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Sunrun Inc
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Good afternoon ladies and gentlemen and welcome to the Sunrun Second Quarter Financial Conference Call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. [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 www.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 MW 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 utility trade group, raise its CapEx forecast yet again just a few weeks ago.
EEI increased their utility CapEx projection for the next two 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 shut-offs.
These pain points, combined with the attraction of clean solar energy and battery storage, are driving consumers to engage meaningfully in their 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 helped replace a retiring fossil fuel power 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 GW of potential in California alone. This is the equivalent of 50 fossil fuel power plants or four times the size of the Diablo Canyon nuclear plant 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 the interconnection obstructions. We have now 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 nine states and Puerto Rico. We are encouraged by the growth in grid services programs offered by forward-thinking utilities that recognize consumer-centered solutions are a key path to decarbonizing.
Utilities in Vermont, Long Island and Massachusetts are now joining grid operators and 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 in 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 costs 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 and 110 mw 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 eight. 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 for 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 in Q2. In the second quarter we deployed 103 MW. 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 less 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 nine, 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 a range of 107 to 110 MWs.
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 will 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 five or more years, so they no longer included 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 non-recourse debt, rather than structured equity, we are able to retain upside on the portfolio overtime. 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 will begin to see incremental proceeds from these lower capital costs as we place into service newly built systems in this new lower interest rate environment.
In July, we re-priced $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 re-priced, 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 shareholders 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. Your line is open.
Thanks for taking my question. 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.
Yea, thanks for the question. There’s a lot of opportunity there, so we’re pursuing multiple ways to improve customer acquisition costs. So on the installation side, what you saw Q2 was a lot better efficiency and utilization. Now you know we may be pushed too hard at that, at the risk of you know the Q3 install potential that we could have achieve, but you saw that significant quarter-over-quarter improvement there.
You are going to see improvement in hardware pricing when the tariffs release and with more competition there. We are also expecting to see improvements from streamlining and automating the whole process, you know for permitting and interconnection which will create a lot faster of cycle times from our customers trying to install. This which is massively lower cost for the whole system. And then I think finally the customer and brand awareness that we will get with penetration will help.
So all of the paths that we’re pursuing across the board and there’s a lot of opportunities in each one of those. I would say in the short term what’s happening is the customer values are supporting the creation caught. So you know, so if you look at markets where there are lower customer values, the creation costs are also lower. So there’s economies 101 here with these attractive customers with our – with each one of our customers on an upcoming value that’s worth almost $10,000 to us, and so the costs support that.
You are also going to see as we discussed with this, you know sort of unprecedented in a while, and labor market there there’s you know pressure there and so what we have said is throughout the year we would expect you know modest improvement of creation costs but not big ones.
So the way I would summarize that is, you know we are very bullish on the opportunity to reduce and tighten those costs across the board. But in the short term, the project values and MPV are really strong and we’re going to see slight improvement, but I wouldn’t expect a significant improvement in the short run.
Yeah, that’s very helpful. I don’t know if this relates, but there were – one of the metrics that seem to be different in prior quarters was the average lease system size of about 8.5 kilowatts. Anything there, they are just mix. Maybe you can provide any comments there, also on the renewal value of, I thought $0.40 per watt, usually you are 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. So one that we are based in, that would be Texas, which is you know 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 the penetrate in markets like that you’re going to see the size improved. I think we’re also, always getting better at finding the more, you know more attractive customer and larger systems size is generally yield more profitable project. So we also, the customers are refining our model to achieve that as well.
On the renewal, I would say there is just you know variations you know quarter-to-quarter. We have also introduced you know 25 year contract in some places, whereas book value were exclusively 20 years. So that would cut you know that piece of the renewal in half in those instances.
Got it and last one from me, not sure if you can provide this, but how much of your ongoing revenue and/or retained values driven by SREC’s? We see the broader category of incentive revenue as well as some you know deferred revenue details, but the clean revenue number either nominally or as a percent of total, it’s a bit obfuscated and I’m just wondering if you can provide that?
So in the definition of any ANG, yeah, you are asking how much is attributed to SREC, right. So we’ve – I’m going to defer to Ed here to make sure I’m saying this correctly. But it’s just the contract what is actually contracted is reflected in that number. So un-contracted SREC, anything that we don’t have a contract for would be incremental to that data.
Got it. Thank you.
Our next question comes from the line of Philip Shen with ROTH Capital Partners. Your line is open. Your line is open.
We can come back to Phil. We can move to the next question, Operator.
Sure sir. The next question comes from…
Sorry guys, can you hear me okay?
Yeah, 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 – you know is up 10% to 20% sequentially over Q2. You know I think today your guidance is just 5% quarter-to-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.
Yeah, the way I would describe it is for the back half of the year we have visibility into the customer deployments overall that we are guiding to. So it does look like a steep ramp in Q4 based on the Q3 guidance, but it’s really just two components. Its 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 the two components in the backlog.
Okay, and you’re right, it is pretty steep for the implied Q4, call it 134 to 142 megawatt implied, you know that’s a 19% quarter over quarter growth rate for Q3. Do you expect – would you be able to reduce the labor tightness and cycle times enough to – you know to realize that Q4 guide and imply Q4 guide and what are the risks potentially around that?
We do. And again we, you know most importantly we have the visibility into the orders and the demand is there, and so we need to execute on hiring and/or you know 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 air it that way than having higher cost from under-utilization. So if you’re going to air one side we were you know maybe a little too tight on that, but you know the orders are there. So we believe we can execute to the capacity enhancement.
Okay, thanks Lynn. And then Ed you had mentioned in your remarks that you expect either in 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. Thanks.
Hi Phil. Yes, the Q4 anticipated transaction would include recently placed in service systems. So there would be tax equity in that transaction.
Great, thanks Phil. I think operator we can take the next question.
Our next question comes from the line of Brian Lee from Goldman Sachs. Your line is open.
Hi guys, its Rebecca here in on for Brian. Thanks for taking our questions. 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 we don’t get an extension until near year end.
Hi, 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 in on the requested 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 you know 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 you know 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 that occurs is likely to occur very close to the end of the year, you know potentially in connection with the appropriations bills or our tax expender bill.
There is a measure introduced to extend it just recently which we think if it were act – enacted in law would be in connection with other larger bills that will need to be considered by the Congress between now and the end of the year.
And I would just add, we are certainly of course planning the business to not count on that.
Okay thanks, and then it looks like there is a heavier mix of megawatts from channel partners during the quarter on then 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 perhaps what you are referring to is a higher mix of cash sale. So I think the cash sales increase from you know 15% to 17% or are you looking – you know because underlying the channel versus direct which we don’t break out. Our direct is actually growing faster than our channel business and so what that does to you over a period of time as you mention is reduce the funded installation costs.
I think the comp first is you know if you look at last year’s Q2 that was sort of – it was an unusual comp, just because in that quarter the project value was down and the cost was down and there was fluctuations from quarter-to-quarter. But if you look more normalized, you’ll see that it’s not really an outlet and in fact it’s down $0.08 versus Q1. So we would expect that direct business is growing faster; we expect that in flow costs will come down in line with that.
Okay thanks.
Our next question comes from the line of Michael Weinstein from Credit Suisse. Your line is open.
Hey, on a high level, are you guys comfortable with $1.15 per watt MPV as a target, you know especially as we see more battery employments in grid service modernization. I was wondering if that’s where you are thinking about landing going forward.
Are you saying more generally or for the year?
More generally.
Let me, I’ll answer both. So for the year we are pleased with ending in that area you know 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 you know earlier.
Over time we believe there is an opportunity to improve that, which is even in our core business. So you know we certainly do see opportunities to do that. It does also help, as I’d talked about in my commentary that utility prices continue to really ride with the CapEx increases. So you know there’s a lot of tailwinds on our ability to charge higher prices and there is cost reduction tailwinds as well. So we are getting benefit in both directions.
In terms of the potential on the grid services revenue, we are really encouraged by the movement on-grid serves 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 2000 plus in MPV per customer and we have a lot of proof points that really support that you know in our pipeline and in active discussion.
However, if you look at the percentage of our customers that are going to be with a grid services contract, you know that’s going to build slowly over time. So could it be 50% of our customers over – you know in the foreseeable future, yes. But it’s not going to be a meaningful percentage over the next couple of years.
Gotcha. And also could you comment a little bit on the labor tightness; is there an 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 sing it, it’s across the board, you know I think most acute. We were seeing it on the downstream insulation side and pretty acutely seeing it in markets, you know some key markets like California.
So it really is across the board in terms of sale people, staffing people in our home depot store, and on the construction side, so I would say across the board. I like our chances in that because we – you know I think we are developing a difference in talent brand and a company that people want to work towards.
In terms of the new home construction, I mean typically that is you know outsourced and there’s a lot of contractors that serve that market. So I think you know that market is fairly [inaudible] mix. You know home building as you know is quite cyclical. So I think they can ramp up and ramp down pretty easily and so I don’t think that influences it in a huge amount.
Great! I mean does this – do higher labor costs you know think that the dealer model might be more attractive at this point or is that not really part of the equation yet?
No, there will be no different. I mean that would flow though to a dealer just as it would flow through to Sunrun. I think if anything you know again developing a high quality place to work and a talent brand and you know and other sort of retention efforts are going to benefit some of the larger players like ourselves. So I could see that as a competitive dynamic favoring us, as compared to the dealers.
Okay, thank you.
Our next question comes from the line of Julien Dumoulin-Smith from Bank of America. Your line is open.
Good morning or good afternoon rather, I’m losing my mind. How are you guys?
Good. Good afternoon.
Excellent! So a quick question, given the meaningful proactive deenergization going on in California, specifically PG&E through the latest quarter and even today, can you discuss the customer demand inflection? I suppose you already alluded to a large backlog, if I quoted you right, there Lynn. What are you seeing in terms of the customer uptick? It seems there is some of the other public data points out there that seem to be very meaningful of very late, but I’d be curious what you’re actually seeing on the ground.
Yeah I think that those tailwinds will be huge, but they are mostly on the comp. So the two tailwinds, I mean maybe three tailwinds we are 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 are going to, so that’s going to cost them consumer pain.
You know two people are going to feel the pain of their power getting set-up, but they haven’t really felt that yet. It’s been a pretty small group of people so far and while fire season really is just on the comp, so I don’t think people have really suffered yet.
And then three, there is just a whole new appreciation from the dangers of climate change and just willingness for individual to own a chip in and make good decisions at their homes.
So those tailwinds are enormous and you know give us confidence that you know California has a ton of runaway. However, I would say that you know we’re just entering the fire season, we are on early days in this, and so you are not going to see the demand uptick in a meaningful way until people have been through a couple of outages.
But maybe to just clarify real quickly, I mean you talked about them huge and on the comp. 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 seeing some of these back outs. Are you really waiting for 3Q to see that uptick that’s materialized? And also maybe even within the storage component, because presumably this would be a solar amp storage sales rather than just a storage cell.
Right. Yeah, 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 expected to grow at that level. So it’s not, it’s not the single issue that’s moving us you know about into these fast growth rates. It’s not materially influencing our number 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 wouldn’t say it’s go stronger than wait and see. I would say customers, people, just need to live-it before they make a decision to you know put panels on the roof and a batter.
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, enter, barrier and scale advantage for us as entering into those PPT 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 back up power. But we’re also as being part of our virtual power plants are going to be able to monitor that battery, you know 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 you know the city of Los Angeles has come to help us replace this gap power plant, we endorsed Sunrun as our product. It really helps on the customer acquisition, on that customer acquisition costs in a pretty differentiated way. So we are very excited for the promise of these opportunity.
Alright, great. Well, thank you very much.
Thank you. One other thing I would add there that you will see in our 10-Q is that we’ve also expanded our capabilities to be able to develop slower and multifamily and low income buildings, which is part of the Oakland contract we won. So we are also working to bring a more comprehensive solution for these virtual power plant that we can put solar on our single family home, plus you know well income community, plus multifamily. So we can really provide more solar access. So we are excited about that progress on those efforts as well.
Great!
Thanks Julien.
[Operator Instructions] Next question comes from the line of Joe Osha from JMP Securities. Your line is open.
Hi everybody.
Hi Joe.
Hi Joe.
Hi. 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 deenergized, has anyone looked at the possibility when you deenergized a line of – will the ISO let you sort of iwind [ph] an entire community if you have a you know 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 residents-by-residents basis.
Yeah, I think we are absolutely working those opportunity. Now one of the things that – one of the reasons that we having success in the early days with the munis and the CPAs is they don’t have quite a good complex regulatory framework as you know some of the IOUs so. So I think there is some blocking and tackling to get through the market and the market mechanisms, where the market mechanisms are really working nicely for this than in the North East.
So the North East, is really so anybody who is competitive in California, the North East is crushing California on this. So they are already – you know the ISO [ph] is allowing batteries in to their wholesale capacity market. There’s multiple utilities that are setting up you know simple programs where we can plug our batteries into their you know capacity and ancillary services market, so that’s happening in the North East; 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 are working the regularity structures and the market structures to you know try to provide this kind of – because this thing totally make financial sense. Ed will probably want to add something.
Okay, so I would say there are two types of you know 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 are describing where you are ion the community is where the transmission line that’s at risk rather than necessary the distribution lines in that neighborhood.
So there is definitely a lot of interest in that and it will take you know some coordination between companies like ours and the utilities, but also largely the regulators to realize that. You know PG&E for an example you know sent an email to its customers encouraging them to buy portable generators.
So I think there is going to you know be a little bit of work in order to sort of realize the benefits and to manifest the benefits that filler and storage together can bring, but we do see that as a you know mid to longer term opportunity. Certainly in the meantime anyone can take action immediately to ensure the security and safety of their own system you know as on a standalone 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 contract still a positive NTV proposition for you guys.
More the latter. So we’ve been really consistently focused on you know generating day one cash, so really more the latter. I think there could be you know at these again. Its 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.
One kooky question and then one other one, so here’s the kooky one. Given the expertise you are developing and going to your munies and CCAs and your IOUs and so growth. Would you ever potentially be in the position of doing a sleeve for somebody else’s capacity. I mean you’ve had these companies that green charge and stand and what not putting batteries out there that they can’t monetized. Would you ever start aggregating other people’s capacity or is that just silly?
Hi Joe, this is Ed. So absolutely that is an opportunity and in fact several developers have called us to propose that, you know particularly I think C&I developers. And you know right now obviously where we are heading down, operationalizing everything for ourselves, but in certain instances we actually have partnered with other people and we do see that, you know as a growing opportunity over time, but one that we haven’t quite you know activate 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 subordinate lenders are lending to you one renewal or help me understand a little bit what the underpinning was there.
Sure. So obviously you know our lenders 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 you know fundamentally just as a debt instruments, what matters is the face value and the interest rate as far as we’re concerned and so we just see it as you know an instrument that is more than 100% of the contracted value out of certain interest rates. But potentially refinance – sorry, renewal revenues you know maybe necessary to repay the note if it were to you know fully amortize out you know over a multi decade period.
Okay, thanks. I could go on all day, but I’ll step aside. Thank you very much.
Thanks Joe.
Our last question comes from the line of Colin Rusch from Oppenheimer. Your line is open.
Thanks a lot guys. So you are looking at the portfolio, the potential capital partners and it sounds like you are moving closer to having more capital come earlier in the process, early in the life cycle. Can you give us a sense of the diversity of options that you have in front of you and you know particularly given the deal with that did with Con Edison, you know that sort of transaction where you have basically no cash up front and keep the equity steady seems pretty compelling from a cost to capital perspective.
Can you give us a sense of the depth and the breadths of options that you are evaluating and how we should think about the cost of capital and structure, evolution for Sunrun over the next, you call it four or six quarters.
Sure, so we are seeing a significant increase in depth of market. You know some data points there: You know the subordinated debt transaction priced pretty confident, at least 200 basis points below what we’ve seen from peers and you know 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, yeah know where I believe over a three to five year period of time you know we ought to be able to demand lower spreads than utility scale transaction given that they have a single week investment grade counterparty and certainly California utility has been an extreme example of that today.
We continue to see growing interest in the ABS market, the transaction you know that we cleared there had a number of new investors than we’ve seen, new investors come into the space during the year. When we replaced the bank deal that I mentioned you know we had seven lenders, that was a syndicated facility. We lost none of them in the reprising. So I’m very comfortable in the depth of market at the moment and the interest in the asset.
Okay, and then just on the technology side, you know certainly for a period of time there were a number of companies looking at figuring out how to shorten the 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 you know migration to different technology solution?
Yeah, there are opportunities certainly, so you know there’s still a lot of physical visits to the home as an example. So you know sales person to the home is also typically for most of them you would need to send a subsequent person out there to examine features, the roof and things. So there is 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 shipped a clear, you know on-side if you shave an hour or two that’s helpful, but that’s really not quite as meaningful. The more meaningful you know reduction in the overall creation costs I think will come as the industry moves from say if you know a 60 day cycle time from a customer side to getting installed where there’s a lot of time to go back and forth.
A lot of customer question, you know customer apathy and things and moving it tighter to you know what you see in international markets where someone signs up and they get installed you know seven 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, [inaudible] to try to get the online and automated permitting interconnection rules, so that we can really tight those times.
Thanks, 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 year and are you marking those investments now and should we start to seeing those in the financials?
No, you know 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.
Thanks a lot.
Thanks Colin.
There are no more questions at this time. I would now like to turn the call back to Lynn Jurich.
Alright! Well, with that we’ll get back to work increasing our capacity for installations and look forward to talking to you guys next week, excuse me next quarter.
Ladies and gentlemen, this concludes today's conference. Thank you for your participation and have a wonderful day! You may all disconnect.