Sunrun Inc (RUN) 2016 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q1 2016 Sunrun Inc.

earnings conference call.

(Operator Instructions)

As a reminder this conference is being recorded.

I would now like to introduce your first speaker for today, Director of Investor Relations, Ms. Charlotte Coultrap-Bagg.

Please go ahead.

Thank you.

Thanks everyone for joining us today.

Please note that certain remarks we make on the call constitute forward-looking statements.

These include statements related to financial and operating guidance and expectations for our second quarter and full-year 2016, momentum in our business and our business strategies, expectations regarding customers, cost reduction, project value, megawatts books, megawatts deployed, product and channel mix at NPV, as well as our ability to raise debt and tax equity, manage cash flow, cost and liquidity, leverage our platform services, and deliver on planned innovations and investments, including in products, services sales and facilities, as well as expectations for our growth, the growth of the industry, microeconomic trends and the legislative and regulatory environment of the industry.

These statements reflect our best judgment based on factors currently known to us, and actual events and results may differ materially.

Please refer to documents we filed with the SEC, including the form 8-K filed with today's press release.

These documents contain risks and other factors that may cause our actual results to differ from those contained in our forward-looking statements.

Our SEC filings are available on the Investor Relations section of the Company's website and on the SEC's website.

These forward-looking statements are being made as of today, and we disclaim any obligation to up date or revise these statements.

If this call is reviewed after today, the information presented during this call may not contain current or accurate information.

With that, let me turn it over to Lynn Jurich, our CEO.

Thanks, Charlotte.

Good afternoon, everyone.

Today we are proud to announce our achievements in the first quarter of 2016.

For the quarter, we deployed 60 MW.

This exceeded our guidance of 56 MW.

We generated $21 million in pro forma NPV, while reaching EPF positive for the first time as a public Company.

The industry also reached an important milestone, crossing over 1 million solar homes, which underscores the increased power and relevance of rooftop solar in our energy future.

Sunrun is dedicated to the residential segment because we believe it has unique value creation characteristics.

We offer something that customer want and rooftop solar can provide: clean, local generation with locked in lower rates.

Sunrun's mission is to develop the industry's most satisfied and valuable customer base.

We are well on our way, having already saved our customers $100 million on their electricity costs and building an army of solar advocates.

In light of a few very favorable macro development, the ITC extension and an emerging long-term regulatory framework in leading states like California, Massachusetts and New York, I'd like to add shape to the enormous and growing value creation opportunity in front of us.

Utility electricity revenue is $400 billion annually, and this figure is growing because even as utilities fall behind today's consumer expectations, they continue to raise rates.

The US is on a path to replace an estimated 70% of grid infrastructure nearing the end of its useful life.

We can approach this investment as if operating a mainframe computer.

So what consumers want are PCs: PCs enabled by an interconnected system with a two-way exchange.

Obviously, we've opted for the latter in computing to great benefit.

We believe that in hindsight the shift to distributive energy and a smarter network will appear just as beneficial and inevitable.

Many technologies are reshaping countless industries today.

The companies driving these innovations are doing so by empowering consumers with a wider range of competitive options, some of which may not even have existed a few years ago.

The effect is that the core competencies of the incumbents, such as utilization of as large an asset base as possible, are made less relevant.

Yesterday's strengths are superseded by new entrants' ability to deliver directly to consumers the service they prefer, whether this is mobility, a new option for lodging, or in our case, lower-cost clean local power.

Reaching homeowners where they live, understanding our customers, and delivering a better experience through solar as a service, this is Sunrun's core competency.

In the past several months, we've enjoyed important regulatory stability in existing net metering structures and progress towards designing the model of the future in California, New York, and Massachusetts.

This comes after about 65 regulatory decisions nationwide since 2013, and several more since our last call, of which over 95% have affirmed the role for rooftop solar and distributive energy.

This doesn't mean there aren't bumps in the road along the way.

Nevada was incredibly discouraging, but it's an outlier, and won't hold up in the face of progress.

You can observe in poll after poll over 90% of the country supports solar across all political parties, regions and demographics.

And American support for competition and clean energy will only strengthen with increasingly extreme weather, pollution and rising electric rates.

With this enormous opportunity ahead of us, Sunrun's strategy to deliver the industry's most valuable and satisfied customer base has four pillars.

First, deliver customer value: our customer experience is our proudest achievement.

We've created a high-quality sales and installation experience and a strong value proposition that pays off over 20 years, with predictable customer payment performance, referrals, smooth home transfers and low customer care costs.

Second, drive NPV: we are focused on market-by-market-level profitability and over-weighting high revenue markets and attractive solar customers.

We've built a plan to hold our project value flat for the year and now are turning heavily to cost improvements to deliver operating leverage.

Year to date, we have experienced more softness in consumer demand than we expected.

In our almost ten year history of operating the Company, we've seen many periods where anticipated incentive reductions have driven purchasing urgency and others where uncertainty, for instance a coming but unknown change in rate structure, slows demand.

Unfortunately, the first half of 2016 has seen unusual customer uncertainty in key markets like California, Massachusetts and Hawaii, all occur at the same time we are exiting Nevada.

In the past, demand has always recovered, and we have no reason to suspect the pattern won't hold this year.

We still believe our 285 MW target for the year is achievable, based on historical seasonality and also our Bottom's Up plan.

It will likely require a near 100% growth rate in our direct business, which is now the majority.

We will continue to watch demand drivers closely and adjust as necessary.

However, I want to be clear that the first priority will be delivering NPV above a $1.00 per watt in the back half of the year.

This profit margin, combined with our secured tax equity and debt advance rates, yields a very attractive ongoing development business, with a lot of runway to grow sustainably.

We want to build a Business that can grow at a 30% annual rate for the next 10 years.

Bob will illustrate this with numbers shortly.

Our third strategic pillar is our platform model.

Our channel business continue to offer a low fixed-cost way to reach incremental customers.

Our platform services business leverages our infrastructure investment across other industry participants, and our partner orientation and open platform make us the preferred partner for strategics who have large existing customer bases, find the residential solar market attractive, but realize there are meaningful entry barriers.

We are excited to welcome Constellation Energy and NRG to our platform this year.

Finally, we have a low risk nonrecourse capital structure with strong advance rates.

We are locked in with attractive project finance well into 2017, and we have no recourse debt outside our working capital line, which is due in 2018.

I'd like to close with an exciting development.

We've installed the first BrightBox in Hawaii.

BrightBox is our solar plus storage as a service offering.

It delivers customer savings with no upfront cost and strong unit economics to Sunrun.

The importance of this innovation cannot be understated.

BrightBox is capable of storing the solar power when it is generated and dispatching it when it has the highest value.

This technology holds incredible promise for value creation when paired with time of use electric rates, or even in the absence of net metering.

We were honored to have Governor Ige there in person to help us flip on the switch last week.

He described BrightBox as exactly the kind of solution that will enable Hawaii's 100% renewable energy goal to be met.

Turn it over to Bob.

Thanks, Lynn.

All of the Q1 numbers described as pro forma during this call exclude cancellations and one-time exit costs for Nevada.

For these details, please see the disclosures in our Q1 earnings release and cost memo posted on our Investor Relations webpage.

In Q1 our pro forma net bookings were 56 MW, up 46% year-over-year.

We deployed 60 MW in Q1, above our guidance for the quarter, an increase of 63% year-over-year.

Volumes were negatively affected by the loss of Nevada pipeline, backlog and exit activities, and by some delay in consumer purchase decisions caused by regulatory uncertainty in California, Massachusetts, Hawaii and New Hampshire, that we believe are temporary.

We continue to execute on our strategy of focusing on net present value and delivering the industry's most valuable and satisfied customer base.

As a reminder, project value represents the present value of upfront and future payments from customers, benefits received from utilities and state incentives and net proceeds from tax equity investors.

In the first quarter, our project value of $4.51 per watt was flat with Q4 2015.

We continue to expect project value to remain relatively constant for the remainder of this year.

Our pro forma total creation costs in Q1 was $4.11 [NOTE: $4.09 was corrected by Lynn Jurich at the end of this transcript] (corrected by company after the call) per watt, down 6% year-over-year, but higher than Q4 15.

As discussed in our last earnings call, we expected creation costs to be higher in the first half of this year versus our ending 2015 quarterly trend, as we continue to scale to invest in market share expansion to support Sunrun built deployment growth of nearly 100% in 2016, while also working through remaining volume headwinds due to the Nevada exit and the regulatory uncertainty in some markets mentioned earlier.

Due to the high creation costs in Q1, our pro forma NPV per watt declined to $0.40 per watt, and we created a total of $21 million in total pro forma NPV.

For Q2, while we expect a modest increase in NPV per watt, primarily from some reduction in creation costs, we'll remain below our dollar NPV per watt target.

In the second half of the year, with forecasted volume increases, continued focus on cost improvement, and with project values remaining flat, we expect to meet or exceed $1.00 per watt in NPV.

Total creation cost is more than a function of increasing scale.

Higher value markets and customers tend to also have higher acquisition and installation costs, but they also drive higher project value and NPV.

Our primary focus is on achieving the NPV target and driving our overall cost stack is critical, but it's not the only lever.

I'd now like to describe the planned cost improvements in the second half in more detail.

Two mix shifts, in addition to continuing efficiency and scale improvements, will help drive unit costs down in the second half of this year.

First, Sunrun built deployments are expected to continue to grow rapidly, channel partner deployments are forecast to be relatively flat from Q2 through the rest of the year, and will decline as a percentage from approximately 35% in Q1 to 20% by Q4.

This increasing mix of Sunrun built systems with lower installation costs will drive our blended installation cost down by approximately $0.40 per watt by Q4, from $2.97 per watt in Q1.

Sunrun built installation cost was $2.36 per watt in Q1, and both installation metrics are both above recent trend due to absorbing indirect and overhead costs on lower volume as a result of exiting Nevada and sizing capacity for continued growth later this year.

Second, solar systems sold for cash or with third loans are increasing as a percentage of our installed volume from the continued growth in our retail channels.

These sales are included in the GAAP income statement line, Solar Energy Systems and Product Sales Revenue, and their entire value is recognized upfront.

We expect a mixed increase from approximately 15% in Q1, to about 20% by the end of this year.

The gross margin dollars generated by these sales, plus from our distribution and other platform services business, which we combine and report as platform services margin, and then subtract from total creation costs, can contribute approximately $0.10 more per watt by Q4 than the $0.12 reported in Q1 for them.

Scale economy benefits from higher deployment volume will primarily drive G&A per watt cost down, since they're more fixed in nature.

We expect at least $0.05 per watt improvement by Q4, from the $0.35 pro forma in Q1.

We plan that sales marketing costs in the rest of 2016 will be lower than in Q1, but somewhat above the levels achieved in the second half of 2015, primarily due to the increasing mix of Sunrun direct sales versus partner channel volume.

Pro forma Q1 sales and marketing costs were $0.90 per watt, and we expect them to declined by more than $0.10 per watt by Q4.

The total impact of all of these improvements can generate a reduction in total creation costs of approximately $0.65 by Q4 2016, versus our Q1 pro forma results.

This would mean that creation costs would be within 2%, or nearly breakeven, with our expected upfront asset financing proceeds.

So now turning to project financing, including runway and upfront asset financing proceeds.

Based on execution of additional tax equity and debt financing transactions, or term sheets we've executed through today, we have the capacity to support our growth plan well into 2017.

Based on these transactions, 75% of project value is a reasonable estimate of the upfront asset financing proceeds we expect to receive on average.

However, individual quarters can vary based on the timing of the receipt of the funds.

As we drive our creation costs down to levels consistently below upfront asset financing proceeds, we expect to become structurally cash flow positive.

Further, when this crossover point is reached, the business can generate substantial cash flow.

As an illustrative example, we've included in the slide presentation a scenario with a reasonable set of operating assumptions, approximately showing $200 million in cash flow can be generated over a three-year period.

Now I'd like to pass the call over to Edward, our Chairman.

Thanks, Bob.

In addition to the value of the development Company, our existing assets have significant value and are also growing every day.

To help illustrate this, we are sharing publicly for the first time a measure, net earning assets, that some of our investors and lenders have found helpful in understanding the value of and growth in our enforced customer base.

Like net retained value, net earning assets includes the present value of the solar assets that are owned by our project finance fund.

Similarly, it deducts our project level or nonrecourse debt.

Unlike net retained value, net earning assets excludes all value from projects in our backlog.

Net earning assets also excludes cash and our working capital revolver.

Because net retained value includes cash and parent company debt, it rises and falls with things like inventory investment, accounts payable terms, and corporate equity issuances.

As such, on a quarter to quarter basis we believe net earning assets provides a higher signal and noise ratio than net retained value does.

Turning to the topics of debt and tax equity, I'm pleased to report we continue to enjoy the lowest project capital costs and longest project capital runway in the Company's history.

As of today we have executed tax equity transactions or term sheets to carry us into the first quarter of 2017.

Today we also closed an upsizing of our aggregation facility.

We added $90 million in capacity, including from two large international bank who are first and lenders to Sunrun.

The loan terms remain the same.

With this upsizing, we now have sufficient back leverage capacity to carry us into the second quarter of 2017.

Finally, I want to touch briefly on discount rates.

We continue to believe that a 6% unlevered discount rate can appropriately be applied to our contracted assets.

Due to recent investor focus in this area, we wanted to provide an additional data point for long-term capital costs.

During the quarter we completed a levered tax equity transaction that monetizes 100% of our 20-year contracted cash flows plus two years of renewals.

In this transaction we place debt and equity separately.

The cost of debt is 3.5%, and the investor's expected equity return is 8.8%.

The total proceeds to Sunrun were sized based on a 6.9% unlevered discount rate.

The total proceeds in the transition is expected to be about $110 million.

We believe that placing debt and equity separately, as we did in this transaction, is likely to yield a lower overall capital cost than selling the unlevered cash flows to a single counterparty.

We also expect yields for this sort of transaction more likely to fall than to increase in the coming quarters.

I'll now turn it back to Lynn for guidance.

Thanks, Ed.

In closing, we are seeing the power of consumer choice shape the energy sector, which has previously been defined by the choices of utilities and fossil fuel supermajors.

We see this trend in electric vehicles, and home solar adoption has grown even faster, with 1 million solar homes now and another 1 million expected by early 2018.

With solar plus storage, we are further unlocking this growth and continuing our ability to build and maintain long-term customer relationships.

In Q2 we expect to deploy 60 MW.

Underlying that is a 100% year-over-year growth rate in Sunrun Direct, offset by a decline in the channel business that we expect will stabilize through the remainder of the year.

For 2016, we expect deployments of approximately 285 MW, but we will focus primarily on delivering NPV of above $1.00 per watt in the second half of the year.

Thank you all for joining us.

I'm going to turn it over to questions, but quickly just wanted to correct one typo in the transcript, the pro forma creation cost for the quarter was $4.11, not $4.09.

So turning it over now for Q&A.

Thank you.

(Operator Instructions)

Krish Sankar, Bank of America.

Hello, thanks for taking my question, and I appreciate the commentary on the discount rate you guys had.

Two quick questions, maybe for Lynn or Ed.

First one, the shift in the consumer behavior towards the direct-sales model, do you think -- or was it leasing -- is that a more cyclical thing driven by financing, price increase or other factors?

So do you think it's actually a structural shift in consumer behavior?

Do you want me to take -- did you have another question?

I can take that one first and then -- So, yes.

So we're not seeing a huge shift.

So where I would start with, first and where we always start with is first principle.

So if you just look at where is there more value for a consumer, it's in the lease system.

The tax benefits are higher when it's owned by a commercial entity.

The consumer benefits from it being managed by a business, and the way that the ITC is structured, where as it declines it actually goes to zero for customer-owned and stays at 10% for leased.

So it's just kind of in looking at where is there more value.

You can really see that it's in that lease system, which is why we're pretty confident that stays the dominant way it gets adopted.

We, as Bob described, I think our mix right now in the quarter was 85% leased, 15% cash.

And so we expect that maybe ticks up to 20%, but that's really more about different marketing channels that we have.

If you actually look at similar sort of channels or distribution, distribution outlets, the leased has really maintained a pretty dominant share.

So I think, for those reasons my expectation is that it maintains the majority.

I think the other trend we may see, is that as these systems start to include storage and as other home monitoring and utility rates move more toward complex time of use rates; I think that'll even more lead people to a managed system by a business.

So we're not seeing a huge shift.

Got it.

That's very helpful.

And then just sort of a follow-up to the [high], you guys talk about being cash flow positive.

Do you think that second what quarter, what year you expect to be, and second, what exactly is the definition of being cash flow positive?

Thank you.

Sure, absolutely.

I'll take that, and then if Bob wants to jump in as well to provide more color, go for it.

So we're trying to make it pretty easy for you guys to model how that happens.

And be pretty transparent about it.

So as we described, the project value is out there.

We've described that we expect that to stay flat.

And we have the financing to monetize 75% of that upfront.

So when those lines cross, you would expect to be sort of structurally cash flow positive.

Now we're not saying that there is a specific order in which that'll happen.

But I think we've given some good guidance in terms of where we think we're going to end up at the end of the year for you guys to be able to extrapolate that.

I think that there's obviously some working capital noise that, obviously would come into play.

But it's a pretty good way to think about cash flow positive in the business.

I'd just say from a big picture, the definition would be when the proceeds from nonrecourse finance and operating cash flows exceeds operating expenses and CapEx, as a broad measure.

Got it.

Thanks, Lynn.

Thanks, Bob.

Patrick Jobin, Credit Suisse.

Hello, good afternoon.

Hello, Patrick.

Hello.

So nice work on the 6.9% unlevered WAC for the levered tax equity transaction.

Can you quantify the size of that portfolio and, you know, just broadly your thoughts on selling assets in this market.

Obviously, very topical with the 8.2% that one of your competitors monetized.

Yes, sure Patrick.

It's Ed.

From a strategic perspective, we want to have access to as many different financing markets as we can.

But that said, sort of absent strategic reasons, we generally prefer the traditional back leverage in ABS markets.

As we continue to think advance rates will decline and we continue to think spreads will decline.

On average, we think we're better off retaining a lot of that.

In this particular instance, the investor approached us, we didn't actually run a broad-based process to identify them.

Going forward, we certainly plan to continue to be opportunistic in our capital strategy, but certainly have a default plan.

As to the size of the transaction, it was $110 million.

For various reasons the assets allocated into the transaction weren't necessarily representative of our overall book, so I'd rather not provide the megawatt number, because I don't know how illustrative it would be.

But $110 million is the transaction to us.

Got it.

And then just I guess two questions.

One, maybe a little bit bigger, and then the other kind of more curiosity.

The first question, can you talk to the energy partnership, the nature of the terms, the agreements, volumes expected this year.

Do we think about second half volumes or economics being close to that $1.00 per watt of NPV, you spoke about.

That's the first question.

And then related to that, the comments on the channel partners being flat from Q2 on a megawatt basis for the rest of the year, but adding in NRG seems to suggest that there might have been some other channel partner pairing back, I guess, from your platform.

Can you speak to that?

Yes, sure, happy to.

You know with NRG, so we're thrilled that they chose to work with us.

I think these guys know the whole industry, and I think it really underscores the fact that we really do believe we deliver the best platform for people to execute on.

We're approaching it in a cautious way, so if you look at our Q2 guidance we're not assuming anything from that partnership.

It's a big organization.

And so we're just kind of cautious in terms of what we put into the forecast.

So I think you'll see that we're just be cautious there.

And the economics relative to other channel partners?

The economics are consistent with the overall strategy.

So, as we discussed on the last call, we really want to run that partner business, and I think have effectively moved it towards a business that no only creates positive NPV but creates positive cash flow Empyrean.

And this partnership is consistent with that.

Thank you very much.

Brian Lee, Goldman Sachs.

Hello, guys, thanks for taking the questions.

Just two quick ones from me actually, one maybe for Bob just on the model.

The sales and marketing expenses, you said $0.80 per watt is the target as you move through year-end, but it seems like you're already lower than that after adjusting for Nevada this quarter.

So, it seems like this is actually moving up through the year.

Did I misconstrue that, or is there something else going on that particular line item besides maybe just the mix shift, in terms of more direct sales as you move through the year?

The primary fact is mix shift, so the way that it works with the channel business is that we do have some of the sales and marketing costs as part of the projects that we buy, so as we continue to have more of a mix of direct -- and it's the majority of our business now.

That's the primary factor, Brian.

Okay.

That's helpful, thank you.

And then just kind of a housekeeping one on the -- for you guys maybe -- the $110 million fund, I know it sounds like the details on that are a maybe a little bit limited in terms what you can share, but can you share what the tenor on the debt piece was?

Is it matching the -- I think you said 20 years, plus 2 years on the renewal that the equity piece was underwriting?

Sure, the that is a 6.5 year mini-firm, so we will be refinanced over the course of equity transaction.

Okay, thank you.

Hello Brian, great questions.

I want to maybe make one comment on the CAC too, because there's a lot of attention and focus on this, and we generally are in the camp of where we're confident that over time, industry CACs are coming down with awareness in automation.

And I think this year our view is -- our view is first of all one; I think it's important to point out that unit economics don't mandate that to happen.

So as you can see, we have still attractive margin and cash flow generation potential at those sort of CAC rates, and in the market, where we are right now, where were try to grow our business, our direct business, at 100% kind of CAGR, which is twice the market in higher revenue markets.

We're going to make the strategic decision to spend a little more on that CAC, and because we think it is the NPV positive strategy.

Thank you.

Stephen Byrd, Morgan Stanley.

Hello, good afternoon.

Hello, Stephen.

I wanted to just discuss your cost structure and understand the goal of continuing to reduce your costs, and you've given some good clarity on your approach.

To the extent that you do fall short of sales expectations, can you speak to how flexible your cost structure is?

What adjustments can you make, sort of as we go through time, as business conditions change, and potentially if volumes aren't where you want them to be.

How can you think about your cost structure?

Yes, absolutely, it's a great question.

I think that's what we're looking at constantly every day, is that NPV equation.

What's the project value, what's the cost structure?

You know, the good news is that we are constantly evaluating what's fixed versus variable, and we're on top of that; and we're pulling the levers, and we're really sort of designing it market by market from a bottom-up standpoint.

So we believe we're not to exposed there.

We have good control over the levers, and we're going to keep watching it.

Okay, great.

And then on the regulatory side, there's been a lot of press around Arizona and the efforts there just to reach agreement.

You have any commentary in terms of the prospects for actually reaching a compromise amongst all the interested parties?

Do you think that's a realistic possibility?

What kind of parameters might -- I know we don't know the outcome yet -- but just, I'm curious about the prospects for both sides actually being able to reach an agreement on that.

Sure.

And are you inquiring about the UNS rate case which is ongoing?

Arizona broadly, if you asked -- understand the scope of the question.

It's really the letter, more broadly in Arizona.

So from a big picture, there are three utilities effectively going through rate cases between now and next summer.

The first two, UNF and TEP, are relatively small and unique.

And then the third one, EPS, obviously is the most important of the three.

We expect EPS is going to file their rate case in June of this year, and it could take approximately a year to resolve.

I think we feel marginally more optimistic about Arizona than we did on the last call.

I think it's kind of moving in the right direction.

And there's the UNS processes is ongoing.

You know, they were seeking a demand charge for all customers.

We're not aware of the utility that has that framework, and for instance, the ARP is involved on that topic as well.

So we're guardedly optimistic.

It will also be the case that before the APS rate case is decided, we will see potentially three new commissioners get elected in November, so that could also swing the outcome.

Generally speaking, I think we also like the way that this election cycle is setting up for the business, in times of historic Republican wins, we've held the line or better.

And we think there's a possibility this one might go the other way and we can make real progress.

So, Arizona continues to be the place that is a more volatile poly situation than our other markets, but I think it's starting to trend the right direction.

That's very helpful.

Thank you very much.

Vish Shah, Deutsche Bank.

Hello, thanks for taking my question.

Lynn, you mentioned the demand as being off to a slow start.

Can you talk about how you think the bookings end-product is looking for the last couple of months?

Have you seen any improvement at all, or are you still seeing some softness?

And then as you think about the tax equity market, are you seeing -- I know you mentioned that you caught sufficient tax equity through the first quarter of next year but how is the industry environment like?

Are you seeing some constraints emerging in that front as well?

And generally financing, besides tax equities though.

Thank you.

Sure.

Thanks, Vish.

You know in the first half of the year, I would say even in the last couple of months there has been more softness than we initially anticipated, and as I mentioned in the script, it's nothing we haven't seen before.

So, this maybe our fourth quarter as a public Company, but we've been operating this for 40 quarters, right at.

And so in the history of that, the consumer demand always sort of ebbs and flows from quarter to quarter because [even] when there's transition periods.

So just take California for example.

If you are a California customer, you know you want solar, you know you can save with it, but you don't know what the rate's going to be.

And it's going to be determined in a year.

So you might just decide, I want to do this but I want to wait for a year until I can understand what my rates look like.

And so that's the kind of -- those are the kind of discussions we see.

The long-term outcome in California is amazing, and we've always seen historically that as you work through those transition periods the demand comes back.

So we're very optimistic, which is why we haven't brought the guidance down, but we do want to be really transparent that it is lower than we expected.

And that again, our priority is definitely going to be about NPV, because what we're really focused on is the long game.

And you look at this market and we want to grow the business at a 30% CAGR for the next 10 years.

And the way to do that is to get sustainable and get to a profit margin and a cost structure that you love; and so that's going to be our focus.

But we are very much not worried about consumer demand.

When you look at our sort of penetration level.

Maybe one other anecdote, I mean this I think is interesting.

If you look at, let's look at Hawaii as an example.

Hawaii, we're now at close to 25% single-family home penetration.

And it's still forecasted to grow this year, at that penetration level.

So that just sort of underscore -- I think it's forecasted to continue up years for the next three years.

So, that just kind of shows you the amount of penetration you can get to, and I don't see that stopping in California and other markets over the long run.

And then perhaps to answer your tax equity question, we feel very good about the environments.

We're seeing new entrant into the sector.

We're seeing larger transactions with our existing partners than we've done previously.

We're also seeing very few investors actually constrained by their tax appetite.

And even, maybe some increased focus among tax equity investors and doubling down on partners who are performing well.

So we are at an all-time high of our tax equity and debt availability with all-time low costs; that environment feels very good.

So just on that front, Lynn, I appreciate the color.

But if -- is your second half volume growth expectation coming from the existing markets, are you looking at new markets?

And if you're investing in OpEx, and if the volumes sort of recover, what else can you do to drive costs down?

Because I think there's not a lot of other leverage that you can pull to go to drive your cost per watt down.

Thank you.

Sure, absolutely.

I think the forecast is the forecast.

I mean, the 285 is existing markets.

I think we said on the last call, no anticipated new states.

So we have the Bottom's Up plan to work this in the markets that we are in, and we think it's achievable.

In terms of the levers that are available to us, I mean similar question to Stephens I think, there are multiple levels available to us.

You can just start by kind of cutting your most expensive acquisition channels and cutting your lowest margin markets.

And so there are actually quite a bit of -- you can also manipulate the top line.

So as we've seen, I think many of us have increased our price slightly in this environment.

We're still at a savings level for our average customer of north of a 20% savings day one, versus the utility, so you that lever to play with as well.

So I think that's what we would do is, is we would look market by market, what do we need to get sustainable?

What are the most expensive acquisition channels to pare back?

What do we need to do in terms of utilization?

So maybe we need to build a bigger back log to have higher utilization, close down a couple of branches, you know there's a lot of levers available to us to being in control of the cost side.

(Operator instructions)

Matt Tucker, KeyBanc.

Hello, good afternoon.

This is actually Greer Buchanan on for Matt.

On the last call you guys mentioned some of the markets you've entered more recently as a potential offset to the loss of Nevada.

Just I know it's only been a couple of months, but could you provide a little more detail on how your business is progressing in those markets?

Thanks.

Yes, sure.

I think what we were trying to communicate was that we have a lot of diversification in the pool.

And then outside of California [relate], I believe we have -- there may be a couple around 10%, but I don't believe we have any market that's north of, sort of a 10% concentration.

And so, I think our hope in making that statement was just giving people comfort that there isn't sort of a Nevada lurking there.

There isn't sort of a state with a 20% share that could be shut down at any given point in time.

So the new markets that we did enter in the year, New Hampshire, South Carolina, I think there may have been one or two others, have been performing, you know, have been performing nicely.

But I think as I mentioned earlier, the growth plan at the 285 [MW] is supported by the existing markets, so we don't need to fill that out.

And so New Hampshire specifically, does the increased cap change anything in terms of your outlook, or was that already contemplated in your plan?

That was one of the examples that we cited earlier, where when there were some uncertainty around there, it does halt the sales a little bit.

So I think that if anything, kind of contributed to some of the early softness.

That market is well below 5% of our volume, as you might imagine.

So just given the size of it.

So it's not meaningful really either way.

Got it.

And then on the tax equity transaction did you, apologies if this is kind of a dumb question, but on the monetization of the renewal component, is there a precedent for that?

Or is that common in most tax equity transactions?

That is, not monetizing a portion of the renewal period.

I think it's been done before.

Okay.

Okay, that's it for me.

Thanks for the time, guys.

Sophie Karp, Guggenheim Securities.

Hello, good afternoon guys, and thank you for taking my questions.

I guess, could you maybe help us square your levered tax equity transaction, and I know you didn't provide the value per megawatt because of the mix, and maybe with the recent transaction.

So I see you did where the monetized at the range of $3.00 to $3.24 per megawatts, per watt; and maybe help us also square it with your own valuation, value creation metric, which is over $4.00 per watt.

And how do you feel that coming together?

Just trying to, anyway understand, crystallize, what the value per watt ultimately is in your mind?

I think from a high level, we think the value per watt of the portfolio is the project value, which is about $4.50 per watt, and on a run rate basis we've said we think the upfront proceeds that we can earn from the $4.50 is 75% of that.

So call it the $3.35 or $3.40 per watt, in that range.

And we think that's the right run rate metric for modeling the business.

So is it fair to say that the variance from this upfront monetization and your ultimate value per watt, is basically attributable to the tail end of the cash flows?

Can you maybe -- I didn't totally understand the question.

In the tax equity transaction, or in what source they did, the cash flows that's a monetize were essentially the first 20 years of cash flow, since so we have are pretty clear understanding now for what they were worth to investors, right?

And so, if you assumed that your overall project value is higher, higher than that, then is it fair to say that entire value, the difference is attributed to the tail end of those cash flows beyond 20 years?

Or am I missing something and maybe your projects are different, and how should I think about that?

Yes, correct.

The difference between the upfront monetization and the project value has two components.

One, is the expected renewal cash flows, and in calculating those renewal cash flows, as we discussed in Q3.

After the Q3 call, we are reporting about a 50% discount to what the likely renewal rates would just be in the contact.

However, in addition, we do not finance 100% of the contracted cash flows as a run rate matter in our business.

So we have more traditionally financed 65% to 75% of those cash flows after tax equity, and that balance of the, call it 25% of contracted cash flows, is also a component of the project value, but not a component of the upfront proceeds that Bob was talking about earlier in the call.

So okay.

Okay, I think that's better.

Thank you.

And I think that's all for me.

Thank you.

Thank you.

Patrick Jobin, Credit Suisse.

Hello, thanks for taking the follow-up.

Lynn, you're making a clear point about consumers taking some pause when rates and regulations are in flux.

But I guess, with NEM 2.0, with time of use rates coming into effect pretty soon, maybe weeks in San Diego, and I guess the final time of use rate structure is not known until early 2017.

I guess, based on your history of how consumers behave in that environment, does the sluggishness in California persist for two, three quarters or how do they act?

And then kind of related to that, you're going to have to sell under NEM 2.0 pretty soon.

Does the selling effort change?

And is it a more difficult sell to consumers?

Or can you still articulate a very simple value proposition?

You can definitely still articulate.

It's a couple good questions in there, and some that, this is a little bit crystal ball here.

But my expectation, having seen this quite a bit over the last 10 years, is I think there may persist a little bit of softness, versus -- I don't think you can totally avoid that one but rates are uncertain.

I think it'll be moderated by just better sales training, and we all have to sort of work that through all of our infrastructure, as we have thousands of people working in California and supporting our customers and our businesses, and the industry globally have even more than that.

So we sort of need to, you know, work it through, simplify the message for consumers.

We're doing all of that.

And so I think that will moderate some of the softness that we're seeing, but yes, it's something that we're definitely going to be watching over the coming quarters.

Got it.

Thank you.

And at this time I'm showing no further questions or comments.

So with that, I would like to turn the conference back over to Lynn for any closing remarks.

Appreciate it.

Thanks, everybody, and we look forward to connecting again in three months.

Take care.

Ladies and gentlemen, thank you for participating in today's conference.

This does conclude the program, and you may now disconnect.

Everyone have a wonderful day.