.
We've also made tremendous improvements on the electric side of the business, as you can see on slide eight. Our emergency response performance is now in the first quartile. As a result of our investments in smart meters, automated switches, and circuit upgrades, we've delivered seven straight years of record-breaking electric reliability. Our customers are experiencing fewer and shorter outages than ever before. All of these improvements are really showing up in our customer satisfaction scores. While we still have more work to do, our J.D. Power results across all customer classes have increased steadily since 2012, as you can see on slide nine. The improvements we made in safety and reliability over the last six years have put us in a position to deliver strong financial results going forward.
Earlier this year, we announced our first dividend increase in six years, we've committed to achieving a roughly 60% payout ratio by 2019. Combined with our expected rate base growth, we're confident we can deliver a strong overall return for our shareholders. Turning to the next section, I want to highlight a few areas that provide PG&E with a strategic advantage, particularly as our industry undergoes significant change. One of the trends we've seen over the last decade is the increasing focus on climate change and greenhouse gas reduction, that trend is only going to intensify in coming years. At PG&E, we've been committed to sustainability for decades, we're one of the greenest utilities in the country. As you can see on slide 13, nearly 60% of our electric deliveries come from carbon-free and renewable resources. That's almost twice the national average.
That's important to our customers who pride themselves on environmental stewardship. PG&E's customers are leading the way for the country with 25% of all rooftop solar installations and 20% of all electric vehicles. We've also expanded our engagement efforts, establishing an advisory council last year to help inform our sustainability strategy and priorities. This council is made up of a diverse group of leaders from environmental organizations like Ceres and the Natural Resources Defense Council, as well as policy experts, academia, and businesses. We've consistently been recognized as one of the leading companies by a number of third-party sustainability assessments. We've also had the privilege of operating in a state that has a number of constructive regulatory mechanisms, which are shown on slide 14.
In California, revenues have been decoupled from sales for decades to help encourage energy efficiency. PG&E's revenues are not impacted by changes in load. The CPUC has also authorized a number of balancing accounts that allow us to track and recover costs that are more unpredictable, such as the cost to respond to earthquakes and other large-scale emergencies. Our rate cases are based on forward-looking test years. The CPUC is now reviewing all requests through the lens of risk mitigation. We think this is the right approach and aligns well with our strategic planning process, which starts with a detailed risk assessment of all of our assets. In fact, earlier this year, the CPUC's Safety and Enforcement Division found PG&E's risk management process to be industry-leading.
California also has a separate cost of capital proceeding that establishes the authorized capital structure and return on equity over a three-year period for all of the IOUs. Our current 10.4% return on equity is fixed through 2017. Turning to slide 15, California continues to be a leader on energy policy. The state is now targeting to reduce greenhouse gas emissions to at least 40% below 1990 levels by 2030. To get there, California will be increasing renewables to 50%, doubling energy efficiency, and electrifying the transportation sector. PG&E will continue to be a critical partner in helping the state achieve its energy policy goals. That brings me to our last differentiator. California's policy goals around safety and environmental leadership will continue to provide opportunities for sustained infrastructure investment.
To support safety and reliability, PG&E is investing in multi-year programs to enhance our gas, electric, and generation assets. I'll provide some specific examples in just a minute. To enable California's clean energy economy, PG&E will continue to modernize the grid to ensure that our systems can effectively integrate both the increased renewables and distributed energy resources. Longer term, California is working on some of the largest rail and water infrastructure projects in the country, which we expect will require $hundreds of millions in PG&E investments over the next 15 years. With our proven track record of being able to finance and deliver on these types of large-scale projects, we are well-positioned to help the state achieve all of its goals at a reasonable cost. This brings me to our last section, which focuses on our future growth profile.
As you can see on slide 18, we have three focus areas, continuing to enhance safety and reliability, enabling California's clean energy economy, and ensuring that our customers' rates will continue to be affordable, particularly in light of future load projections. Slide 19 shows a few examples of some of the longer-term programs we'll be executing to enhance safety and reliability. On the gas side of the business, we've been steadily increasing the percentage of our gas transmission pipeline that is capable of in-line inspection, and we're targeting to reach about 65% by 2026. In fact, we've partnered with a number of companies to create the next generation of in-line inspection tools that can capture even more detailed information about the integrity of the pipeline without any interruption to gas service. We also continue to increase the number of miles of gas distribution pipeline we're replacing each year.
On the electric side, by 2019, we're targeting to install automated switches on about 45% of our urban distribution lines and upgrade about 85% of our urban substations. These investments will continue to enhance electric reliability by increasing our ability to automatically reroute power during outages. California's clean energy policies will also drive continued investment. As you can see on slide 20, we expect to spend about $1 billion through 2020 on grid modernization projects. As I mentioned earlier, our customers are already adopters of technology, and we already have the most solar rooftop installations and electric vehicles in the country. The demands on our distribution grid are greater than ever before, and we need to continue to invest in technologies and systems that seamlessly integrate Distributed Energy Resources and accommodate two-way power flow.
We also expect to play a critical role in helping to electrify the transportation sector by building out the necessary charging infrastructure. We see this trend continuing well into the next decade as the state moves towards its longer-term goals of increased renewables, energy efficiency, energy storage, and electric vehicles. With all of this investment in our future, we are keenly focused on affordability. As you can see on slide 21, we're in good shape today. Our bills are 30% lower than the national average, and over the last couple of decades, our electric rates have grown in line with the rate of inflation. We know it will be challenging to continue this trend.
Over the next 10 to 15 years, we expect our bundled electric load to decline due to a combination of increased energy efficiency and demand response and communities electing to procure their own generation through Community Choice Aggregation. In fact, this was a major driver behind our decision not to seek to extend the Diablo Canyon Power Plant license beyond the current expiration dates of 2024 and 2025. As you can see on slide 22, we have a number of strategies to manage this change. Our current electric portfolio gives us a lot of flexibility. We purchase over half of our energy from third parties, and about 30% of the megawatt hours under contract are expiring over the next five years. As I mentioned earlier, our revenues have been decoupled from sales for decades, and we have mechanisms in place to allocate appropriate costs to our departing customers.
While declining load doesn't impact our earnings, it does shift costs among our customers under the current rate structures. That's why our strategy also includes modernizing our rate structures. As the use of our grid changes, the way our rates are designed needs to be changed as well. Both the state legislature and the Public Utilities Commission have recognized the need for reform, we've made some progress over the last year through flattening the residential tiers and moving new net energy metering customers to time of use rates. We've also shifted the peak period for our time of use rates from midday to the evening hours in recognition of the significant amount of solar generation now available during the day. More work needs to be done.
In September, the CPUC issued a draft white paper on its Distributed Energy Resources Action Plan, which outlines its vision for effectively integrating distributed energy resources into the system. Part of that vision is to develop rate structures for the new grid uses while ensuring that rates remain affordable for non-DER customers. We look forward to working with the commission over the next several years to update our rate structures to better reflect the current and future uses of the grid. At the same time, we're working to drive sustainable efficiencies in our own cost structure. Through our benchmarking and continuous improvement efforts, we've successfully reduced costs in a number of areas over the last few years. Going forward, we'll continue to capture savings through process improvement, technology investments, and procurement efficiencies while maintaining our strong focus on safety and reliability.
As I think you can see, we're at the forefront of a lot of exciting industry changes. California's vision of a decarbonized economy creates a lot of investment opportunities. As we just discussed, we are well-positioned to manage changes to our load profile as customer choice increases. Before I turn it back over to Jason to talk about our updated guidance, I want to say again how proud I am of the progress that this team has made over the last six years. We have had a relentless focus on safety and reliability, and you can really see the results of that in our operational metrics. I'm excited about our future and confident in our ability to deliver strong operational and financial results going forward. With that, let me turn it back over to Jason.
Thank you, Tony. I'm going to finish up today's presentation by reviewing our 2017 earnings guidance and updated CapEx and rate base guidance through 2019. Turning to slide 25, our 2017 guidance on an earnings from operations basis is $3.55 to $3.75 per share. We're also providing ranges for the items impacting comparability, which I'll come back to in a minute after we review the guidance assumptions on Slide 26. Starting in the upper left corner, you'll see we're assuming capital expenditures are roughly $6 billion. We've included the breakdown by rate case here. In the upper right corner, our estimate of weighted average rate base is about $34.3 billion for the year. Both the CapEx and rate base assumptions are within the ranges we provided last quarter. In the lower left, we continue to assume a CPUC-authorized equity ratio of 52% and a return on equity of 10.4%.
Finally, in the bottom right corner, we list some of the other factors we believe will affect 2017 earnings from operations. Our guidance assumes that both the GRC settlement and the proposed phase two decision in the gas transmission rate case are approved without material change. You'll recall that we did not seek recovery in the gas transmission rate case for about $50 million of costs in 2017. We're also showing a positive item here for incentive revenues and other benefits, which include things like our energy efficiency programs. I'll note that we're no longer showing a positive item for tax benefits, consistent with the guidance we previously provided. We continue to expect that CWIP earnings will be offset by the below-the-line cost, which includes things like charitable contributions, advertising, and certain environmental costs.
In 2017, we expect that the other earnings factors listed here will largely offset each other. As a result, we are targeting to earn the CPUC-authorized return on equity on rate base for the enterprise as a whole. Turning to slide 27, the guidance for our items impacting comparability ranges from a negative $35 million to a positive $40 million pre-tax. The categories are consistent with the items we had in 2016. The estimated range for pipeline-related expenses is $80 million-$125 million pre-tax. This item relates to clearing our gas transmission rights of way. While we're confident in our ability to fully complete the program within this range, there is a chance that a small portion of that work could slip to 2018 due to permitting requirements. We'll monitor the program throughout the year and provide updates as we have better information.
The second component is legal and regulatory-related expenses, which we estimate to be between $10 million and $40 million pre-tax. This represents costs incurred with enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications. The third component is for potential fines and penalties, again related to natural gas matters and regulatory communications. We're showing a total of $30 million, which reflects the 2017 portion of the disallowed expenses expected from the phase II gas transmission rate case decision. While we haven't yet reflected the 2017 portion of the ex parte penalty, we'd expect to record an additional $14 million pre-tax after the proposed phase II decision is approved. Butte Fire-related costs were uncertain in 2017, but this item will reflect any updates to third-party liability estimates, legal costs, and insurance receivables.
Finally, for the gas transmission rate case, we're showing a positive $160 million for the portion of the 2015 and 2016 out-of-period revenues that we plan to recognize in 2017. Turning to slide 28, we assume equity issuance of about $400 million-$600 million in 2017. That compares to roughly $800 million in 2016. The main drivers for the difference are the lower expected San Bruno penalty costs and gas transmission capital disallowance. Partially offsetting these reductions are higher capital expenditures. After 2017, we expect our unrecovered costs to continue to decline as we wrap up the gas transmission rights-of-way program. As a result, in 2018 and 2019, we expect to be able to meet our equity needs largely through our internal programs, which can generate about $350 million annually. Moving to slides 29 and 30, we've updated our CapEx and rate base guidance through 2019.
This year, we're including a breakdown by major rate case. For the general rate case, the numbers are consistent with the all-party settlement we announced earlier this year. For the gas transmission and storage rate case, the numbers are consistent with the assumptions embedded in our Q2 guidance, with one exception. We previously assumed that roughly $400 million would be added to rate base in 2017 for the 2011 through 2014 capital spend subject to audit. Because that audit has not yet begun, we're now assuming that the $400 million will be added to rate base in 2018. For the electric transmission owner rate case, we show a small range, which represents the TO18 request at the high end and the TO17 settlement at the low end. We've held these assumptions flat through 2019.
We've also listed some items here that are not included in our rate base assumptions, including primarily any new investments that will be included in the 2019 gas transmission rate case and the 2018 and 2019 electric transmission rate cases. Finally, slide 31 is just a reminder that we are targeting a roughly 60% payout ratio for our dividend by 2019. On average, this should provide for above-average dividend per share growth. I know we've covered a lot this morning. Let me conclude by reiterating the points Tony started with. Over the last six years, our focus on safety has resulted in significant operational improvements. We have a number of strategic advantages that help position us to effectively manage industry changes, and we believe our roughly six and a half to 7% rate base growth and above-average dividend per share growth through 2019 make us an attractive investment.
With that, I'll open it up for questions in the time we have remaining.
Certainly. Ladies and gentlemen, if you would like to ask a question, press star one. To remove your question, press star two. If you're using a speakerphone, please pick up your handset before using your keypad. Again, to ask a question, press star one. We will pause briefly to allow questions to generate in queue. Our first question comes from the line of Steve Fleishman with Wolfe Research. You may proceed, Mr. Fleishman.
Just on the financing plan for 2017 and the equity, are we pretty much at a level where we're just funding the core business, and we're not really dealing with any of the balance sheet fixes for some of the lingering issues?
Good morning, Steve. The 2017 equity guidance plan does assume that we continue to fund some unrecovered costs, which are primarily related to the clearance of our rights-of-way in our gas transmission business. Otherwise, the major driver of that equity plan is our CapEx and the need to fund our CapEx spending.
How much is that, $100 million still? Or is that a different to rights-of-way or $75 million?
We're estimating between $80 million-$125 million for the year.
Okay.
Pre-tax.
Okay. One other high-level question. Tony, you mentioned in terms of the affordability stuff, you have a lot of your old PPA contracts rolling off over the next five years.
That's correct.
My recollection is some of these probably are pretty high pricing. I'm just curious how much potential rate headroom that creates over the long term, any kind of just sense of that?
Steve, the way to look at it is, our objective is to maintain a rate trajectory that approximates the rate of inflation. You've got several levers to pull. One is we're working hard on efficiencies within our operations. As you recognize, another will be the cost of purchased power. You're absolutely right. Some of the early renewable contracts that we signed probably a decade ago were significantly higher. While those aren't changes that fall to the bottom line as such, but they are changes that affect affordability because they directly affect the customer bill. We're working on pulling those levers.
We have a number of other balancing accounts that we continue to work on, where, again, don't necessarily fall to the bottom line, but give us more headroom when we invest the capital that we see we're going to be investing over the next decade or so.
Okay. Thank you.
Thank you, Mr. Fleishman. Our next question comes from the line of Julien Dumoulin-Smith with UBS. You may proceed.
Hi. two questions here. First, a little bit more detailed. When you think about the cost of capital proceeding coming up, can you give us some comments on what the tailwinds you're seeing in your cost of debt versus what's embedded in rates today and willingness to potentially use that as part of the ongoing conversations? I'll stop there.
The cost of capital or any settlement discussions are confidential. What I would say in terms of the embedded benefit for cost of debt is roughly around $75 million a year.
Got it. That's pretty stable right now?
That's what we're currently experiencing now. We'll have to see how rates move and what our upcoming issuances look like.
Got it. Excellent. Then going back a little bit higher level, you commented one of the erosions in your sales forecast relates to CCAs. Can you comment on what the pace of the CCA is and just broadly what that means for your business? I know there's puts and takes, but I'd just be curious, specifically on the procurement front, what does that mean?
Well, Geisha Williams will comment on that.
Hi, Julien, this is Geisha. We have CCA activity going on at various stages of development or at various stages of consideration. Some of the CCAs, some of the communities present larger amounts of load than others, it's really a probabilistic view of trying to figure out when certain CCAs are going to happen, what kind of load might in fact depart. Now remember that they would only be responsible for providing the energy side of the business. We would still be responsible for the T&D business. As we look at our load projections, it's kind of difficult to pinpoint it down to a particular number in terms of what we might be able to see from CCAs. It can move pretty quickly. In other cases, we see CCAs taking longer, sometimes up to 18 months or 24 months.
It's a bit fluid is how I would answer that.
Got it. Maybe just curious, do you think broadly the tariff structure, the exits, and ongoing payments are sort of reflective of what you avoided the incurred cost?
Hey, Julien, this is Steve Malnight from Regulatory Affairs. I think that as we look that we're constantly working with the commission on how to continue to revisit and look at the cost allocation mechanisms that are in place. I will say, as Geisha alluded to, I think when we look forward, we see a significant expansion of CCA load growth, that's one of the reasons why the Diablo Canyon settlement made sense for us. In light of that, we continue to go back and look. I think that it's likely that those mechanisms will evolve as the marketplace evolves as well.
Got it. Great. Thank you so much.
Thank you, Mr. Smith. Our next question comes from the line of Jonathan Arnold with Deutsche Bank. You may proceed.
Oh, good morning, guys.
Morning, Jonathan.
Morning, Jonathan.
Thanks for all the detail. Just a quick question. You indicated that the items kind of other than the regular rate base type math would net to about zero in 2017. Any reason to see that changing as you look out into the 2018 and 2019 that's obvious?
It continues to remain our objective to earn our authorized return on equity. What I will say is the gas transmission and storage phase one decision created some challenges for us in terms of mandated work levels and certain cost caps. We're going to continue to drive efficiencies to offset these challenges to enable us to earn our authorized return. I think that should be the focus, earning the authorized return on equity across the enterprise as a whole.
Okay. Then just sort of a little detail, but I think you said that going forward 2018, 2019, you think you could hit your equity needs largely through internal plans and that they generate about $350 a year. Should we be using $350? Is it a little higher, or?
I'm just going to stick with what I had said, which is it will largely meet our equity needs.
Okay. All right, that's it. Thank you very much.
Thank you, Mr. Arnold. Our next question comes from the line of Michael Lapides with Goldman Sachs. You may proceed.
Hey, guys. Congrats. Tony, one question. The slide on grid modernization and the billion-dollar spend, just curious, is all of that embedded in some of the GRC settlements in your distribution spend that you have over the next few years? Or will you have to go into the CPUC and request approval of this in some kind of memo account?
No, the approach we've been making is to embed our grid modernization in our GRC cases, in our transmission system cases. We've been making these investments probably for close to 10 years, and we continue to make them. The $1 billion number is our estimate of what it's going to be in the next couple of years coming up.
Yeah, as a reminder, I would say most of it has already been approved, but there is a component that we're still seeking recovery from in terms of our TO case.
Got it. Turning to the TO on the electric side, just curious, how do you think about what the trajectory of electric transmission spend is over the next 3-5 years, kind of flattish to what you've got in 2016, 2017 potentially elevated? What could be some of the drivers that could move that around?
Yeah. I think as you look at the next, clearly through 2019, you're going to see a pretty flat but pretty robust spend in TO. That's really driven by a number of things, but a lot as we look beyond 2019, frankly, will be with renewables integration work. As we seek to achieve the 55% RPS goal by 2031, we recognize that we're going to need to continue to invest in our transmission infrastructure. A strong amount of capital through 2019, and although we're not providing guidance beyond it, I would imagine that we'd continue with a similar type of expenditure.
Finally, when I look at your CapEx budget, so kind of in the $6 billion range for the next three years, pretty flat, actually, not kind of accelerating, which is fine. That would imply that free cash flow should improve, right? Because you get D&A, you have some other items like insurance proceeds and those things that add to some cash flow. Should we think about, hey, your earnings growth may slow down a little bit in the back end of this forecast because CapEx is just constant at the $6 billion level, but maybe your cash flow actually accelerates each year relative to the prior one?
There's a couple of things that are moving against sort of those assumptions. What we've seen is sort of an increase in the regulatory lag for cash recovery of certain items. One of the things that I would point to would be our expenditures for our wildfire prevention costs, which are pretty significant given the drought in the state. That generally has been taking us three years between the time we spend the money and when we collect it in rates. There are offsetting factors that I would point to that would offset the cash acceleration that you mentioned.
Got it. Okay. Thanks, guys. Much appreciated.
Thank you, Michael. Our next question comes from the line of Chris Turnure with J.P. Morgan. You may proceed.
Good morning. I wanted to focus on the equity needs for next year. You still have a pretty good range there of $200 million. What is embedded in that assumption in terms of proceeds from insurance on the Butte Fire or other factors that might move you to the top or bottom end of the range?
We continue to expect to seek recovery for all of our insured losses from insurers. There will be a timing lag between points in which we recognize the charge for the costs, when we actually pay those out, and when we collect them. Since they're mostly timing-related items, we'd expect to try to finance those as much as possible with short-term financing.
Okay. When you think about the GTNS 2011-2014 audit, you're kind of putting that into 2018 rate base right now. Is that a full assumption of the amount that's being reviewed, how can we think about the considerations that that audit group will be taking into consideration there?
Yeah. The $400 million reflects the full rate base impact subject to audit. We feel good about the spend. We feel it was prudent. We feel it was necessary. We're going to have to go through that audit. You're going to have to make your assumptions around any pushback that we'll receive from our regulators. We feel confident enough to have proposed it, we'll continue to seek recovery of it through the audit.
What about timing there? Is early 2018 a conservative assumption that could be accelerated?
There wasn't really a timing ascribed to the audit in the phase 1 gas transmission rate case. That's why we've conservatively moved the rate base impact to 2018. I think it's just going to be important to follow the timing of the audit here throughout 2017 to make assumptions on ultimate timing of collection.
Okay. That makes sense. Thanks.
Thank you. Our next question comes from the line of Michael Weinstein with Credit Suisse. You may proceed.
Hi, guys. Question on the $1 billion Grid Modernization Investment Plan. How much of that, or how much upside is there potentially when you look at that versus the distribution resource plans that are filed? Specifically, I'm thinking of the amount that you originally intended to spend on, let's say, for example, electric vehicles. That's been pared back, and I'm just wondering if there's more spending that you'd like to do beyond the $1 billion that just simply hasn't been approved yet, or that you're not planning on filing immediately. How long could that go out for?
Hi, Michael, this is Geisha. We've been at this grid modernization for quite some time now, and we've continued to be making investments for the last five, six years. What's reflected on page 20 is our estimate of the work that we intend to do through 2020. As we get more insights and we continue to work with the Commission on the DER Plan, on IDER and the DRP, there could be additional sort of changes along the way, but we would actually seek that recovery through future rate cases. I think in terms of an outlook through 2020, I think what we're showing on page 20 is accurate.
All right, not expected to change much then. Also on the equity range, just going back to that previous question, you said that the timing high versus low depends on insurance recoveries. Is that accurate?
No, I'm sorry. I wouldn't count the insurance recoveries for the Butte Fire in that equity issuance guidance. What I was referring to is there's going to be a timing difference between ultimately when we record the charge, when we pay out the cash, and when we collect it from insurers. Since that is largely a timing-related issue, financing those payments, we'll do so through short-term financing options.
Okay. What are the factors that vary between the high and the low end of the equity range for 2017?
I think there's going to be a lot of factors in terms of sort of timing of recovery. As I mentioned, I think we're seeing a trend towards a lag in cash recovery of certain expenditures, particularly, as I mentioned, wildfire prevention costs. Our last application for recovering those costs was about $200 million. We continue to accelerate the spend in terms of preventing wildfires here in the state because of the drought. There are assumptions on the recovery of cash that could push us to the upper end of that range.
Got you. Okay. Thank you.
Thank you, Michael. Our next question comes from the line of Anthony Crowdell with Jefferies. You may proceed.
Good morning. Just a question on CWIP. I guess prior to the San Bruno incident, I think CWIP was split, half went to shareholders, half went for below-the-line cost. As you've cleared maybe a lot of the issues related to the San Bruno incident, you've cleared them up. Is there still a need with this level of below-the-line costs?
It would be hard for us right now to say we could cut back on them. We still are dealing with some San Bruno issues. Also as we look forward, with this size of capital investment, we've got to make sure the public understands why are we investing in renewables, why are we investing in electric vehicles. I would be reluctant to say we could cut back on those costs in the next couple of years, certainly.
Okay. Just last question, and Anthony, you don't have the answer, that's fine. Just when you had started this endeavor of turning the company around, you had looked at a time frame of maybe three to four years. Kind of in five years, I think the slides today you put out really show how much the company has been transformed over that time. I mean, do you see yourself still around there through this transformation, or are you thinking other things?
I'm having a great time. I love seeing these slides. We pulled them together, and you know you're making progress, but when you lay them out, it's fun to see how things have come together. I talk to our board all the time about our talent development plans, and at some point they'll make a decision about transition, but I'm not going to speculate. I'm having too good of a time.
Great. Thanks for taking my question.
Thank you, Anthony. Our next question comes from the line of Praful Mehta with Citigroup. You may proceed.
Thank you, and thanks a lot for the slides. They are very helpful. A quick question on the business update. I guess an important component of that is just regulatory relationships. How do you see that having transitioned over this transformation? Are there any things that you're looking to achieve or any trackers that we should look for that would suggest where regulatory relationships stand today?
Well, hi, this is Steve Malnight. I would say we recognize that over the last several years, we've had a need to focus on rebuilding trust with our regulators and stakeholders externally. We have really made intensive efforts at that and are continuing to increase our engagement with commissioners, with staff, with interveners, all with a clear eye towards the ex parte rules and restrictions. I think that those kinds of efforts have really paid off as we are working on trying to settle key cases or other things. We're going to really continue on that path and keep moving forward. I think that between the commission and PG&E, we share tremendous common interests on ensuring that this company runs a safe, reliable, and affordable and clean system, and that's where we're going to keep working.
What I'd like to add, too, is if you look at the role of a regulator, I mean, they ultimately want to ensure that we're delivering safe and reliable service to our customers. When you look at the slide deck that's been put together and you look at the type of improvement that we've made over the last five or six years, we feel good about it, and we think it's a foundational basis of conversation with our regulators about the good work that we've done. I think that it's about making sure you're delivering great service to your customers, and that in turn, ultimately, we believe, leads to improved relationships with our regulator as well.
Gotcha. That's very helpful. Thanks. Secondly, in terms of retail rates, you've clearly pointed out that that's something that you're focused on, which makes sense. As you're looking forward post 2019, and you're looking at growth rates relative to keeping retail rates in check, is there a tapering off of the growth you see over time, balancing off these different considerations? How do you see that growth being maintained through the post-2019 period?
I think we're going to look at a lot of factors there. Tony mentioned earlier on the call the fact that we've potentially got some headroom associated with our expiring procurement contracts. Our focus is continuing to drive efficiency in our operations to keep our rates affordable. As we mentioned, the trends we're seeing for capital investment, we think are longer term and extend beyond this 2019 period. Our objective is to balance the need for that system investment while continuing to drive efficiencies in all aspects of the customer's bill.
There are structural things in rates that the commission has already laid out a roadmap. We anticipate that the number of tiers, which we collapsed down to 3 tiers, the commission is looking at in the next year or so collapsing that to 2 tiers. That eases some of the tension between our heavy energy users in the hot areas of the state, and that will be helpful. Also going to time of use rates, which the commission has said they intend to do in the 2019 timeframe for residential customers, actually before that for our commercial customers. All of these things will start to have an impact. We'll have to sort all of those out. It's a dynamic area, but we watch it very closely, so we don't get rates spiking in any part of the state.
Fair enough. Thank you, guys.
Thank you, Praful. Our next question comes from the line of Kevin Fallon with Citigroup. I'm sorry, Citadel. You may proceed.
Yeah. Hi. I had a question on slide 10 on the dividend that you guys are targeting in 2019 of $2.40. Are you guys implicitly trying to lead people to earnings power of $4 in 2019? Or does the roughly 60% payout range fall in the old guidance of 55%-65%?
I think we're not trying to lead there. We're trying to focus on a 60% payout ratio of our earnings in 2019, and our objective is to get there over the next several years.
It'd be wrong to infer that the $2.40 is a 60% payout of what you expect to earn in 2019?
That's correct. Yeah.
Okay. Thank you.
Thank you, Kevin. Our next question comes from the line of Travis Miller with Morningstar. You may proceed.
Hi, thank you.
Good morning.
I'm wondering, with respect to the grid modernization investments, the $1 billion, and then any other extra that might come of that, how do you think about rate recovery for that? Are you thinking GRC? Are you thinking other trackers? Is there something else completely different out there? How do we think about the recovery of that?
I think you should think of it in terms of the regular recovery we get through the GRC and the TO rate case. That's the approach we've taken over the last 6 to 10 years now. We have been investing in our grid at a pretty good clip. It's a big part of the reason we're seeing the improved reliability. As we look at future GRCs, that'll be the right mechanism for distribution infrastructure improvements, modernization, and then the TO cases for the transmission piece.
Got you. Are there any of these initiatives that you would expect to either request or get rate tracker treatment, an annual true-up type treatment?
Well, the one that's sort of a little bit different is probably the electric vehicle. That would be outside. It's a separate sort of filing. We're expecting to get a decision on that hopefully in the near term. That's an example of one that falls outside the GRC. There could be others. Right now we don't think of anything else. We really do like putting everything through the GRC and using the TO rate case for transmission as well.
Great. Appreciate it. Thanks.
You bet.
Thank you, Travis. There are currently no additional questions. Ladies, thank you.
All right. Great. Thanks, Monique, and thanks to everyone for joining us this morning. We look forward to seeing many of you next week at the EEI conference. Thank you.
Thank you, ladies and gentlemen, for attending the PG&E Corporation third quarter earnings conference call. This will now conclude the conference. Please enjoy the rest of your day.