Sunrun Inc (RUN) 2018 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q1 2018 Sunrun Inc.

Earnings Conference Call.

(Operator Instructions)

As a reminder, this conference may be recorded.

I would now like to turn the conference over to your host, Mr. Patrick Jobin, Vice President of Investor Relations.

Sir, you may begin.

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 that 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 with you Sunrun's first quarter financial and operating results along with progress against our strategic priorities.

People want the freedom to take control of their energy and improve their families' lives.

We are proud to have delivered reliable, clean energy and more than $200 million in savings to our nearly 200,000 customers.

We put our customers first, helping them learn about solar, find solutions they want and pave the way to a meaningful relationship with home energy for decades.

In the first quarter, we added 9,400 customers representing 68 megawatts of deployments and generated $65 million of net present value, up 16% year-over-year.

We created NPV per watt of $1.10 or over $8,000 per customer.

The last few quarters have solidified Sunrun's leadership position in the industry.

Our massive market opportunity continues to expand to support strong growth and increasing customer value.

We are entering new geographies, and BrightBox home solar and battery service increases our value proposition by providing stored energy to our customers to reduce cost and service reliability as well as to utilities during peak times when stored energy is a cost-effective way to provide resiliency to the grid.

We are reiterating our full year guidance of 15% growth in deployments and growth in cash generation above this rate.

Our annual growth and continued innovation will be achieved while keeping NPV targets above $1 per watt.

Technology and cost improvements allow us to serve more customers in even more states.

Last month, we launched in Illinois, proving that solar service isn't just for coastal cities.

We are growing in the heartland of America.

This marks our eighth market entry since early last year.

Also, just a few weeks ago, we received the green light from regulators in Florida to offer a solar lease.

As many other markets have demonstrated, allowing third-party ownership, or solar service, makes solar accessible to millions of additional homeowners.

Today, the California Energy Commission unanimously approved the mandate for all new homes to have solar starting in 2020.

California builds over 100,000 new homes annually.

For context, there were approximately 124,000 new solar customers added in California in 2017.

The solar-as-a-service model is particularly well suited to this market because it can help homeowners and builders add solar for no upfront cost.

Our BrightBox home solar and battery service continues to gain traction.

This superior energy service has been launched in 6 states, and customer demand continues to exceed expectations.

We launched BrightBox in Massachusetts less than 3 months ago, and already, nearly 10% of the time, customers we sold to directly are opting to add a battery.

With a low upfront cost, BrightBox is a fraction of the cost of the alternative: dirty, noisy diesel generators.

In California, over 20% of the time, our direct customers are choosing to add a BrightBox.

In certain markets in Southern California, this rate is now above 50%.

Our grid services initiative are paving the way to deliver even more value per customer.

Regulators and utilities are recognizing that home batteries are clean, quick to market, targeted and responsive and can be superior to spending on traditional infrastructure.

Sunrun has created a customer base that nurtures long-term loyalty.

This space, along with our customer acquisition strength, make us the natural partner to unlock the full value of residential solar for these efforts.

To accelerate our lead, today, I'm pleased to announce an expansion of our grid services partnership with National Grid.

National Grid has provided Sunrun approximately $8 million for a share in revenues that arise from new grid services contracts that we jointly bid prior to June 2019.

National Grid's increasing investment is a signal that this market is strong and near-term opportunities await.

I'll now turn the call over to Bob, our CFO, to review Q1 performance and discuss guidance in more detail.

Thanks, Lynn.

In the first quarter, we increased aggregate NPV by $65 million or 16% year-over-year.

We also increased our cash position while adding to net earning assets, our metric for value to Sunrun shareholders for systems over their remaining lives.

This quarter, we're including NPV, project value and creation cost by customer in addition to unit economics per watt.

We believe this is also a meaningful way to express the value and cost of our decades-long customer relationships.

NPV per customer was nearly $8,100 or $1.10 per watt, reflecting an improvement of over $2,000 per customer compared to the prior year.

Q1 project value was approximately $33,800 per customer or $4.61 per watt.

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

We expect project value will decline slightly over time but with costs declining more, although in the short run, there can be quarterly fluctuations.

Turning now to creation cost on Slide 8. In Q1, total creation costs were approximately $25,700 per customer or $3.51 per watt.

Similar to project value, creation costs can fluctuate quarter-to-quarter due to changes in geographic and channel mix.

Creation cost per watt were 4% higher year-over-year, primarily driven by sales activity in Q1 that supports strong Q2 installation growth.

We expect creation cost will show modest declines for this year, even with the module tariff impact and as we continue to invest in new geographies and grid services.

We also expect the adoption rate of home batteries to continue to increase, which carries a higher per-watt cost but also delivers strong NPV.

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

Blended installation cost per watt, which includes the cost of solar projects deployed by our channel partners as well as installation costs incurred for Sunrun-built systems, improved by $0.02 year-over-year to $2.65 per watt.

Installation costs for systems built by Sunrun were $1.92 per watt, reflecting $0.22 or 10% year-over-year improvement.

In Q1, our sales and marketing costs were $0.75 per watt.

We calculate sales and marketing unit cost based on deployed volume in the current period.

The increase in sales activities this quarter will lead to a significant increase in deployments in Q2, while the majority of the selling and marketing expense was recorded in Q1.

We expect sales and marketing unit cost to decline in Q2 as deployments increase.

In Q1, G&A costs were $0.30 per watt, approximately flat compared to 2017.

In Q1, G&A cost per watt excluded 2 nonrecurring items totaling approximately $7 million for charges related to establishing a reserve for litigation and an impairment of solar assets that were under construction by a channel partner that ceased operations.

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.

We achieved platform services gross margin of $0.19 per watt compared to $0.09 in Q1 2017.

In the first quarter, we deployed 68 megawatts, slightly above our guidance of 67 megawatts.

While we don't manage the business for a particular mix between channel partner and direct, our direct business is the platform behind the Comcast partnership volume ramp and where we have focused our initial BrightBox sales and installation efforts, and it's growing faster than our overall growth rate.

Our cash and third-party loan mix was 13% in Q1, in line with recent levels and consistent with our outlook of low to mid-teens.

Turning now to our balance sheet.

Our liquidity position remained strong.

We ended Q1 with $243 million in total cash, a slight increase from last quarter.

We continue to estimate our cash generation will grow faster than our deployments in 2018.

In 2017, we generated $43 million in cash on an adjusted basis.

As Ed will describe later on the call, we are working to optimize our existing project debt and expect our cash generation to accelerate as the year progresses.

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 or accelerated market entries beyond our current plan.

Ed will discuss our capital structure strategy in more detail later on this call.

This quarter, we adopted new accounting standards for revenue recognition and lease accounting, which also required us to recast prior reported GAAP financial results to conform with these new standards.

While the standards are mandatory beginning next year, we chose to implement both this year to limit the amount of change to our reported financials.

The changes primarily affect revenue recognition and interest expense with no impact on cash.

Our recast 2017 financials resulted in only $3 million higher revenue, which represents less than a 1% impact.

EPS improved by only $0.01.

For a deeper discussion of these impacts, we have provided a supplemental presentation on our Investor Relations website.

Moving on to guidance on Slide 10.

We remain confident in our growth trajectory and are reiterating our guidance of 15% deployment growth for the full year.

In Q2, we expect to deploy 88 megawatts, reflecting a 16% increase year-over-year.

As I mentioned earlier, we expect to maintain our unit economics above our target of $1 per watt of NPV for the full year.

Now let me turn it over to Ed.

Thanks, Bob.

Today, I plan to address 4 topics: our general approach to generating cash flow, our interest rate strategy, our near-term capital strategy and pipeline, and finally, changes during the quarter to gross and net earning assets.

As Bob mentioned, we report average customer value for the quarter as project value.

We turn project value into upfront cash by raising tax equity, project debt and sometimes project equity against these newly constructed solar systems.

Tax equity primarily monetizes investment tax credits.

Project debt and project equity monetize recurring cash flows.

When the sum of customer upfront payments, rebates and these project finance items exceeds our overall cash expenditures, we generate cash.

Net earning assets represents the overall estimate of the value expected to be received by Sunrun shareholders after servicing this project level capital.

As shown on Slide 11, when we employ tax equity and project debt alone, we realize upfront roughly 90% of contracted project value.

When we add project equity, we realize 95% to 100%.

These numbers have remained stable over the last year despite an increase in long-term interest rates.

This is because the strong performance of residential solar assets continues to deepen investor conviction in their high quality, lowering the spreads to U.S. treasuries that capital providers require.

As such, overall capital costs are flat to improving slightly.

So far this year, we have amended 3 project debt facilities to lower debt costs, increase loan-to-value, extend maturities, and/or increase capital commitments.

In one instance, we lowered the interest rate and increased the loan-to-value, resulting in both more proceeds upfront and more cash flow after debt service over time.

Despite these early accomplishments, we're hopeful we can do better yet in the second half of the year when we expect to pivot from the commercial bank market to the public debt markets.

In the past, we have financed our assets principally with callable bank debt in anticipation that capital costs would decline.

They have, and these call options are now valuable.

We currently have about $1 billion in callable debt that, over 2018 and 2019, could see a reduction in cost of between 50 and 100 basis points overall.

We are taking early steps to approach the public debt markets in a scalable fashion.

For instance, in Q2, we closed an insurance policy, as is customary in asset-backed security transactions, to ensure without deductible the tax basis in most all of our existing assets as well as those we expect to place in service over the coming several years.

We believe we are well positioned related to interest rates.

Although long-term interest rates have increased since the presidential election, the market no longer expects that trend to continue.

The forward interest rate curve indicates that long-term interest rates that matter to our business will rise less than 10 basis points over the next 3 years.

Meanwhile, as I mentioned earlier, the spreads we pay to treasuries are declining.

If, contrary to current market expectations, long-term interest rates were to rise meaningfully, we note that there is a very strong historical correlation between growth in residential retail electric rates and interest rates.

This correlation exists because most of the cost of residential electricity is the amortizing capital cost of transmission and distribution rather than energy generation, and regulators customarily pass through to customers changes in utility capital costs.

Increasing retail electric rates would allow us to raise customer pricing.

As to our existing assets, we typically lock in interest rates using 18- to 20-year swaps.

We've also used fixed-rate debt.

Our swaps provide 18 to 20 years of interest rate protection, even when individual credit facilities mature earlier.

More than 80% of our expected debt service over the next 20 years is subject to swaps or fixed rate loans.

Switching gears to our upcoming capital strategy.

We believe we will achieve the best possible execution by sequencing our transactions, first, in the public senior debt market; next, if applicable, in the subordinated debt market; and finally, to the extent desired, in the project equity market.

As such, we wouldn't expect to execute a project equity transaction any earlier than Q4 of this year.

This may concentrate cash generation in the fourth quarter of the year.

We still don't expect to refinance into the public markets any seasoned assets, meaning those operating for at least 5 years, until early 2019.

Our capital commitments more than support our 2018 growth plans, and we have tax equity capacity into 2019 and project debt capacity into Q4 of this year.

We have now closed or signed term sheets for 3 tax equity financings since new year at terms consistent with our previously shared expectations.

Finally, I turn to our installed asset base, as shown on Slide 12.

Net earning assets rose 9% from Q4 to $1.3 billion, reflecting a 20% year-over-year increase.

Last quarter, I mentioned that the timing of cash receipts on tax and project equity financings impacted net earning assets.

Those timing issues have now resolved but similar quarter-to-quarter variations may occur in the future.

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

Thanks, Ed.

Let's open up the line for questions.

(Operator Instructions) Our first question comes from Michael Weinstein of Crédit Suisse.

Yes.

Could you quantify a little bit better the opportunity in California from the new rules that are in effect?

Like what portion of your business is in California?

What's your expectation for increase in volumes at that point?

And how will it affect the business as a whole?

Yes, great question.

We are thrilled about the results, certainly.

I put a little context into the script, so just from a market level, the amount of new solar homes that were installed last year, both new home and retrofit, was just over 100,000.

And there are -- there were just over 100,000 new home permits.

So it's -- there's a little overlap there, but it's roughly doubling.

So it's a huge vote of confidence for the market.

I think, strategically, it also is really important because it's showing that California is serious about home solar and batteries and what that can do to build a cleaner, more cost-effective, customer-centric system, generally.

So that's a -- it's a huge proof point there.

The other reason Sunrun is particularly well positioned in this market is because the new-home market works very well for the solar-as-a-service or solar-leasing business model.

One of the hesitations for builders or consumers on new homes in the past has been, "If I have to add another $10,000 or so to the house, that conflicts with my new kitchen that I want." And so with the solar-as-a-service model, neither the homebuilder nor the buyer has to spend any amount of money upfront to get the solar, and the rates are cheaper than what the utility offers.

So there's really no compromise, it's just a better service.

So I think there's been some discussion recently about the share of loan versus lease in California, and I do think that this could be something where the share of this service model increases as part of the market generally.

The other interesting thing about the mandate is that it does also offer some compliance credit for storage.

So again, we're seeing in California already with the time of use rates that consumers are very interested in adopting storage.

So as I said on the -- in the prepared comments, in many places in Southern California, it's already more than 50% of people getting solar or adding a battery.

And so similarly, I think this market will -- it will be an attractive market to help accelerate those efforts.

And then, finally, California is really leading the way in terms of the grid services opportunities, and we were excited to announce the National Grid partnership today where, that partnership, they invested $8 million, and that's to get a return on contracts we bid on over the next year.

So that means we -- that the vote of confidence that there are near-term opportunities, a lot of those are in California for aggregating the battery and selling those services to the utilities.

So it's -- this new-homes market is going to be another great market to help accelerate those grid services efforts.

So it's early.

Our share -- to answer your specific question, our sharing, we don't break out specific state by state concentration.

I think, if you look at the overall market, California's somewhere around 40-ish percent of the market.

We're somewhere in that zone.

But I think this is very encouraging, and it's just one of many different markets that opened up for us this quarter and then over the last year.

Great.

And did you -- can you disclose what percentage of the grid services partnership was sold to National Grid for the $8 million?

No.

And it's structured as just a share of the revenues for any contracts that are signed over the next year.

So it's not any sort of ownership or long-term ownership or formal JV or anything like that.

Is it a percent -- can you talk about the percent of revenues that are being...

No, that's not disclosed.

Got you.

And just one last question.

When a -- if a homebuilder agrees to do a deal with Sunrun, who is actually signing the lease at the time that they're building the house?

So I believe the -- it's -- the homeowner may take the lease for a portion of the time, but it's really the homebuyer that (inaudible).

I mean, the other thing I will -- the other thing that's important to note about this too is just the normalization of solar is a -- will be a huge proof point for the market.

So the fact that every home has this, this is just going to help resale value, it's going to help awareness across the whole business.

So it's -- it will be a big lift in terms of overall customer acquisition in the state.

Our next question comes from Joseph Osha of JMP Securities.

Sorry, the audio is kind of bad.

Two questions.

First, Ed, when you talk about going to the public markets on debt for pre-flip assets there, is the LTV going to go up as part of that transaction?

Or are you just dropping the cost of debt?

I just want to make sure I understand what you're discussing here.

Great question, Joe.

So we're seeing the public markets mature as relates to newly placed in-service assets.

So where the issues around tax equity and leasing previously caused a more significant change in interest rates or advance rates, we're seeing that compress.

And in fact, in many respects, the public debt markets are now at comparable LTV and lower interest costs.

So our expectation is -- at or even near current market data points, we are expecting to be moving heavily towards public debt securities at this point.

So it's really more about newly placed, in-service assets as opposed to much refinancing?

So the market is strong for both.

The point I was just trying to make in the call is just to reiterate that the opportunities that we have refinancing our seasoned assets, for instance, the post-flip assets that you're asking about, we expect to be attacking that in 2019.

Okay.

And then a question for Lynn, following on the previous questions.

If I'm a homeowner or a homebuyer, am I potentially going to have the option of either buying the system outright as part of the house or signing a lease?

Or am I just going to be -- if the homebuilder has decided that the lease is -- is that what I get?

I'm just curious about how much optionality homebuyers are going to have.

The -- it's done both ways today.

And so it'll be really the -- builder-by-builder specific.

It is my understanding that the majority of the new-homes market today is done through the third-party-owned model.

So I think the recent statistics I have seen quoted in the press are that, last year, about 15,000 new homes had solar on -- new homes had solar, and I -- again, I believe the majority of those were done through the third-party-owned model.

Our next question comes from Sophie Karp of Guggenheim Securities.

Two questions.

One is a follow-up on the new rule in California.

I am wondering, is that an option for new homebuyers to opt out of solar leases or purchases?

Or is that sort of imposed on them?

No, I believe it's a mandate that the home has to have solar.

I mean, I think that the -- technically, I think it's about how much emission the home creates, so it's possible that there are alternatives like geothermal or residential wind or other kind of more niche offerings.

But as a practical matter, most believe that this is mandated, and so almost every new home will have solar on it.

Got it.

All right.

And then, again on California, a couple of your competitors who have reported so far, so they're pretty new in their focus on California, maybe trying to refocus more on the DG in residential, and another competitor appears to be aggressively moving their sales force into the state.

Are you seeing the competition getting more aggressive, and so it's eating into the costs?

Or what's the -- what does it feel like on the ground?

Yes, I think it's -- the story is the industry is returning to growth, so it's fantastic to see that.

As we mentioned often, we're so underpenetrated, and more awareness generally helps all companies.

So we're encouraged, and we think that the renewed focus on DG and the focus in California is really a testament that the consumer interest is there and the demand's there.

So we're excited about it.

But you're not seeing any pressure from the acquisition cost so far from the dynamics?

Or the market is big enough for everybody?

Absolutely.

If you just look at the project value that we recorded in the period was very strong.

That tends to be a reflection of what the end consumer pricing looks like.

And as Bob discussed, the acquisition cost was right on.

It was a little higher this quarter because the denominator is smaller, given that the deployments are seasonally slower in Q1 and we have really strong growth coming in Q2.

But acquisition costs are staying fairly consistent on a like-for-like basis.

So no, we are not seeing that.

And again, I do believe that more advertising, more consumer awareness in the category generally, at this stage of the industry and for a while to go, will lower everyone's acquisition cost.

Got it.

And one last one, if I may.

You have more and more batteries and BrightBox attachment rate, as Ed pointed out, that increases the cost per watt basis slightly, right?

So how should we think about this increase maybe?

What does it cost for a system without a BrightBox versus a system with a BrightBox on a per watt basis?

What's the differential there, for our modeling purposes?

For your modeling purpose, I think that the high guidelines we've given you still hold.

Again, across the nationwide portfolio, the BrightBox penetration is not a hugely significant number for the year.

So the guidance we've given around project values slightly declining through the year, costs slightly declining through the year with a lot of that coming out of the installation, those are all operating leverage and efficiencies we're going to see offset by some of this cost increase on the battery.

But those patterns are generally going to hold, and that dollar-plus of NPV will hold as well.

So again, just to repeat that, slight declines in the project value, slight declines in the creation cost back and the dollar-plus of NPV.

Our next question comes from Colin Rusch of Oppenheimer.

Did I miss the bookings somewhere someplace?

And if you're not disclosing that anymore, could you walk us through why not and give us some metrics around close rates and what's going on with the sales team?

This is Bob.

So we have decided to stop providing the bookings number because it basically was converging to the installation number as we've been able to collapse the time from NTP to install.

So we didn't think that it was a good leading indicator.

It was not really providing additional information.

As far as close rates and things like that, that's not something that we've been disclosing.

Yes.

I mean, I think that the -- and then the Q2 guidance gives you an indication of where we're going to end up.

Okay.

And then the sales and marketing expense has grown a couple quarters in a row here.

And I know that you guys have a very tight grip on your spending and then what the impact can be.

So when you move into new markets or deploy additional resources, are you seeing 3-month, 6-months, kind of 9-month impacts?

And how should we think about the cadence of that?

The sales and marketing costs are -- when we look -- like Lynn said, when we look at kind of same-store, same-channel performance, we're actually seeing that the CACs, when you look at it over time and when the deployments actually happen and compare the cost to that, and then the volume that's related to that, we're actually seeing that they're consistent.

Or for our own Sunrun-managed, direct kind of sales channel, we're actually seeing them improve slightly.

So I think that's one thing to consider.

When we report the total sales and marketing cost for the firm, we describe that it's sensitive to channel mix.

So because of our multichannel strategy, when we report overall costs, it's a blend of what we actually sell and deploy versus what we do through channel partners.

And that actually can have an effect.

So as we mix more towards Sunrun, the channel partner costs for systems that we purchase include selling and marketing costs.

So as we mix, as -- and we suggested in my comments that we're growing faster, that the Sunrun direct piece is growing faster.

As we mix in that direction, that makes sales and marketing costs blended a little bit higher.

Our next question comes from Brian Lee of Goldman Sachs.

A lot of focus on California, with the ruling being fresh here.

But just maybe could we focus on Florida for a moment?

Because it seems like it could move the needle faster for you guys.

Maybe some color on that market, how big an opportunity you think it could be, how quickly it can ramp.

And then maybe what has to happen, in your view, for it to drive upside to your volume guidance for this year if that's, if there's a scenario where that plays out?

Yes.

Thanks, Brian.

So the deployment guidance for the year does not contemplate a big contribution from Florida.

So as you've seen, we will be active there soon and the third-party-owned model was approved.

We are optimistic and have seen in other markets that when third-party-owned becomes available, it does unlock growth, but we do believe that it's premature to bake that into the plan.

That certainly wasn't in the initial plan.

So we think about this again as helping set the stage for this long-term industry growth rate of 15%, 20% that we're targeting over the next decade.

But I think it takes a little while to get these markets up and running, and we haven't officially launched the product yet in Florida, so it's not anticipated to be a huge contributor this year.

Okay, fair enough.

Appreciate the color.

Second question, just on grid services.

The National Grid investment, can you help us understand that a bit better?

So is that in the cash flows for Q1?

And then how is it being structured?

Is this potentially a recurring investment?

And does that count toward the -- does the $8 million count toward your cash flow targets for the year?

Good question.

So one, it is not in the -- it just closed today.

So we announced it today.

So it's not in Q1, it's a Q2 event.

The way that it is -- because it's relatively small, all things considered, we have not disclosed the specifics of it.

But what it does is, based on this $8 million and any of these grid services contracts that we bid over the next year or so, technically end of June 2019, there's a revenue share around that.

So it -- and then it ends at that period.

So that's how it's currently contemplated.

It's really an expansion of what we've been doing and a testament that we've done a bunch of work on this over the last year together to size the market and the opportunity, and it's a vote of confidence that they're -- it's -- the market's real and that there are near-term opportunities over the next year.

In terms of how it affects the financial profile for the year, the $8 million funds the grid services business that we're building out, so there's a lot of costs that's in our creation cost stack right now for the grid services.

So yes, the $8 million is in the cash flow guidance technically, I guess, but we also are spending on R&D to ramp that business, and that's in the creation cost outlook.

Okay.

And there's no contingencies on the investment where, let's say, over the next 12 months through June 2019, you bid on grid services opportunities, you don't win anything, there's 0 revenue share to be had, does anything happen to the investment that they've made?

I guess how is it being carried in the balance sheet?

Ed?

Hey, it's Ed here.

So in the -- what we view as the very unlikely scenario that there are no grid services contracts won.

We would not have to refund the amount to National Grid.

And in fact, part of the reason we're not disclosing the share is the better we do, the smaller their share is, so it's variable.

In terms of the accounting for it, we're still finalizing that.

I suspect it won't be in period revenue, but we'll talk -- we can address that later next quarter.

Okay.

And then just maybe last one for me, I'll pass it on.

Again, on grid services, bigger picture here.

There's been a push publicly from some of the inverter companies and battery companies to kind of be the aggregator and offer these platforms.

So curious how you're thinking about the ecosystem.

I know it's early days, but what your view is in terms of how it's going to evolve, why Sunrun or the servicing entity would be the right one to lead grid services versus others in the supply chain that seem to be targeting it as an opportunity as well.

Sure.

Great question.

It's all about the customer relationships and the customer acquisition capabilities and that they're our customers.

And I think that's also why Sunrun has a strong position vis-à-vis the utilities, in addition to others in the supply chain, is that for someone to use their own personal real estate and have somebody use part of their assets, you -- they have to trust you.

You have that long-term relationship with that customer, and that's what we're building.

That's what we're investing in, and that will be a very strong and durable competitive advantage for us, we believe, over the years.

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

First one's on guidance.

With the Q1 results and your Q2 guide, this suggests back half needs to grow 23% year-over-year.

Can you just provide us some additional color as to kind of where you see the strength coming from?

And I know we talked about it in the last call, but now that we're closer to the back half, give us a feel for -- I know it might be a number of geographies, but if you can give us some detail around the deployment growth there.

That would be great.

Sure, absolutely.

We are seeing strong growth across the board, really.

So it's of -- our longer-term markets of California and the Northeast are showing very strong growth.

We also entered 7 new markets last year, as we described, including big markets like Texas and Florida that didn't contribute significantly last year but are starting to be ramped this year.

Nevada also is coming back quite strong, so we have that one -- that brief window in Nevada where net metering wasn't offered, and that market's coming back strong.

Arizona, as we described in the last call, part of the Q1 results was due to Arizona being pulled forward into last year, but that market is coming back as the pipeline rebuilds.

And Illinois had a very successful launch last March.

So we're really seeing it very nicely distributed across the whole country, and good contribution from the -- all the foundational work we went -- we've been through, and entering now 8 new markets over the last 1.5 years.

Great, Lynn.

This one might be more for Ed.

As it relates to the ABS market, it's becoming more mature, spreads are coming down.

There may be a chance to, in addition to refinancing the assets on your balance sheet, that you might be able to do this before the flip.

I think, last quarter, you guys talked about potentially giving $200 million of ABS post-flip.

Is there -- can you give us an update on whether that has changed at all?

And then also, if there is an anticipation or expectation that you might do pre-flip assets with ABS, some color on that would be great.

Sure.

A great question.

And what I was hinting at on the -- in the prepared remarks is if current market conditions hold, we could potentially term out or refinance almost all of our existing assets into the ABS or other public debt markets.

The current callable debt balance is about $1 billion, that is mostly all preflipped assets at this point.

So that is likely to be a 2018 and 2019 project, and -- with the significant portion in 2019.

But at this point, given current market pricings, it would be the base case.

Great.

So digging a little bit deeper there, Ed, I think you said in your remarks that, that could be a 50 to 100 basis point improvement.

So just if you can, kind of back of the envelope, what kind of interest rate or interest expense improvement could we actually see as a result of refinancing potentially that $1 billion?

Yes, sure.

So 100 basis points on $1 billion would be $10 million a year as a rule of thumb.

And then obviously, that would amortize out over the 20-year period.

One thing I should caution, obviously, is if we simply reprice a credit facility, that doesn't create, to your point, immediate cash.

That would create cash, obviously, over the life of the 20-year asset unless, of course, we place project equity against that asset, which would then pull forward that interest cost savings.

Great.

Okay.

So think about it, $10 million perhaps divided over a 20-year period, and then some of the caveats that you just mentioned as well.

I mean, the $10 million was at 100 basis points.

So I -- we said 50 to 100 basis points.

So I was just trying to use the round numbers, and that's per year.

Per year, yes.

Per year on (inaudible) the initial.

Yes, and I -- and maybe -- and so maybe just another way to think about it for folks, because I -- we've been fortunate that there are a lot of new people paying attention to us these days, which is exciting, is we still believe that, in terms of modeling and thinking about the cash flow generation, the -- in the slides that we offer, we still believe that the leverage, the -- with the tax equity and the debt, we're getting upfront 90% of the contracted value.

And then with project equity, we get that up to 100%.

So that is still -- the strategy is to employ a mix of that.

And one of the things we're communicating is that, that's holding -- many people ask questions to us about the interest rate environment, and we're actually seeing improvement in the interest rate environment, as Ed articulates.

And we're also seeing this whole new asset class become available earlier, which is the public debt market, because it's matured, because we have things like the insurance policy that we bought.

So these -- so it gives us more flexibility, is what we're saying.

And then I also want to be clear to you that the refinancing of the seasoned assets that Joe asked about as well, we still anticipate that, that will happen in Q '19.

So it's not -- our plan is not to generate the cash flow guidance by refinancing every all of our assets this year.

Our plan is to generate it by operating well the assets that we're developing in period, but we have a lot of optionality available to us.

Yes, it certainly seems like it.

And then one last question about this topic.

If the callable piece is about $1 billion, can you give us a sense of what the first tranche might be?

What kind of timing?

Could we see something this quarter or next quarter?

Some kind of sense of magnitude of -- and timing would be great.

Fair question.

So yes.

So as I said, I think we're looking to sequence the activities, first, in the senior market, then potentially any subordinated market with potentially project equity thereafter.

I had made the comment that the project, if we place project equity, it likely wouldn't be before Q4.

So I would assume that would -- we therefore follow -- you'd more likely see these sorts of transactions happening in the second half of the year.

Our next question comes from Julian Dumoulin-Smith of Bank of America.

Well, so I wanted to come back to a couple of things that have been mentioned already.

First, on the latest developments in California.

Can you help us understand a little bit of the market opportunity?

I know you mentioned the 15,000 homes metric earlier and perhaps some opting to choose a third-party option.

But how do you think about sort of entering the remainder there, right?

Because I would imagine that, to a certain extent, you'd be dealing more with the direct -- the home developers as a market.

And perhaps maybe what I'm asking is like, what's the go-to-market strategy on tapping into that new kind of customer or counterparty, if you will?

Yes.

No, great question.

You're exactly right.

So again, just to size it, new home permits were about just over 100,000 last year.

So that gives you a sense for where this is going to go.

And you're right.

It's a different customer base.

The customer base is the homebuilder, and we already -- it's not a huge piece of our business, but we already sell to homebuilders, have those relationships, have the business staff, have the contracts appropriate for that channel.

So we're well positioned for it.

It hasn't been a huge focus area because we've pursued other, what we felt, were more attractive markets and business lines.

But with this new news, it's certainly something that we're well positioned to take advantage of.

So you are correct, and we are well positioned, we believe.

Great.

And just to clarify that, do you have any kind of exclusivity deals with any of them as it goes already?

And/or to the extent to which you're engaging with them, would this be -- if you think about it like as a business segment, would this be under like a services element, as you think about it?

I think, you wouldn't see -- I don't think you would see it play out as its own segment because the product will look fairly similar to our current PPAs.

It would be -- the way it would reflect in the financials is, certainly, we believe it's a lower-cost way to acquire customers, so that's attractive.

Likely, the PPA rates we're able to offer homeowners because of that lower cost will be a bit lower, so you'll probably see a little bit lower project value, a little bit more attractive cost.

Again, we were pretty committed to our strategy of pricing $1 of NPV.

We see no reason why we can't hold that type of margin in this business line, but we wouldn't anticipate that it looks much different or would be carved out in any way.

And again, we're going to ramp for this.

This is 2020.

So it's -- certainly, billows are getting ahead of it, and there'll be market opportunity now, but we -- there's a couple of years before it goes into effect.

In terms of the extrusive relationship, that's not something that we disclose, but we have strong existing relationships.

Got it.

Excellent.

And then I'm not sure who to direct this one to.

I think, in the comments, you guys alluded to a 1Q-versus-2Q discrepancy on the marketing cost that you talked about because of acquisition.

How much of a corresponding offset could we see in 2Q, given sort of the timing, which seems like a timing-related issue here this quarter on cost structure?

Yes.

So we do think, with the return to kind of more normalized volumes like we've had in the recent past, that the sales and marketing cost will come down pretty significantly from where they were in Q1.

Okay.

All right.

Just leave it at that.

And then maybe just finally if I could, quickly, how do you feel about the full year annualized cash target?

If I were to think about -- you've talked about growth at or above deployment trends.

And sort of last year, you did about $40 million in cash.

So if you were to think about that, that would imply about $50 million, sort of give or take, in cash flow generation this year.

How are you tracking against that?

I know you mentioned interest savings here.

How much of a component would that be as well vis-à-vis your own thinking and planning?

I think I'll talk about operating, and Ed can chime in on the finance there.

We're tracking well to that.

We -- the best metric to see how much value we're creating and how much margin we're creating in our development efforts really is that NPV target.

So you see the NPV targets are strong, and holding in that, plus operating leverage that we're going to see and the volume growth we're going to see is just -- it's going to drive growth rate and cash above that 15% growth rate.

So above the $50 million that you quote.

And then there's the financing opportunity on top of that.

Yes.

And to be clear, that is -- the interest savings, what we were talking about earlier, would not be material this year for 2 reasons.

One, the initial transaction would occur in the second half of the year; and then, two, a very, very substantial portion of the overall refinancing activities.

Certainly, well more than half -- substantially more than half would occur in 2019.

So that's something that will definitely accrue to Sunrun common shareholders over time, but those savings and interest expense, I wouldn't see as a material driver to the '18 cash flow.

So let me just sum it up, because I want to make sure that this is -- it's an important point.

We are thrilled with the cash generation in the business and the potential, so I want to we make sure that we're being clear on it.

We continue to estimate that the cash generation is going to grow faster than the deployments in the year, and that's not going to be due to any sort of onetime financing heroics.

This is due to strong operating and growth in the business.

And the project finance market is as strong as it has been pretty consistently for 11 years, so we do expect that.

As Ed mentioned on the call, because of the order of operations, of how we're attacking the capital structure, a lot of that cash flow generation is going to come in the end of the year -- towards the end of the year, because we're going to place the senior debt first and then pursue the project equity-type structure that generate more upfront cash.

So the shape of it may have more in the end of the year, but we are feeling positive that -- yes, we're feeling positive that we will hit that.

Of course, the Q4 has 2 great effects, which are the deployments.

We're getting real operating leverage because we're growing well, and deployments should be significantly higher in Q4 than they are today, plus the timing of the (inaudible).

Got it.

Excellent.

It seems like you'd be well on your way in 2019 against that similar growth or cash growth target just because of the financing tailwind.

Is that kind of fair?

I know, obviously, it's not annualizing at that full $10 million in '19 itself, but there is some kind of tailwind.

Well, I mean, yes, that helps.

But we also have a business that's structurally cash flow positive and growing at a nice rate.

And again, we're expecting to grow 15% this year.

Given where the first quarter ended up, you can see that, that growth rate is higher even, closer to 20%.

We see no reason why that growth rate can't be sustained.

We're setting the foundation for it with our market expansion and service offering expansion.

So that's the big story, and then the refinancing is gravy on top of it

I'm showing no further questions at this time.

I'd like to turn the call back over to Lynn Jurich for any closing remarks.

Well, that's it.

Thanks for the great questions, and we look forward to speaking with you guys next quarter.

Thank you.

Ladies and gentlemen, this does conclude today's conference.

Thank you for your participation, and have a wonderful day.

You may all disconnect.