Sunrun Inc (RUN) 2019 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Sunrun second quarter financial conference call.

(Operator Instructions) As a reminder, this conference call is being recorded.

I would now like to turn the conference over to your host, Patrick Jobin.

You may begin, sir.

Thank you, operator, and thank you to those on the call for joining us today.

Before we begin, please note that certain remarks we will make on this conference call constitute forward-looking statements, although we believe these statements reflect our best judgment based on factors currently known to us, actual results may differ materially and adversely.

Please refer to the company's filings with the SEC for a more inclusive discussion of risks and other factors that may cause our actual results to differ from projections made in any forward-looking statements.

Please also note, these statements are being made as of today, and we disclaim any obligation to update or revise them.

On the call today are Lynn Jurich, Sunrun's Co-Founder and CEO; Bob Komin, Sunrun's CFO; and Ed Fenster, Sunrun's Co-Founder and Executive Chairman.

The presentation today will use slides, which are available on our website at investors.sunrun.com.

And now let me turn the call over to Lynn.

Thanks, Patrick.

We are pleased to share Sunrun's second quarter results and progress against our strategic priorities.

In the quarter, we added 12,600 customers representing 103 megawatts of deployments, a 13% year-over-year improvement.

We generated $95 million of net present value and created NPV per watt of $1.11 or $9,500 per customer.

We generated $44 million in cash, and since the last call, have achieved record low capital costs in our financings.

Sunrun offers households a superior energy experience and our value proposition continues to increase.

We were not surprised to see EEI, the utilities trade group, raise its CapEx forecast yet again just a few weeks ago.

EEI increased their utility CapEx projection for the next 2 years by 15% from their prior estimates.

It now tops $250 billion and is at all-time highs.

With limited growth in energy consumption and this significant increase in spending, doubled depreciation expense, will likely be passed to consumers in the form of higher electricity rates.

At the same time, many customers are experiencing unreliable service exacerbated by extreme weather and forced power shutoff.

These pain points, combined with the attraction of clean solar energy and battery storage, are driving consumers to engage meaningfully in our personal energy usage for the first time.

Solar is proving to be a unique access point to obtain significant relationships with customers.

Today, I want to highlight the California market to show how much customer growth lies ahead and how distributed assets will help create a more resilient clean system.

First, our modeling shows that in California, we are just now exiting the early adopter phase and moving into the early majority phase, an area of the curve that is twice the size of the earlier segments.

Second, the California mandate for new homes will be additive to the growth during the next few years.

Both from new home construction and the increased category awareness, it will bring as home solar and batteries become mainstream.

We are engaged in conversations or contracted with half of the top 10 homebuilders in California and are gaining share.

Finally, many Californian communities are racing to retire fossil fuel plants and replace them with virtual power plants comprised of solar and battery storage.

Los Angeles, Glendale and Oakland are recent examples.

Sunrun is positioned to win with our Brightbox offering, targeted customer acquisition capabilities and growing density and scale advantages.

In July, we added to our Energy Services award in ISO New England with another landmark contract in Oakland.

This contract helps replace a retiring fossil fuel plant with home solar and battery systems on low income housing.

The contract is particularly meaningful because it will help disadvantaged communities who often experience the harmful impact of fossil fuel pollution the most.

Furthermore, it shows that Community Choice Aggregators in California are starting to realize that home solar and batteries are a valuable and cost-effective resource planning tool.

For context, the virtual power plant opportunity could be 9 gigawatts of potential in California alone.

This is the equivalent of 50 fossil fuel power plants or 4x the size of the Diablo Canyon nuclear plants slated to retire in 2025.

We expect other states will follow this trend.

Because of the huge potential of battery storage paired with solar, we continue to invest in Brightbox, even though it is causing short-term headwinds from slower install times, an immature supply chain and permitting and interconnection obstructions.

We now have installed more than 6,000 Brightbox battery systems and continue to expect demand is ready to unleash with anticipated cost reductions and severe climate events.

We recently expanded Brightbox to Texas, New Jersey and Vermont, and the service is now available in 9 states and Puerto Rico.

We are encouraged by the growth in grid services programs offered by forward-thinking utilities that recognize customer-centric solutions are a key path to decarbonizing.

Utilities in Vermont, Long Island and Massachusetts are now joining grid operators in offering programs that enable batteries to participate in capacity markets and other grid services revenue streams.

Brightbox represents over 10% of our direct business overall and more than 25% in California.

Our market position and long-term potential continues to improve.

Customer demand and our order book are strong.

We are forecasting more than 20% annual growth in orders for Q3, and our direct business continues to grow much faster than that.

However, the tight labor market is making timely hiring in our direct business more challenging than we expected, resulting in growing backlogs.

So on the positive side, our focus on efficiency resulted in cost improvements.

You can see that Sunrun Built cost improved 7%, both year-over-year and from Q1, despite wage increases, tariffs and increased battery mix.

However, we are behind our staffing plan required to realize customer demand in Q3.

We are also prioritizing Brightbox, which we believe is the right long-term decision, but creates longer cycle times and requires additional crew training.

We expect to deploy between 107 to 110 megawatts in Q3.

We are working to increase capacity to reduce backlog in Q4 and realize the expected growth in orders.

I'll now turn the call over to Bob, our CFO, to review Q2 performance and to discuss guidance in more detail.

Thanks, Lynn.

NPV in the second quarter was approximately $9,500 per customer or $1.11 per watt, an improvement of $0.13 from a year ago and up $0.05 from Q1.

Project value was approximately $37,900 per customer or $4.44 per watt in Q2.

As a reminder, project value is very sensitive to modest changes in geographic, channel and tax equity fund mix.

Turning now to creation costs on Slide 8. In Q2, total creation costs were approximately $28,400 per customer or $3.33 per watt, an improvement of $0.13 or 4% from last quarter.

We expect creation costs will continue to improve from Q2 levels in the second half of this year.

As with project value, creation costs can fluctuate quarter-to-quarter.

As a reminder, our cost tax is not directly comparable to those of our peers because of our channel partner business.

Blended installation cost per watt, which includes the costs of solar projects deployed by our channel partners as well as installation costs incurred by Sunrun Built systems, was $2.50 per watt, an $0.08 improvement from last quarter.

Install costs for systems built by Sunrun improved by $0.13 or 7%, both sequentially and year-over-year, to $1.82 per watt.

In Q2, our sales and marketing costs were $0.80 per watt, up $0.02 from Q1.

Our total sales and marketing unit costs are calculated by dividing costs in the period by total megawatts deployed.

A higher mix of direct business results in higher reported sales and marketing costs per watt, but it also means there will be lower blended installation costs per watt over time due to the higher mix of direct business installations at the lower cost per watt.

In Q2, G&A costs were $0.28 per watt, an improvement of $0.01 from Q1.

Finally, when we calculate creation costs, we subtract the GAAP gross margin contribution realized from our platform services.

This includes our distribution, racking and lead generation businesses as well as solar systems we sell for cash or with a third-party loan.

Our platform services gross margin was $0.25 per watt, Q2.

In the second quarter, we deployed 103 megawatts.

Our cash and third-party loan mix was 17% in Q2 in line with recent levels.

We expect this mix to continue in the high teens for the rest of the year.

Turning now to our balance sheet.

We ended the second quarter with $354 million in total cash, a $44 million increase from last quarter.

We continue to expect cash generation of over $100 million in 2019.

Quarterly cash generation can fluctuate due to the timing of project finance activities, but this represents our best view based on our plans for the remainder of the year.

We define cash generation as the change in our total cash plus the change in recourse debt.

Also, please note that our cash generation outlook excludes any strategic opportunities beyond our current plans and also does not include ITC safe harboring activities.

Moving on to guidance on Slide 9. We continue to expect full year 2019 deployments to grow between 16% and 18%.

As our direct business outpaces our overall growth rate, more expenses are front-loaded for sales and deployment capacity.

The dynamics of a tight labor market and more front-loaded expenses puts pressure on NPV and cash generation.

Despite this, we still expect to generate $100 million or more in total cash for 2019 and to exceed last year's $1.08 NPV result.

We also expect to be in the range of our previous $1.15 NPV target for the year.

As mentioned earlier, in the third quarter, we expect deployments to be in the range of 107 to 110 megawatts.

Now let me turn it over to Ed.

Thanks, Bob.

Today, I plan to discuss our recent project finance activities along with our capital strategy for the remainder of 2019.

I'll also touch on net earning assets and capital runway.

Reductions in long-term interest rates and growing interest in residential solar assets are causing capital costs and advance rates to improve across the entire capital stack.

Since our last call, we executed transactions in the ABS market, bank market and subordinated debt market, all on record terms.

In May, we completed a securitization of assets that have been operating for 5 or more years, so they no longer include a tax equity investor.

The notes were priced at a 4% yield with an 80% advance rate.

The advance rate of 80% is nearly 10 percentage points higher than the senior tranche in Sunrun's prior securitization and represents the highest advance rate for any similarly rated tranche in a solar lease and PPA transaction to date.

The yield of 4% is the lowest yield for any solar lease and PPA transaction to date.

Combined with the subordinated debt on the transaction, which brought the total proceeds to over 100% of the portfolio's contracted gross earning assets, the weighted average cost of debt was 5.75% or 6.17%, including all fees.

This transaction presents another data point in support of using a 6% discount rate to calculate asset value.

Since we are now able to structure these trends, these sorts of facilities solely as nonrecourse debt rather than structured equity, we're able to retain upside on the portfolio over time.

Although we received significant gross proceeds in this refinancing, net proceeds were materially reduced by swap breakage costs.

As we've discussed before, when refinancing a hedged portfolio, we don't materially benefit when base interest rates fall, and we likewise aren't materially harmed when they rise.

We'll begin to see incremental proceeds from these lower capital costs as we place in service newly built systems in this new lower interest rate environment.

In July, we repriced $229 million of bank debt.

We reduced the spread to LIBOR plus 212.5 basis points from 275, stepping up over time to 300 basis points.

We also increased the advance rate from 68% to 72%.

We repriced rather than refinanced this facility for expediency into lower transaction-related costs.

We expect to execute another debt transaction in either the ABS or bank market during Q4 depending on market conditions.

Moving to Slide 10.

At quarter-end, net earning assets was $1.4 billion, an increase of $139 million or 11% year-over-year.

Net earning assets is our way to describe the value of the cash flows to Sunrun shareholder after payments to financing counterparties.

Cash was $354 million.

Total cash less recourse debt increased $91 million from the prior year period and increased $44 million from Q2.

Turning finally to our pipeline.

Our project debt commitments provide runway through 2019 while our tax equity commitments extend into the second quarter of 2020.

And with that, I'll turn the call back over to Lynn.

Thank you, and we'll now open it up for questions.

(Operator Instructions) Our first question comes from the line of Moses Sutton from Barclays.

In light of the recent events, there's been a reinvigorated focus on creation cost.

Despite maybe a bit of headwinds this quarter, you've averaged a 7% decline since 2015, can you review your base case views on how much further this could go?

In future years, how this might be affected by Brightbox, maybe any broader commentary on creation cost over time and its mix?

Yes, thanks for the question.

We -- there's a lot of opportunity there.

So we're pursuing multiple ways to improve the customer acquisition cost.

So on the installation side, what you saw in Q2 was a lot better efficiency and utilization.

Now we maybe even push too hard at that at the risk of the Q3 install potential that we could have achieved, but you saw that significant quarter-over-quarter improvement there.

You're going to see improvements in hardware pricing when the tariffs release and with more competition there.

We're also expecting to see improvements from streamlining and automating the whole process through permitting and interconnection, which will create a lot faster of cycle times from a customer sign to install, which is massively lower cost for the whole system.

And then I think, finally, the customer and brand awareness, that we will get -- the penetration will help.

So all of those are the path that we're pursuing across the board, and there is a lot of opportunity in each one of those.

I would say, in the short term, what's happening is the customer values are supporting the creation costs.

So if you look at markets where there are lower customer values, the creation costs are also lower.

So there is a economics 101 here, where with these attractive customers with our -- each one of our customers on a net present value is worth almost $10,000 to us and so the costs support that.

You're also going to see, as we discussed, with this sort of unprecedented, in a while, anyway, labor market, there is pressure there.

And so what we -- I've said is throughout the year, we would expect modest improvements of creation costs but not big ones.

So the way I would summarize that is, we're very bullish on the opportunity to reduce and tighten those costs across the board.

But in the short term, the project values and NPVs are really strong, and we're going to see slight improvements, but I wouldn't expect significant improvements in the short run.

That's very helpful.

I don't know if this relates, but there were -- one of the metrics that seem to be different than prior quarters, was the average lease system size of about 8.5 kilowatts.

Anything there?

Is it just mix?

And maybe you could provide any comments there?

Also on the renewal value, I saw $0.40 per watt, usually you're more in the $0.50 range based on your calculation?

Got it.

I'll take the system size.

There are some of the newer markets that we are growing and do tend to have larger system size.

One that where they standout would be Texas, which is a market where people use a lot of air conditioning and have bigger houses than in California.

So I think as you -- as the mix starts to penetrate in markets like that, you're going to see the size improve.

I think we're also always getting better at finding the more attractive customers, and larger system sizes generally yield more profitable projects.

So we also -- we're constantly refining our models to achieve that as well.

On the renewal, I would say there's just variations quarter-to-quarter.

We have also introduced 25-year contracts in some places, whereas before we were exclusively 20 years.

So that would cut that piece of the renewal in half in those instances.

Got it.

And last one from me.

I'm not sure if you can provide this, but how much of your ongoing revenue and/or retain value is driven by SRECs?

We see the broader category of incentive revenue as well as some deferred revenue details, but the clean revenue number either nominally or as a percent of total, it's a bit obfuscated.

I'm just wondering if you can provide that.

So in the definition of any A&G, you're asking how much attributed to SRECs.

So we -- I'm going to defer to Ed here to make sure I'm saying this correct, it's just the contracted, what is actually contracted is reflected in that number.

So uncontracted SRECs, anything that we don't have a contract for would be incremental to that data.

Our next question comes from the line of Philip Shen from Roth Capital Partners.

We can come back to Phil, move to the next question, operator?

Sure, sir.

Sorry, guys.

Can you hear me okay?

Yes, we can hear you now, Phil.

Okay.

Great.

Okay.

Sorry about that.

So first question is on the Q3 guide.

How many megawatts do you think you left on the table as a result or do you think you will have left as a result of the longer cycle times and so forth?

Historically, your Q3 guide is between -- is up 10% to 20% sequentially over Q2.

And I think, today, your guidance is just 5% quarter-over-quarter.

So I'm guessing it's the cycle times, the tight labor market and so forth.

But what could it have been had -- you didn't have to deal with those issues?

Yes.

The way I would describe it is, we -- for the back half of the year, we have visibility into the customer deployments overall that we're guiding to.

So it does look like a steep ramp in Q4 based on the Q3 guidance, but it's really just 2 components.

It's reducing the backlog that we've accumulated and then the actual Q4, and then a pretty organic Q4 growth rate to hit the overall number.

So that's how I would describe those 2 components in the backlog.

Okay.

And you're right, it is pretty steep for the implied Q4, call it, 134 to 142 megawatts implied.

That's a 19% quarter-over-quarter growth rate from Q3.

Do you expect to be able to reduce the labor tightness and cycle times enough to realize that Q4 guide and -- implied Q4 guide?

And what are the risks potentially around that?

We do.

And again, we -- most importantly, we have the visibility into the orders and the demand is there.

And so we need to execute on hiring and/or finding third-party capacity to realize that.

I think, ideally, we wouldn't be exiting Q3 with such a large backlog, but we'd really rather err that way than having higher cost from underutilization.

So if you're going to err on one side, we were maybe a little too tight on that, but the orders are there.

So we believe we can execute to the capacity enhancements.

Okay.

And then, Ed, you had mentioned in your remarks that you expect either an ABS or, I think, bank financing in Q4.

If you were to do an ABS, do you expect it to be pre-flip assets?

Or if not, what kind of asset base do you expect for the Q4 ABS?

Phil, yes, the Q4 anticipated transaction would include recently placed in service systems, so there would be tax equity in that transaction.

Okay.

Thanks, Phil.

I think, operator, we can take the next question.

Our next question comes from the line of Brian Lee from Goldman Sachs.

It's Rebecca Yuan on for Brian.

So can you provide some details on your ITC safe harbor strategy?

And maybe thoughts on the odds of an extension?

And then are you able to position for both outcomes if say we don't get an extension until near year-end?

This is Ed.

Great question.

So first, we are planning to avail ourselves of the IRS safe harbor rules by carrying excess inventory into next year, which obviously would extend our access to the 30% credit.

We've begun accumulating small amounts of this inventory already and are on track to close a nonrecourse credit facility for the equipment in Q4.

We are doing our best to structure it such that whether or not there is an ITC extension.

We have kind of covered our bases in terms of risk and profit.

And some of that we view proprietary, but we'd be happy to discuss on a subsequent call.

To your question about the odds of an ITC extension, I think our best thinking is still that's probably about 25%.

And if it occurs, it's likely to occur very close to the end of the year potentially in connection with the appropriations bills or a tax extender bill.

There was a measure introduced to extend it just recently, which we think if it were enacted in law would be in connection with other larger bills that are -- that will need to be considered by the congress between now and the end of the year.

And I would just add, we're certainly, of course, planning the business to not count on them.

Okay.

And then it looks like there was a heavier mix of megawatts from channel partners during this quarter than where it's been trending recently.

And so just how should we think about the mix going forward and the reduction in the blended cost per watt?

So the -- perhaps what you were referring to is there's a bit of a higher mix of cash sales.

So I think -- believe the cash sales increased from 15% to 17%.

Or are you looking -- because we had underlined the channel versus direct, which, as you know, we don't break out.

Our direct business is actually growing faster than our channel business.

And so what that does do over a period of time, as you mentioned, is reduce the blended installation costs.

I think the comp, first, is if you look at last year's Q2, that was sort of -- it was unusual comp just because in that quarter, the project value was down and the cost was down.

And that wasn't -- there is fluctuations from quarter-to-quarter.

But if you look more normalized, you'll see that it's not really an out letter.

And in fact, it's down $0.08 versus Q1.

So we would expect that.

The direct business is growing faster.

We expect that, that input cost will come down in line with that.

Our next question comes from the line of Michael Weinstein from Crédit Suisse.

On a high level, are you guys comfortable with $1.15 per watt NPV as a target, especially as we see more battery deployments and grid service modernization?

Just wondering if that's where you're thinking about landing going forward?

You're saying more generally or for the year?

More generally.

Let me -- I'll answer both.

So for the year, we're pleased with ending in that area.

As Bob said there is -- in that number, there's a lot of fast growth in our direct business, which puts some pressure on it because we do recognize the expenses earlier.

Over time, we do believe there's the opportunity to improve that just even in our core business, so we certainly do see opportunities to do that.

It does also help, as I talked about in the commentary, that utility prices continue to really rise with these CapEx increases.

So there's a lot of tailwinds on our ability to charge higher prices, and there's cost reduction tailwinds as well.

So we're getting benefit in both directions.

In terms of the potential on the grid services revenue, we're really encouraged by the movement in the -- on grid services with utilities and with some of the meetings in California.

So that continues to be an opportunity.

We're very bullish about, but it's going to take a little while to build.

So we estimate that grid services can add 2,000 plus in NPV per customer, and we have a lot of proof points that really support that in our pipeline and an active discussion.

However, if you look at the percentage of our customers that are going to be with a grid services contract, that's going to build slowly over time.

So could it be 50% of our customers over -- in the foreseeable future?

Yes, but it's not going to be a meaningful percentage over the next couple of years.

Got you.

And also, could you comment a little bit on the labor tightness?

Is that in installation or sales and customer acquisition?

Where are you really seeing that showing up?

And also, what happens with that next year as the California rooftop mandate starts to really kick in and that market starts to expand?

That's a good question on the rooftop expansion.

I think in terms of your first question on where you're seeing it.

It's across the board.

I think most acutely, we're seeing it on the downstream installation side and pretty acutely seeing it in markets, some key markets like California.

So it really is across the board in terms of salespeople, staffing people in our Home Depot stores.

And on the construction side, so I would say, across the board.

I like our chances in that because we -- I think we're developing a differentiated talent brand and a company that people want to work towards.

In terms of the new home construction, I mean, typically, that is outsourced.

And there is a lot of contractors that serve that market.

So I think that market is fairly boom and bust and -- home building, as you know, it's quite cyclical.

So I think they can ramp up and ramp down pretty easily on that.

So I don't think that influences it in a huge amount.

Great.

And I mean does this -- do higher labor costs make you think that the dealer model might be more attractive at this point?

Or is that not really part of the equation yet?

No, there would be no difference.

I mean that would flow through to a dealer just as it would flow through to Sunrun.

I think if anything, again, developing a high-quality place to work and a talent brand and other sort of retention efforts are going to benefit some of the larger players like ourselves.

So I would -- I could see that as a competitive dynamic favoring us as compared to the dealers.

Our next question comes from the line of Julien Dumoulin-Smith, Bank of America.

So a quick question.

Given the meaningful proactive de-energization is going on in California, specifically PG&E through the latest quarter and even today, can you discuss the customer demand inflection?

I suppose you've already alluded to a large backlog, if I quoted you right there, Lynn.

What are you seeing in terms of customer uptick?

It seems there's some -- some of the other public data points out there seem to be very meaningful of very late, but I'd be curious what you're actually seeing on the ground?

Yes.

I think that those tailwinds will be huge, and -- but they're mostly on the come.

So I mean the 2 tailwinds -- I mean maybe 3 tailwinds we're going to get from that is: one, electricity prices are going to have to increase.

And we haven't seen those really flow through like as they're going to.

So that's going to cause some consumer pain.

Two, people are going to feel the pain of their power getting shut off, but they haven't really felt that yet.

It's been pretty small group of people so far, and wildfire season really is just on the come.

So I don't think people have really felt it yet.

And then three, there's just a whole new appreciation from the dangers of climate change and just willingness for individuals to want to chip in and make good decisions at their homes.

So those tailwinds are enormous and give us confidence that California has a ton of runway.

However, I would say that we're just entering the fire season, we're on early days in this, and so you're not going to see the demand uptick in a meaningful way until people have been through a couple outages.

But maybe to just clarify real quickly.

I mean you talked about them huge and on the come.

Have you seen an uptick even in the isolated geographies that have experienced this?

I mean is this something that is perceivable in your numbers as you look at them, where you have seen some of these blackouts?

Or you're really waiting for 3Q to see that uptick that's materialized?

And also maybe even within this -- the storage component because presumably this would be a solar and storage sale rather than just a solar sale?

Right.

Yes, I mean, the way I would answer that, so we expect our order volume to grow 20% year-over-year in Q3.

Independent of this outages, I would still expect it to grow at that level.

So it's not the single issue that's moving us above into these fast growth rates.

So it's not materially influencing our numbers in the current quarter or even over the next couple of quarters.

I do believe it will, but it's not materially changing things this quarter or next quarter.

Got it.

More of a wait and see, but it seems like a good tailwind kind of thing?

I would say -- go stronger than wait and see.

I would say, customers, people just need to live it before they make a decision to put panels on the roof and a battery.

If I can, just one more real quickly.

Can you discuss the opportunity to leverage like the Oakland contract and other similar constructs around expanding your CCA penetration to existing customers in a more enhanced customer acquisition venue?

Absolutely.

I think this is another entry barrier and scale advantage for us is entering into these VPP programs because what we're going to be able to do is offer our customers all the benefits of the solar plus storage, which is cleaner, cheaper, energy plus backup power, but we're also, as being part of our virtual power plants, they're going to be able to monetize that battery for additional value.

So it just enhances the customer value proposition.

The other thing it does is it gives you a marketing and urgency message to the consumer.

So now if the city of Los Angeles have come help us replace this gas power plant, we've endorsed Sunrun as our provider.

It really helps on the customer acquisition -- on the customer acquisition costs in a pretty differentiated way.

So we are very excited for the promise of these opportunities.

One other thing I would add there that you'll see in our 10-Q is that we've also expanded our capabilities to be able to develop solar on multifamily and low-income buildings, which is part of the Oakland contract we won.

So we're also working to bring a more comprehensive solution for these virtual power plants, so we can put solar on our single-family homes plus low-income communities plus multifamily, so we can really provide more solar access.

So we're excited about the progress on those efforts as well.

(Operator Instructions) Next question comes from the line of Joe Osha from JMP Securities.

Kind of following on Julien's line of questioning there for a moment.

When you look at some of these communities that are out there in areas that are at risk of being de-energized.

Has anyone looked at the possibility when you de-energize the line of -- will the ISO let you sort of island an entire community, if you have a capacity arrangement in place?

Is that type of thing possible?

Or is the protection or the backup power, if you will, still going to be available only on a residence-by-residence basis?

Yes.

I think we're absolutely working those opportunities.

Now one of the things that -- the one of the reasons why we're having success in the early days with the munis and the CCAs is they don't have quite as a complex regulatory framework.

As some of the IOUs do.

So I think there is some blocking and tackling to get through that -- those -- the market and the market mechanisms.

Where the market mechanisms are really working nicely for good services in the Northeast.

So the Northeast is really -- so anybody who's competitive in California, the Northeast is crushing California on this.

So they're already -- the ISO New England is allowing batteries into their wholesale capacity market.

There is multiple utilities that are setting up simple programs where we can plug our batteries into their capacity and ancillary services market.

So that's happening in the Northeast.

That's going to be a model.

In California, where the early wins and the early attention to this are really through the CCAs and the munis.

And then at the same time, we're working the regulatory structures and the market structures to try to provide these kind -- because they totally make financial sense.

Ed will probably want to add something.

Okay.

Yes.

So I would say there are 2 types of customers who could be impacted by a blackout.

You can have a community that is at the end of a long transmission or distribution line that is at risk in fires or you can have a community whose actual wires are in a risky spot.

So the best opportunity for the micro grid, which is what you're describing where you island the community, is where it's the transition line that's at risk rather than necessary the distribution lines in that neighborhood.

So there's definitely a lot of interest in that.

And it will take some coordination between companies like ours and the utilities, but also largely the regulators to realize that.

PG&E, for an example, sent an e-mail to its customers encouraging them to buy portable generators.

So I think there's going to be a little bit of work in order to sort of realize the benefits and to manifest the benefits that solar and storage together can bring, but we do see that as a mid- to longer-term opportunity.

Certainly, in the meantime, anyone can take action immediately to ensure the security and safety of their own system as -- on a stand-alone basis.

Okay.

And then kind of as a follow-on from that, when you are looking at how you think about pricing Brightbox at this point, is there kind of an implicit assumption there that there will be some additional monetization from grid services?

Or is Brightbox just with the initial contracts still a positive NPV proposition to you guys?

More the latter.

So we've been really consistently focused on generating day 1 cash.

So really more of the latter.

I think there could be -- as these -- again, it's market-by-market, a judgment call on how likely you think those revenues are going to be.

But we've taken -- we've been a little more conservative on that.

Okay.

One kooky question and then one other one.

Here's the kooky one.

Would -- given the expertise you're developing in going to munis and CCAs and IOUs and so forth, would you ever potentially be in the position of doing a sleeve for somebody else's capacity?

I mean you've had these companies like Green Charge and Stem and whatnot putting batteries out there that they can't monetize.

Would you ever start aggregating other people's capacity?

Or is that just silly?

Joe, this is Ed.

So absolutely, there is an opportunity.

And in fact, several developers have called us to propose that, particularly I think C&I Developers.

And right now, obviously, we're heads down, operationalizing everything for ourselves.

But in certain instances, we actually have partnered with other people.

We do see that as a growing opportunity over time, but one that we haven't quite activated on the priority list yet.

Okay.

And then the last one, Ed, for you, that comment you made on the ABS deal with the subordinated debt on it being more than 100% of contract, does that mean that subordinated lenders are lending to you on renewal?

Or help me understand a little bit what the underpinning was there?

Sure.

So obviously, a lender's base case, I don't always see.

So their exact assumptions are uncertain to me.

But my assumption is that there is value being provided to the renewal portion.

But I think fundamentally, just as a debt instrument, what matters is the face value and the interest rate as far as we're concerned.

And so we just see it as an instrument that is more than 100% of the contracted value at a certain interest rate, but potentially refinance -- sorry, renewal revenues may be necessary to repay the note, if it were to fully amortize out over a multi-decade period.

Our last question comes from the line of Colin Rusch, Oppenheimer.

So you're looking at the portfolio or the potential capital partners.

And it sounds like you're moving closer to having more capital come earlier in the process -- earlier in the life cycle?.

And can you give us a sense of the diversity of options that you have in front of you?

And particularly given the deal that you did with Con Edison, that sort of transaction, where you have basically no cash up front and keep the equity stub seems pretty compelling from cost of capital perspective.

But can you give us a sense of the depth and the breadth of options that you're evaluating?

And how we should think about the cost of capital and structure evolution for Sunrun over the next, call it, 4 or 6 quarters?

Sure.

So we're seeing significant increase in depth of market, some data points there.

The subordinated debt transaction priced, I'm pretty confident, at least 200 basis points below what we've seen from peers and was a competitive process with a great deal of interest.

Although interestingly, it's still probably 200 basis points above what you might see in utility scale transactions where, I believe, over a 3- to 5-year period of time, we ought to be able to demand lower spreads than utility scale transactions given that they have a single week investment-grade counterparty.

And certainly, California utilities are an extreme example of that today.

We continue to see growing interest in the ABS market, the transaction that we've cleared there had a number of new investors, and we've seen new investors come into the space during the year.

When we repriced the bank deal that I mentioned, we had 7 lenders.

That was a syndicated facility.

We lost none of them in the repricing.

So I'm very comfortable in the depth of market at the moment and the interest in the assets.

Okay.

And then just on the technology side, certainly, there for a period of time were a number of companies looking at figuring out how to shorten installation times through new devices.

Do you see real innovation happening in that area at this point?

And is there a way to mitigate some of that labor tightness through migration to different technology solutions?

Yes, there are opportunities, certainly.

So there's still a lot of physical visits to the home, as an example, so sales person to the home.

There's also typically, for most homes, you would need to send a subsequent person out there to examine features, the roof and things.

So there's solutions like drones and other things that are showing some promise to eliminate some of that.

So that's one example.

The installation, like once you've shipped a crew on-site if you shave an hour or 2, that's helpful, but that's really not quite as meaningful.

The more meaningful reduction in the overall creation cost that I think will come as the industry moves from, hey, it's a 60-day cycle time from a customer sign to it getting installed, where there is a lot of time to go back and forth.

A lot of customer questions, customer apathy and things and moving it tighter to what you see in international markets where someone signs up and they get installed 7 days later.

That's what really is going to help eliminate a lot of the waste.

And I think we are making good -- slow but good progress AHJ by AHJ to try to get the online and automated permitting and interconnection rules, so that we can really tighten those times.

And then just one final question for me.

Just in terms of continuing the growth trajectory, do you guys feel like you need to expand geographies to support growth into next year?

And are you making those investments now?

And should we start seeing those in the financials for the remainder?

No.

Any -- strong growth next year is not -- does not necessitate geographic expansion.

So we would not -- we would expect deeper in our existing markets versus big geo expansion.

There are no more questions at this time.

I would now like to turn the call back to Lynn Jurich.

All right.

Well, with that, we'll get back to work increasing our capacity for installations and look forward to talking to guys next week -- excuse me, next quarter.

Ladies and gentlemen, this concludes today's conference.

Thank you for your participation.

Have a wonderful day.

You may all disconnect.