SolarCity (SCTY)

[jhm]

SCTY's report http://www.solarcity.com/sites/default/files/SolarCity-Distributed_Energy_Resources_in_Nevada.pdf reminds me of another piece of fantasy Comparative Environmental Life Cycle Assessment of Conventional and Electric Vehicles - Hawkins - 2012 - Journal of Industrial Ecology - Wiley Online Library

even a brief cursory view of their methodology would result in extremely generous valuations for the value of utility solar as well.

there is a simple 'sanity check' that easily comes to those in jurisdictions without an integrated electricity monopoly, what would an energy retailer pay for this electricity? Unfortunately for SCTY or NVenergy, its the type question whose answers doesn't match their business plans.

Well, this is the methodology that the PUCN has elected to use, so I won't try to defend it beyond that regulatory function. However, it is worthwhile to consider how utility scale solar would fare under the same cost/benefit methodology.

Utility and rooftop solar share in the same benefits (per kWh) of Energy 3.7c, Generation Capacity 2.6c, and CO2 Regulatory Price 0.9c. But utility solar does not provide the benefits of Line Losses (0.4c for distributed solar), Ancillary Services (0.1), Transmission & Distribution Capacity (2.8c) or Voltage Support (0.9c). Thus, utility solar has a total benefit of 7.2 c/kWh while distributed solar yields 11.4 c/kWh.

On the cost side, distributed solar has 0.3c/kWh for Program and Integration costs. Utility solar would have the same Integration cost plus specific transmission cost depending on specific siting of the plant. Thus, utility solar could have integration and transmission costs in range of 1.3c/kWh.

Thus the net value of utility solar is about 5.9 c/kWh, while distributed solar is worth 11.1 c/kWh. Under NEM, the participant is saving 9.5 c/kWh on their power bill, which is counted as a cost, so the net benefit to the system is 1.6 c/kWh. A utility solar PPA would need to come in at about 4.3 c/kWh to provide the same net benefit, and fortunately PPAs under this mark are possible. Thus, both utility and NEM distributed solar are cost effective and worth adding to the grid, under this PUCN valuation tool.

But what this analysis makes clear is that one cannot simply compare the cost of utility solar to distributed and conclude that either one wins hands down. Distributed solar adds a lot of benefit to transmission and distribution networks that utility solar simply cannot provide.

 

[ggies07]

From this article: A grid of DERs: DOE program aims for 100% solar penetration on the distribution system

“We are so used to utilities having siloed approaches. For example, the people who run demand response programs do not necessarily interact with those who do planning and operations,” Kiliccote said. “We don’t know the cost of our actions. If utilities had more sensors on their networks and combined these data streams and looked at them more holistically instead of in their silos, they would better understand the consequences of their planning and operations decisions.”

Isn't this exactly what SolarCity is offering now to utilities? They have already thought about all of this and are way ahead of the game.

 

[dandurston]

I don't understand why local installers are able to offer lower prices than SolarCity for buying a system. It seems like a switch from buying to leasing shouldn't be a issue for SolarCity and could actually be a positive as it provides more upfront cash flow.

In terms of hardware costs, SCTY with it's higher purchase volume should be able to match or better the cost of the system - and hopefully soon with Buffalo they'll have a real panel cost advantage. Plus they should be at least as good if not better at install costs since they have high volume crews, established training programs and refined mounting hardware (Zep).

Has SCTY just not been aggressive with their pricing for purchases? Or is there some real reason why they can't match local installers. I can see the argument they have more bureaucracy/overhead but that doesn't seem like a major thing. Or maybe it's because SCTY is including extras (maintenance, warranty, inverter replacement) in their pricing?

 

[jhm]

I don't understand why local installers are able to offer lower prices than SolarCity for buying a system. It seems like a switch from buying to leasing shouldn't be a issue for SolarCity and could actually be a positive as it provides more upfront cash flow.

In terms of hardware costs, SCTY with it's higher purchase volume should be able to match or better the cost of the system - and hopefully soon with Buffalo they'll have a real panel cost advantage. Plus they should be at least as good if not better at install costs since they have high volume crews, established training programs and refined mounting hardware (Zep).

Has SCTY just not been aggressive with their pricing for purchases? Or is there some real reason why they can't match local installers. I can see the argument they have more bureaucracy/overhead but that doesn't seem like a major thing. Or maybe it's because SCTY is including extras (maintenance, warranty, inverter replacement) in their pricing?

It is not SolarCity's strategy or customer value proposition to be the low price leader. Thus far, there is no low price competitor that has reached significant scale. When you buy a SolarCity system the company stands behind it for decades. You have service, performance guarantees and warranties. So you are buying a turn-key system, not just the installation of panels and inverters. Consumers who do not value this kind of premium service can certainly go with lower cost installers, but they may also be incurring greater risks. Anyone who has ever hired a contractor to do work around the house knows that there is a very real risk of contracting with someone who does a bad job. So reputation is very important. One of the supreme advantages of a PPA over cash is that if the system does not deliver the kWh output as planned, the PPA provider takes the economic hit. The PPA provider only makes money as actual energy is delivered. But if you paid cash to a sloppy installer, you bear all the risk. If that system underperforms, you eat the loss. This is also one of the reasons why utilities will buy power under a PPA. It's not because they lack the means to own and finance a power plant directly. They simply want to buy the power without risking the equity of ownership. Now SolarCity is quite willing to sell a system outright for cash, but as a PPA provider it does have a reputation to uphold. So the same care that goes into builing and maintaining a system under a PPA needs to be applies to all systems sold. To provide cut rate systems just to compete on price with no-name local installers would expose SolarCity to serious reputational risk. It's got to stand behind every system it builds. That is why this is a strategic choice.

 

[dandurston]

Fair enough. Thanks.

 

[renim]

...
Utility and rooftop solar share in the same benefits (per kWh) of Energy 3.7c, Generation Capacity 2.6c, and CO2 Regulatory Price 0.9c. But utility solar does not provide the benefits of Line Losses (0.4c for distributed solar), Ancillary Services (0.1), Transmission & Distribution Capacity (2.8c) or Voltage Support (0.9c). Thus, utility solar has a total benefit of 7.2 c/kWh while distributed solar yields 11.4 c/kWh.....

look at from the other side
2015 project price for solar is 4.5c/kWh
2016 project price for solar is about 4.0c/kWh

lets start with the 4.0 c/kWh, and subtract generation capacity of 2.6 c/kWh, that leads to an effective cost of 1.4c/kWh. At that price, natural gas plants simply turn off during the day, because solar is cheaper than the cost of the gas. pretty quickly the scenario becomes one where the wholesale price of midday electricity becomes negative, similar to wind power in texas, except more reliably negative prices.

then subtract 0.9ckWh regulatory price, solar utility becomes 1.4-0.9 = 0.5c/kwh wow
at that price pretty much every non rainy day in Nevada is negative wholesale price for electricity from 9am to 4pm.

then realise that Nevada like to co-locate utility solar near users, for example
First solar at coppermountain Copper Mountain Solar 1 | First Solar
First solar at pumpkin hollow mine NV Energy to study solar on Nevada Copper land to power Hollow copper mine in US
MGM solar Mandalay Bay Opens Convention Center’s 350,000-Square-Foot Expansion & Welcomes First Group | Mandalay Bay Resort and Casino
of course the gigafactory, and neighboring sites.

do we start to subtract the Line Losses (0.4c for distributed solar), Ancillary Services (0.1), Transmission & Distribution Capacity (2.8c) or Voltage Support (0.9c) for the solar farms that are located adjacent to large facilities in Nevada. Because in Nevada, utility solar farms/distributed solar can both describe the same physical location.

so from 0.5c/kWh - 0.4c/kWh for distributed solar gives a cost of 0.1c/kWh
0.1c/kWh - 0.1 c/kWh Ancillary Services gives a resultant cost of zero.
zero - 2.8c/kWh for Transmission & Distribution Capacity because its colocated at a mine or casino or industrial park gives a resultant cost of -2.8c/kWh
-2.8c/kWh - 0.9c/kWh for Voltage support gives a resultant cost of -3.8c/kWh

its ludicrous, but imagine how these phantasic benefits really are, from the perspective of a utility solar developer in Nevada.

I could go on, but its kinda silly. But I would point once again, even adding the value of 'generation capacity' to solar is such a cost benefit that day time wholesale electricity prices turn negative.

 

[jhm]

look at from the other side
2015 project price for solar is 4.5c/kWh
2016 project price for solar is about 4.0c/kWh

lets start with the 4.0 c/kWh, and subtract generation capacity of 2.6 c/kWh, that leads to an effective cost of 1.4c/kWh. At that price, natural gas plants simply turn off during the day, because solar is cheaper than the cost of the gas. pretty quickly the scenario becomes one where the wholesale price of midday electricity becomes negative, similar to wind power in texas, except more reliably negative prices.

then subtract 0.9ckWh regulatory price, solar utility becomes 1.4-0.9 = 0.5c/kwh wow
at that price pretty much every non rainy day in Nevada is negative wholesale price for electricity from 9am to 4pm.

then realise that Nevada like to co-locate utility solar near users, for example
First solar at coppermountain Copper Mountain Solar 1 | First Solar
First solar at pumpkin hollow mine NV Energy to study solar on Nevada Copper land to power Hollow copper mine in US
MGM solar Mandalay Bay Opens Convention Center’s 350,000-Square-Foot Expansion & Welcomes First Group | Mandalay Bay Resort and Casino
of course the gigafactory, and neighboring sites.

do we start to subtract the Line Losses (0.4c for distributed solar), Ancillary Services (0.1), Transmission & Distribution Capacity (2.8c) or Voltage Support (0.9c) for the solar farms that are located adjacent to large facilities in Nevada. Because in Nevada, utility solar farms/distributed solar can both describe the same physical location.

so from 0.5c/kWh - 0.4c/kWh for distributed solar gives a cost of 0.1c/kWh
0.1c/kWh - 0.1 c/kWh Ancillary Services gives a resultant cost of zero.
zero - 2.8c/kWh for Transmission & Distribution Capacity because its colocated at a mine or casino or industrial park gives a resultant cost of -2.8c/kWh
-2.8c/kWh - 0.9c/kWh for Voltage support gives a resultant cost of -3.8c/kWh

its ludicrous, but imagine how these phantasic benefits really are, from the perspective of a utility solar developer in Nevada.

I could go on, but its kinda silly. But I would point once again, even adding the value of 'generation capacity' to solar is such a cost benefit that day time wholesale electricity prices turn negative.

I'm very much in favor of collocation large scale solar with industrial load. This too is distributed solar, so no argument there.

I think however that you are abusing this valuation tool. What you are doing is supposing that you can dump so much solar in a given program onto the system at once so as to push whole prices to negative values. This is not how such a tool would be used. For each incremental project you would need a new analysis that looks at the current state of the system and make sensible assumptions going forward. Look at how the Energy assumption was developed in this report. It was based on making assumptions about future wholesale prices at the time that distributed solar would be producing power. This is the 3.7c/kWh benefit. Now, if the state of the system under your proposal were to drive future wholesale prices to 0c/kWh, then this benefit goes to 0c/kWh. Similarly, you'd need to reconsider the Capacity benefit, as a full 2.6c/kWh benefit may no longer be justified when the system is so heavily oversupplied under your proposal. So maybe this comes down to 1.6c. So along with CO2 regulatory benefits of 0.9c, we are looking at a total benefit around 2.5c/kWh.

This is actually quite interesting to contemplate because these are the kinds of barriers that utility solar will eventually face. How do you actually justify adding yet more solar into an oversupplied market? Indeed this must be done to move to a 100% renewable system. So the solution, I think, is that more needs to be offered than just wholesale power with zero emmisions. So collocation delivering T&D becomes one such path. Another would be to include storage with the solar. Suppose you've got a utility solar system with enough storage to timeshift all the power produced. Then you'd be able to value the Energy benefit at the highest daily wholesale price. So maybe this is 8c/kWh. And the capacity benefit is even larger than 2.7c because this is fully dispatchable power. So let's say 4 c/kWh. Also the battery can be used to reduce integration cost for other non dispatchable power and reduce T&D costs. So another 3c, say. And CO2. So you get to a total benefit around 16c/kWh. (This should be comparable to the benefit of a gas peaker.) So proceeding with this sort of project has much greater potential to add significant net benefit, far more than just adding straight utility solar to an oversupplied market. Moreover, if the project has positive net benefit and gets approval, then it actually works in a direction against wholesale prices going too close to zero or below. Specifically, with sufficient storage, such a plant will never sell into the market below a certain price. Ultimately, it is storage that puts a floor on wholesale prices.

I'd also point out that in a free market solar will never take the spot price below zero. Solar can curtail at zero. It is baseload thermal power that has need to pay to feed power into the market so as to avoid a more costly ramp down. Solar, of course, can take the price to zero, but incurs no marginal cost with curtailment. The exception, of course, is when the market is not free and there are government incentives for wind or solar to keep feeding into a negative price market. But in practice, even where the US PTC has done this for wind, these negative markets have also been oversupplied with thermal baseload as well. The reason why I point this out is that as we try to envision what a 100% renewable market may look like, negative spot prices should only exist due to the continued presence of thermal generation. When there is sufficient storage to get rid of fossil peaking plants, then storage will set a lower bound on spot prices, and once the batteries are all charged up, everything else curtails.

So if I am correct in this, what we will see is that utility solar ultimately must get bundled with storage to be a net benefit to the grid. Meanwhile, distributed solar at all scales will become increasingly sophisticated about providing T&D and other grid benefits. These added benefits will be the only way to justify adding more solar to oversupplied markets. I do think this is a tall order for remote utility solar even with storage. The reason why is that distributed solar will be able to add storage at quite near the same cost. So it offers all the benefits of remote solar with storage plus locational benefits to distribution and transmission infrastructure. For example, transmitting battery stored power at a time of peak load adds stress all along the T&D system, but discharging at the point of consumption avoids all this stress. So once cost of wholesale power gets low enough, remote utility solar loses its key advantage over distributed solar, specifically it's low levelized cost per kWh. But before we get to this point, I think we are talking a grid that has over 6 hours of storage at average load. So I think we are looking out at least ten years from now but probably 20 years from now. Right now there is so much opportunity to displace fossil generation, that it just does not matter much. But we can definitely see that SolarCity recognizes the growing importance of properly address all opportunities for DERs to add benefits of location to the grid. Now they are documenting those benefits, and soon they will be optimizing and monetizing those benefits. This is taking the game to the next level.

(Notice that SolarCity will soon make it hard for any new gas peaker to get approval. Is it clear how this is the case?)

 

[doggusfluffy]

Another Voice: SolarCity has raised its statewide job commitment - The Buffalo News

The bottom line is that our total job commitment to the City of Buffalo has not changed, nor has our commitment to spend or incur approximately $5 billion in combined capital, operational expenses and other costs in the state.

Strange bedfellows: How solar and utilities struck a net metering compromise in New York

“Both sides agreed net metering is a successful tool, something that customers understand,” said SolarCity’s Khan. “If we’re going to consider to use it as a customer-facing tool, we’re going to have to incorporate what the commission wanted to do, which is setting a path where their best use is. Based on our experience elsewhere in the country, customers [should] have reasonable certainty [over] what their savings proposition is over the course of their life.”

 

[dandurston]

Short shares drop 8% from 23.6M to 21.7M - so a reduction from ~4.5 days to ~4 days to cover.
Solarcity Corporation (NASDAQ:SCTY) Shorted Shares Decreased By 8.16% - Franklin Independent

 

[doggusfluffy]

It's looking like the Energy bill is getting bogged down with partisan political theater.

Color Dems skeptical: "It looks to me like we're headed for a CR or an omnibus," said Rep. Nita Lowey of New York, the top Democrat on the Appropriations Committee. "It doesn't look like they're going to be able to bring any bills to the floor." ME readers know we've sung this song before: Last time it was the Interior-EPA appropriation and the confederate flag that sunk the process.

HALF A SET OF CONFEREES IS BETTER THAN NONE: We'll probably have to wait until the Senate comes back in 10 days before finding out who its energy bill conferees will be, but the House got things started on Thursday. As Pro's Alex Guillén reports, Republicans named 24 conferees, led by Energy and Commerce Chairman Fred Upton, and Democrats named 16, led by Energy and Commerce Ranking Member Frank Pallone.

This looks promising from the DOE:
Orange Button: A New Data Standard for Cheaper Solar?

 

[renim]

Its my understanding that California has a requirement for Investor owned Utilities to obtain 50% of their energy from renewable (RPS) by 2030. (This seems to exclude both full size hydro and PV self consumption).

Just a cursory glance at CAISO daily demand suggests to me that solar will need to supply nearly 100% of 9am-4pm electricity. With a massively steep ramp following that can only be achieved via battery. Followed by mostly gas power at night. I would suggest that sunny day time wholesale price of electricity will be very cheap, and the cost of night time power will be correspondingly expensive as it now needs to support a lot of asset depreciation.

50% of power is not a big deal for solar
50% of energy is a big deal for solar

look for TOU is California, and batteries, lots of batteries.
Is this good for SCTY, I don't think so,
but it is great for TSLA.

Plenty of room for Buffet to export PV to California, its at the expense of thermal power stations.

 

[renim]

...

I think however that you are abusing this valuation tool....

I agree, but it was based on the documents 2017-2019 forecast, its their abuse of the tool.

...
(Notice that SolarCity will soon make it hard for any new gas peaker to get approval. Is it clear how this is the case?)

yeah, but it still needs to deal with repeating but irregular major weather events. a domestic PV system with 100% net capacity is nowhere near sufficient for 'outlier' weather events, and thats approximately the limit that can placed on a residential house. Even a 200% net capacity system is quite insufficient for 'outlier' weather events.

its from a wet summer 2010/2011, I still remember it because it broke a drought, and caused floods (a semiregular occurrence here, the day the flood hit, the weather had turned fine again) Batteries are great for daily cycling, but for big weather events, they need to be powered by an energy source not in deficit. so not solar. going from 95% renewable to 100% renewable is really hard unless there is reliably dispatchable sources (hydro or geothermal).

Perhaps the US equivalent is what happens when every house has PV, but a polar vortex happens? does the US then just rely on the solar in hot dry areas? In Australia, Tasmania's recent issues suggest that funding new gas power stations would've been wise, compared to decommissioning and offering for sale old gas power stations that are surplus.

What I'm getting at is that an annual 1/2 hour black out, or 1/2 day black out is not that bad
but what if it becomes a once in 6 years, a 6 day contiguous black out instead? to many that won't be acceptable.

 

[Jack6591]

#6211renim, Today at 6:17 PM
Last edited: Today at 6:48 PM
NewIts my understanding that California has a requirement for Investor owned Utilities to obtain 50% of their energy from renewable (RPS) by 2030. (This seems to exclude both full size hydro and PV self consumption).

Just a cursory glance at CAISO daily demand suggests to me that solar will need to supply nearly 100% of 9am-4pm electricity. With a massively steep ramp following that can only be achieved via battery. Followed by mostly gas power at night. I would suggest that sunny day time wholesale price of electricity will be very cheap, and the cost of night time power will be correspondingly expensive as it now needs to support a lot of asset depreciation.

50% of power is not a big deal for solar
50% of energy is a big deal for solar

look for TOU is California, and batteries, lots of batteries.
Is this good for SCTY, I don't think so,
but it is great for TSLA.

Plenty of room for Buffet to export PV to California, its at the expense of thermal power stations.

• 
  

REPORT
− QUOTE REPLY

In my view, you are underestimating the business relationship and "branding" of Elon Musk/Tesla/SolarCity.

 

[jhm]

Its my understanding that California has a requirement for Investor owned Utilities to obtain 50% of their energy from renewable (RPS) by 2030. (This seems to exclude both full size hydro and PV self consumption).

Just a cursory glance at CAISO daily demand suggests to me that solar will need to supply nearly 100% of 9am-4pm electricity. With a massively steep ramp following that can only be achieved via battery. Followed by mostly gas power at night. I would suggest that sunny day time wholesale price of electricity will be very cheap, and the cost of night time power will be correspondingly expensive as it now needs to support a lot of asset depreciation.

50% of power is not a big deal for solar
50% of energy is a big deal for solar

look for TOU is California, and batteries, lots of batteries.
Is this good for SCTY, I don't think so,
but it is great for TSLA.

Plenty of room for Buffet to export PV to California, its at the expense of thermal power stations.

I think California is going to need alot more wind power. This will cover evening through morning and not need nearly as much smoothing from batteries.

BTW I've started playing with hourly data from CAISO. I've been trying to size up how much battery capacity could be used to smooth out supply and demand. The basic metric that I am developing is based on the sum of absolute deviations from a 24-hour average to hourly demand or net demand. This gives you twice as many GWh of discharge needed, but you need about this much capacity to deal with variability and to keep the depth charge between say 35% and 85% most of the time. So California supplies about 24.5GW average. For daily balacing about 2 hour, 50 GWh of batteries, would suffice, and for weekly balacing 9.3 hours, 225 GWh, would suffice. It turns out that there is a lot of weekly periodicity to balance. Tapping into EV fleet charging would substantially reduce need for grid storage, just 1% of autos (250,000) in a fleet charging program could reduce the daily battery requirement by about 2 GWh. Charging on the weekend would also help with weekly load balancing. Adding more wind power has little impact on the daily battery requirement, but solar requires substantially more battery time shifting. So this is the main reason I think the state should pursue much more wind power.

So my analysis is not at all looking at extreme weather events. I think that once California has enough storage for daily balancing, 2 hours, it will be in a good position to use baseload thermal generators to handle variation from day to day. Most coal and CC NG generators are utilized about 45% to 60%. So there is substantial capacity to swing this load from day to day. Peaking plants are really only intended to be used for 1 to 2 hours a day, but just 1 hour of battery capacity will pretty much eliminate that market for short bursts of power. Less flexible but more efficient combined cycle gas plants will be quite adequate for maintaining a sufficient state of charge in grid batteries. So I did take my analysis out to measuring batteries need to balance a whole week. It may take the state more than five years just to 25 GWh of batteries, but the weekly level of 225 GWh may take longer than 15 years. This will no happen over night. But looking out to sufficient storage capacity for weekly balancing gets us to a place where only the most efficient base load plants are needed to make week by week adjustments to the energy inventory in storage. We are talking about a multidecade transition to get to 100% renewables. There will be a glut of thermal capacity over that transition period. So I'm not really worried about building out extra capacity just to handle extreme weather events, and California is not an island like Tasmania. It currently imports about 25% of its power and will continue to use and maintain those transmission assets for quite a long time. I am confident that wind and solar can continue to scale up. The sticky issues are how to scale up battery production, how best to balance the grid with less than 1 hour of storage but lots of solar, and how to manage stakeholders with potentially stranded assets. For battery maker, the key thing is to focus on applications with the very best economics. Once the utilities figure out how to save money and improve service with batteries the market will be quite deep. Consider that the global power consumption is around 2.5 TW. So just getting to a 1 hour storage capacity globally would take ten gigafactories five years of production at 50 GWH/year/factory. It is hard to see a pathway to 2500 GWh of grid storage in the next ten years. So as much as I'd love to see California get 250 GWh by 2030, it's probably not fair that one state would soak up such a large share of the global supply of batteries.

 

[jhm]

What Factors Have Driven Downstream Solar Stocks So Far in 2016? - Market Realist

This is a nice comparative analysis. I think it lends credibility to this industry just to have Market Realist give this sort of treatment to it. Sunrun looks like the hot company, Vivint comes out very troubled, and SolarCity is a clear market leader. I invest in SolarCity and SunPower, which comes across as underwhelming in this line up. I certainly hope that Sunrun can catch up in market share, so it needs to grow at a faster rate. Even so, this horse race is good for attracting investors.

 

[dandurston]

Short shares drop 8% from 23.6M to 21.7M - so a reduction from ~4.5 days to ~4 days to cover.
Solarcity Corporation (NASDAQ:SCTY) Shorted Shares Decreased By 8.16% - Franklin Independent

In the second half of May short shares skyrocketed to 28.0M from 21.7M. Wow.
Solarcity Corporation (NASDAQ:SCTY) Shorted Shares Decreased By 8.16% - Franklin Independent

 

[Jack6591]

@dandurston In the second half of May short shares skyrocketed to 28.0M from 21.7M.Wow.

Any positive or negative catalysts on the horizon?

 

[doggusfluffy]

Something like this could spur a rush to go off grid but it would be an incredible boon to Tesla Energy for batteries on every level for backup.
Why a power grid attack is a nightmare scenario

Also another panel efficiency breakthrough or two wouldn't hurt...
Hot new solar cell

Probably it will take some regulatory or political event to provide catalyst...as if I'm any sort of prediction expert.

 

[dandurston]

Any positive or negative catalysts on the horizon?

I'm no expert, but I think the main thing holding SCTY back is the lack of an obvious difference between the cost and value of the watts they are installing. Last quarter costs were $3.18/watt and they argued for a value of $3.46, but no one really believes that value (e.g. because customers might default, maintenance costs, they recently sold some to Hancock for $3.24 etc.) and even this only leaves 8.8% to cover all the other costs of running a business. So a lot of people think SCTY is breaking even or losing money on the systems they install and their true retained value likely doesn't exceed their debt.

So when SCTY can clearly demonstrate they are making good margin then the stock will go way up. To do this SCTY could:
1) Start selling a lot more systems (instead of PPA) for a price meaningfully higher than costs (they do have a new loan product that started this quarter). Reducing the uncertainty of 20 year cash flows would be huge.
2) Offload their PPAs for higher pricing ($3.50 may be possible).
3) Make real progress in cutting costs towards $2.25 - their 2017 goal. This could occur by getting a handle on sales costs 2016 and by getting their factory scaled up and working cheaply in 2017.

Catalysts like state laws affect the size of the addressable market, but new beneficial laws still aren't going to help much if everyone thinks SCTY is losing money on each system.

Once SCTY can demonstrate a spread >$0.50 per watt on their systems I think the stock will rise above $50. Once they get close to $2.25 we might see $75 and if they also get favourable legislation then it might crack $100. Conversely, if the credit markets tighten or debt piles too high before SCTY can increase their margin then they could be in real trouble.

So in the short term I see new securitization deals and legislation as a potential positives and the ongoing short selling frenzy as a negative. It's actually impressive the stock has risen ~30% with the 6 million new shares sold short.

I think the next ER will probably be a big drop again unless SCTY shows strong bookings and much reduced sales costs.

 

[neroden]

Distributed solar adds a lot of benefit to transmission and distribution networks that utility solar simply cannot provide.

By this methodology, it adds about 4.2 cents / kwh of benefit.

Unfortunately the current premium for rooftop solar over utility solar in the US is higher than that. It needs to come down. This premium doesn't seem to be for fundamental reasons -- it's overhead, marketing, profit margin.