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Updated: 1 year 29 weeks ago

Spirae, Conductor to the Distributed Smart Grid

Tue, 09/25/2012 - 12:59

Distributed energy resources (or DER, in utility industry parlance) are a major headache for utilities. Rooftop solar panels, fuel cells, batteries and other active generators of power are now feeding electrons back into a grid designed to deliver them one way only, from major power plants to end-users.

As if that weren’t bad enough, solar and wind power also generate power intermittently, in sags and surges that can wreak havoc with local grid stability. Add it all up, and you’ve got a recipe for a whole new set of problems that the smart grid industry is trying to solve.

Enter the next generation of virtual power plants, microgrids and other forms of distributed energy controls. Major grid players like General Electric, Siemens, ABB, Alstom, Schneider Electric/Telvent and others are working on the DER challenge, as are defense contractors-turned-smart-grid vendors like Boeing, SAIC and Lockheed Martin.

At the same time, a host of startups like Viridity Energy, Integral Analytics, Power Analytics (formerly EDSA) and others are providing technological and system expertise to the mix, creating virtual or actual islands of power stability and balancing resource amidst the larger grid system.

Spirae is another player in the DER technology space. Founded in 2002, it has grown to a cash-flow-positive, profitable status via a host of contracts aimed at controlling distributed energy resources at a grid operations scale, CEO Sunil Cherian said in an interview last week. The company has taken no outside investors: “We eat what we kill” is how he put it.

Spirae has landed some interesting projects to feed its coffers, including FortZED, a Department of Energy-funded project in its hometown of Fort Collins, Colo., which wants to achieve zero net-energy status by generating more renewable power over the course of a year than it uses. On a grid-wide scale, it’s one of many partners on the $178 million Pacific Northwest Smart Grid Demonstration project, meant to link the region’s wind power, hydropower and distributed energy resources into a more integrated, balanced system.

In Denmark, Spirae’s projects also range in scale from its “smart city” project with the municipality of Kalundborg, aimed at achieving energy balance via efficiency and distributed power, to the grid-scale “cell controller” research project with Energinet.dk, the Danish transmission system operator.

Another Spirae partner is Boeing, which has enlisted Spirae’s help on a $6 million DOE grant-funded project with Chicago utility Commonwealth Edison. Spirae is working with Philadelphia-based Viridity Energy and San Diego-based Power Analytics (formerly named EDSA) on the Boeing project, a team it’s also involved in at the University of California at San Diego’s microgrid project involving solar power, batteries and smart building controls.

“We’re looking at a portfolio of resources, and our assumption is that this portfolio comes and goes; you don’t have the certainty of a power plant in this case,” he said. That rule applies to intermittent generation sources, of course -- but it also applies to power users, who can change their consumption in ways that are hard to predict.

But smart grid technology -- two-way digital communications between utility control rooms and endpoints on the grid -- is changing that equation. Distribution automation can help utilities fine-tune grid control systems to balance intermittent solar or wind, and demand response can call on lots of customers to lower their power consumption to help smooth out instabilities at a local level, to name two examples.

Spirae’s expertise is in the complex control algorithms used to balance the grid-side systems with the building-side energy resources, Cherian said. For example, in Fort Collins, Spirae has implemented a system that helps balance reactive power, using technology similar to that deployed for volt/VAR optimization projects, to keep the city’s power mix in balance with the grid, Cherian said.

Spirae’s system includes a hardened control box or server, called the BlueFin, that plugs into utility SCADA systems and other networks, but it can also deploy its underlying technology via similar gear from partners, he said. BlueFin can also plug into end-user systems like generation plant controls or building management systems, which allows it to call demand-side resources into play, he said.

That could give the utility, or a demand response aggregator, the tools to use often-idle building power controls to help balance what’s happening on the grid at that moment, he said. While Spirae’s technology wouldn’t turn down the thermostats itself, it could tell a thermostat control platform how many homes it needed to tap to balance what’s happening on the grid at that moment, he said.

Spirae tests its technology in the InteGrid Test and Development Lab in Fort Collins, which it co-owns and operates with Colorado State University. It’s all part and parcel of the R&D nature of its work. After all, most utilities don’t yet face the challenge of managing a significant share of customer-generated power, or keeping double-digit penetration of wind and solar power in balance.

Over the next three years, however, Cherian sees utilities shifting from exploring their options for managing the DER challenge to actually implementing it on a broad scale, with Europe ahead of the U.S. in terms of growth. Making the transition from pilot project to commercial-scale product would be the next step in that transformation. 

Geothermal Utility Launches in Colorado

Tue, 09/25/2012 - 09:00

The recent success of solar PV has nothing to do with the sun shining brighter. Instead, the uptake in solar is largely due to falling technology costs and new financing schemes that don’t rely on homeowners or businesses to shell out cash upfront for an entire system. 

Solar models are now informing other renewable energy technologies, namely, geothermal heat pumps. Unlike geothermal power plants, which involve deep drilling to access naturally occurring reservoirs of hot water, geothermal heat pumps sit far closer to the surface and provide heating, cooling and hot water at a fraction of the cost of conventional systems. Despite the incredible resources for different geothermal technologies in the U.S., these vast resources remain largely untapped for many reasons. 

The upfront cost of a closed-loop geothermal heat pump, which involves installing a series of liquid-filled underground pipes, has kept the technology on the sidelines. In Colorado, that could become a problem of the past. PanTerra Energy has become the first private company to be registered with the Public Utility Commission as a geothermal utility in Colorado.

“If you were installing gas, the gas utility would bring the gas line to your facility, then you’d pay for access to it,” said Mike Ryan, president and co-founder of PanTerra Energy. His company does not claim any technological improvement on the closed-loop systems that are already out there, but it is offering a scheme similar to a power purchase agreement that allows institutions to get geothermal without shelling out the millions of dollars to build the system, because PanTerra owns and operates the infrastructure.

“If you can provide users with a straightforward monthly cost for their heating and cooling, without the added financial burden of buying the loop field infrastructure, then GHPs can quickly become a mainstream technology," Ben Northcutt, executive director of the Colorado Geo Energy & Heat Pump Association, said in a statement.

Closed-loop systems sit dozens -- not hundreds -- of feet below the surface. At that depth, the earth’s temperature is fairly constant (about 55 degrees Fahrenheit) so that air from the surface can be moved through to warm it in winter or cool it in summer. (The steady temperatures can be as few as 10 feet under our feet.) A geothermal heat pump passes the air below the surface and uses 25 percent to 70 percent less energy than conventional heating and cooling, according to PanTerra Energy. 

Installing the system of pipes below the ground isn’t unheard of; there are installations in all 50 states. Ryan said, “Geothermal has been used for decades and has been successfully used in schools, jails and commercial structures.” Ball State University in Indiana, for instance, has the nation’s largest ground-source, closed-loop geothermal system, which will supply heat and cooling to 47 buildings on campus when it’s complete. The university will be able to shut down four coal-fired boilers.  

Even though geothermal heat pumps aren’t new, the way the industry is designed has made it difficult for prices to come down. PanTerra assembled the disparate parts of the geothermal ecosystem in one place, combining drilling, installation and financing. The Englewood, Colo.-based company, which just launched last year, is in talks with towns, counties, universities and correctional facilities. The technology can be used in residential applications, but for now the focus is on commercial and municipal applications.

Colorado has had a statute on the books since the 1980s stating that a geothermal company could be treated as a utility, but it was a chicken-and-egg proposition, as the company needed to already have had completed a project that’s been defined as such in  order to receive the designation. Of course, no project would get green-lighted without Public Utility Commission (PUC) approval.

PanTerra worked through the process by coming to an agreement with the PUC to get a preliminary registration to go forward and land projects that can then be permitted by the PUC.

Although the first contract has yet to be inked, there is already interest from other states, including California and Rhode Island.

If PanTerra is successful in landing customers and managing geothermal systems as the first geothermal utility, it will hardly offset existing utilities. Traditional utilities still need to keep the lights on and power the electrical outlets. If anything, geothermal utilities could be a benefit to utilities, as there are no air-conditioning peaks with geothermal the way there is with traditional AC. 

Even if the technology isn’t new or disruptive, it doesn’t mean there isn’t a lot of work still to do. “The PUC has been very receptive,” said Ryan. “But when you’re the first one that’s doing this, you are in some ways creating the wheel.”

Big Wind: 845 MW Shepherds Flat Wind Farm Marks Opening

Mon, 09/24/2012 - 17:00

With the pending expiration of the production tax credit for wind threatening to put the kibosh on new projects, the nation’s second-largest wind farm, an array of 338 turbines scattered over thousands of acres of wind-buffeted hills just south of the Columbia River in north-central Oregon, officially began full operations on Saturday.

Along with cheers from renewable energy advocates, the completion of Caithness Shepherds Flat brought reminders of the heavy subsidies that supported its development -- and, ironically, highlighted the gloomy state of the wind industry in the United States in the waning days of the PTC.

This 845-megawatt Oregon project has been coming on-line in increments, sending power under 20-year agreements to Southern California Edison and helping the utility meet its obligations under California’s aggressive renewable portfolio standard. With the entire project finished, Caithness Energy, politicians and assorted partners in the project -- including Google, which invested $100 million -- did the ribbon-cutting thing.

In doing so, they called Shepherds Flat “one of the world’s biggest wind farms,” apparently not interested in picking a fight with the Alta Wind Energy Center in California, which checks in at 1,020 megawatts (and growing). Alta has several units, and some people apparently don’t want to add them all together and call it the biggest wind farm, and instead give that title to Shepherds Flat. But Shepherds Flat itself is made up of three units, according to the Oregon Department of Energy: Shepherds Flat North (265 megawatts), which was completed in February; Shepherds Flat South (290 megawatts), completed in July; and Shepherds Flat Central (290 megawatts), where work was wrapped up in August.

Anyway, they both seem to lose out to Jaisalmer Wind Park in India, which reportedly reached 1,064 megawatts in April.

What might truly distinguish Shepherds Flat is the level of taxpayer support it received. Even within the Obama administration, there was concern expressed on this count: An October 2010 memo to President Obama by three senior White House advisors detailed how developers were able to pile several different subsidy programs into a mountain of benefits that left them with “little skin in the game.”

The memo noted that Shepherds Flat’s developers received a $500 million federal grant, state tax credits totaling $18 million, accelerated depreciation on federal and state taxes worth $200 million, and a premium for its power from the state worth $220 million. On top of that, a $1.3 billion partial loan guarantee provided $300 million in benefits to the developers, bringing the total subsidy for the $1.9 billion project to nearly $1.24 billion. The memo speculated that the project would have happened without the loan guarantee.

In celebrating the project’s completion, however, the developers and supporters said the support Shepherds Flat received was well worth it. They put the focus on the project’s benefits -- and even Greg Walden, Oregon’s lone Republican in its House delegation and a favorite of Speaker John Boehner, was on board.

“This project has created jobs during a very tough time for rural areas of Oregon, and has added to the tax base as counties are struggling to provide basic services,” Walden said in a statement. “Moreover, the wind energy produced at Caithness Shepherds Flat will be part of an ‘all of the above’ energy strategy that this country so desperately needs.”

Caithness Energy said Shepherds Flat “will eliminate 1.483 million metric tons of CO2 annually, the equivalent of taking approximately 260,000 cars off the road.” The company said the turbines will spin out “an estimated 2 billion kilowatt-hours each year,” equivalent to the total used by 173,000 average Oregon homes annually. Some 400 workers were on the job building the wind farm for more than two years, and 45 workers will be employed operating and maintaining it.

Shepherds Flat apparently took advantage of the investment tax credit cash grant instead of the production tax credit for wind. But the cash grant option for the investment tax credit is gone, and without congressional action in the lame-duck session later this year, the PTC will be, too, for projects not completed by the end of the year. Job losses are already mounting throughout the industry supply chain, and the American Wind Energy Association predicts the expiration of the PTC could result in the loss of 37,000 jobs.

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Editor's note: This article is reposted in its original form from EarthTechling. Author credit goes to Pete Danko.

$197M DOE Loan Landing at Oregon’s SoloPower for Flexible CIGS Solar Panels

Mon, 09/24/2012 - 15:15

Can solar startup SoloPower prove the commercial business case for flexible CIGS solar panels and improve the optics of the beleaguered DOE loan guarantee program?

SoloPower, a flexible solar panel manufacturer, starts production at its 400-megawatt capacity Oregon factory this week, according to Reuters.

That milestone lets SoloPower begin to access a $197 million DOE loan guarantee -- the firm "must have its first production line up and running and meet other undisclosed milestones before it can begin to draw down funds," according to the Reuters piece.

Earlier recipients of loans from the $35 billion DOE loan guarantee program for solar manufacturing include the defunct CIGS thin film aspirant Solyndra and the defunct cadmium telluride thin film firm Abound Solar. The firm 1366 Technologies also won a $150 million loan guarantee but has yet to draw down funds.

Abound's failure is indicative of the difficulty of competing against Chinese crystalline silicon solar with U.S.-based manufacturing, a challenge also faced by SoloPower. SoloPower claims it can extract a premium for it unique flexible panel -- but it still essentially must compete against solar panels from China and the U.S. with costs of $0.70 per watt.

SoloPower is going after the same rooftop market as Ascent Solar, Global Solar, and the now-bankrupt ECD, except it is doing it with a more efficient product. The value proposition for flexible modules from SoloPower is that there is less hardware required to install the modules and the installation is easier and less expensive. However, this thesis has yet to be proven in volume and scale.

The other alleged advantage of flexible CIGS solar panels is that their lightweight nature opens up "value-engineered" rooftops that could not support the weight of conventional crystalline solar panels. This thesis also remains to be proven.

SoloPower CEO Tim Harris said in the interview with Reuters that half of the buildings in the world can't bear the weight of heavy, rigid panels made with silicon. Others have claimed, "Each and every commercial roof in the developed world can withstand the extra 3 to 5 psf dead load required to support a glass panel PV installation." The company claims that lighter weight makes installation easier and reduces the cost of balance-of-system components. Certainly, it can reduce the cost of racking, which adds about $0.25 per watt.

SoloPower has raised more than $200 million from Hudson Clean Energy Partners, Crosslink Capital, Convexa, and Firsthand Capital. The firm has also won significant tax credits and incentives from state government.

Earlier this year, SoloPower raised the bar a little higher on the efficiency of its flexible solar panels, and is now boasting an NREL-measured aperture-area efficiency of 13.4 percent. Module efficiency for the firm's SF1 panel is 11.4 percent, according to Tim Harris, the CEO. The SF1 panel is optimized for metal roofs and has a junction box that is located on the front of the panel. The firm's panels are built with a roll-to-roll electrodeposition process.

I interviewed personnel at the firm last year; the CEO told me that capex is "way under a dollar [per watt]" and production cost is "competitive." Harris claimed his firm already has more orders than it can fill with a product targeted to regions with high electricity prices and rooftop solar subsidies.

Solar panels manufactured in the CIGS thin film materials system have long held the promise of high efficiency at low costs but have yet to deliver -- despite billions of dollars invested by venture capital investors. Solyndra is the most prominent failure, but other CIGS companies like AQT have faltered as well. CIGS firms HelioVolt and Ascent Solar gave over their firms to Asian conglomerate SK Group and TFG Radiant Group, respectively. Nanosolar has shipped in the neighborhood of ten megawatts of solar panels over the course of ten years and three CEOs. MiaSolé, despite strong technical achievements, has been forced to lay off a large fraction of its employees as its management looks for an acquirer or partner. Q-Cells sold its CIGS effort, Solibro, to Chinese power firm Hanergy.

The only way SoloPower can buck this trend is with very low costs, good efficiencies, high reliability and the sheen of bankability.

Better, Faster Corporate Venture Investment in Cleantech

Mon, 09/24/2012 - 15:00

Venture capital firms are pulling back from the greentech sector. The number of cleantech-focused VC partners is thinning.

The greentech IPO market is stingy at best. There have been just 27 venture-backed cleantech M&A deals worth more than $50 million over the last ten years. VC investment in solar and smart grid has long since peaked and we are in an era of painful startup attrition in solar.

Cleantech VC is having a hard time.

Perhaps a relative brightspot in the cleantech investment landscape has been the increased involvement of corporate VC arms and strategic investors. Corporate venture investment in cleantech was $620 million in Q2 2012, up 319 percent from Q1 2012, according to CB Insights. This year, late-stage funding from firms such as Monsanto, BASF and Wanxiang Group have funded Sapphire, NanoH20, and GreatPoint Energy, respectively. Five of the top ten VC deals in Q1 had corporate participation, as did a quarter of all deals.

Corporate investors have different revenue expectations and timeframes than standard VCs. They also have potentially deeper pockets.

But the traditional complaint hurled towards corporates by VCs was that the deals took too long. 

Broadscale Group looks to act as a clearinghouse to link growth-stage cleantech firms with its network of corporates, including Duke Energy, General Electric, and National Grid. Pegasus Capital Advisors, a PE fund manager, is also part of the consortium.

The idea is that growth-stage firms get fast access to big-name sources of capital, distribution, and demand.

Broadscale CEO Andrew Shapiro said, “Capital is necessary, but not sufficient. New models of collaboration are needed to scale up breakthrough solutions." Duke Energy’s CEO James E. Rogers said in a release, “We believe this network approach can help us to cost-effectively identify and benefit from promising new energy solutions.”

Perhaps Broadscale, by adding a bit of competition, can get corporate investors to move a little more aggressively into cleantech.

Guest Post: Why Tradable SRECs Are Ruining Distributed Solar

Mon, 09/24/2012 - 14:00

The following is a guest post from the North Carolina Solar Center, which includes the Database of State Incentives for Renewables & Efficiency (DSIRE).


I write this article as someone (1) who could not be more interested in how the different state solar renewable energy credit (SREC) trading markets are structured and how they operate, and (2) who as recently as a couple of years ago felt SREC trading markets represented a real breakthrough for incentivizing solar. Notwithstanding the title of this guest post, hopefully that little introduction establishes my credentials as a student (figuratively) and an analyst of public policy rather than a zealot. In any case, perhaps a better way to put it is to say that while in most cases, distributed solar needs some form of supplemental incentive beyond federal tax credits and net metering, it doesn’t need tradable SRECs.

Why not? The arguments below may not be new to anyone who operates in the eastern U.S. solar landscape, but sometimes part of persuasion is presenting ideas in a new way. I’ve certainly persuaded myself of the merits of my arguments, so let’s just see if I can persuade anyone else. Tradable SRECs are ruining distributed solar because:

1) They Enhance Risk. There are plenty of people who remain skeptical of even the basic concept of solar electricity (i.e., the technology is too new, inefficient, and unreliable). This is not surprising, but what is surprising is how we could arrive at a system that takes what many see as a risky investment in the first place and introduces additional risk. Of course, every investment carries a certain amount of risk, and there will always be elements that are beyond control and predictive capabilities of even the most sophisticated operator. The chosen policy path cannot and need not eliminate all risks, but it seems reasonable to ask that it not exacerbate them by subjecting adopters to the whims of markets that few would describe as well-functioning, transparent, or predictable beyond the near term.

And yet, for a while it seemed like this didn’t matter. We’ve seen huge investments in some state markets, resulting in supply that far outstrips the mandated demand. How did that happen? Certainly, exogenous influences like the 1603 grants played a role, but the potential upside also attracted investments by those with an apparent tolerance for risk, as well as by those who did not fully understand the risk. I think that the shoe is on the other foot now. In New Jersey, for instance, we now have a demonstrated rather than theoretical risk, in the market that many of us, myself included, thought was less vulnerable than the rest due to its size. The question is: Is there anyone out there who is willing to bet that it won’t happen again? To quote a prolific figure in U.S. history, “Fool me once, shame on you. Fool me twice, won’t get fooled again.” If we’re not fools, then un-contracted SRECs now have zero value in stimulating investment even among risk-tolerant parties. If they have zero value, what’s the point of using them as a financial incentive?

2) SREC Markets Don’t Balance Themselves. To follow on my prior point, it seems that the sole truly accurate prediction that we can make about SREC markets is that they exhibit a very tenuous balance between supply and demand. The empirical data we have indicates that maintaining anything resembling a balance between supply and demand for an extended period of time may well be impossible. What we’re left with then are two undesirable outcomes: (1) undersupply, where we live at or near the alternative compliance payment (ACP) and end up over-subsidizing projects, or (2) oversupply, where prices plummet far below the levels needed to stimulate new investment. Nothing I’ve seen suggests this is anything less than a certainty. As currently designed, SREC markets simply cannot balance themselves.

One could argue that oversupply is proof that the system works. After all, what we want is more solar, and we want it cheap, right? That’s an interesting argument, but a poor one. My response is yes, it worked… to create a market bubble. Seeing this as a good thing is akin to seeing the housing bubble as a good thing because it increased home ownership. In the long run, bubbles are damaging, and the lessons they teach us can be exceedingly harsh.

Are there solutions to this? Absolutely! All we need to do is readjust and revise the standard every couple of years. The historical record is well populated with solar carve-out “fix” examples. During 2012 it was New Jersey (S.B. 1925) and Maryland (S.B. 791). During 2011, the District of Columbia effectively took its carve-out from perpetual oversupply to perpetual undersupply (D.C. Law 19-36). Delaware went the market fix route in 2009 (S.B. 173) and 2010 (S.S. 1 for S.B. 119), while New Jersey (A.B. 3520) and Maryland (S.B. 277) both show up again in 2010. Legislative fixes are probably better than the alternative (e.g., Pennsylvania’s dismal solar market), but I question whether the continuance of this pattern is the most efficient path to a sustainable industry.

Well, perhaps we could set up the adjustment system in advance, right? We’ll know soon how well the Massachusetts annual adjustment system works. The recent Massachusetts Department of Energy Resources (DOER) announcement of potential revisions to the annual solar compliance calculation suggests that it sees an oversupply problem on the horizon. Whatever the chosen path, in order to maintain SREC price stability, market participants have to believe that the system will work. I’m not sure the industry as a whole currently has the requisite level of confidence. In the long run, maybe policymakers will design a system that functions well and inspires confidence. The problem with banking on such a solution is that it leaves the industry stranded indefinitely, and if costs continue to spiral downward at recent rates, it could well end up solving a problem that no longer exists.

3) SRECs Are Too Complicated. There are hundreds of articles and blog posts out there about selling solar to potential customers. It is pretty clear that even without adding SRECs to the picture, understanding the mix of federal and state incentives is daunting. This applies both to providers and their customers, since on the behind-the-meter side, the provider must understand all of the ins and outs and be able to convey them to customers in a coherent, understandable, and presumably persuasive manner. Some readers may recall a 2011 guest post by Travis Bradford positing that customer acquisition costs can add up to 20 percent to the cost of a residential system in California. Yes, California, a state without SRECs.

I’ve spoken with many businesses and consumers about SRECs during the past five years. While most of them understand the concept easily enough (i.e., “The utility is going to pay me for these, right?”), I’ve rarely been left with the impression that they grasp all of the important details, rules, and risks involved. This leads me to believe that the use of SRECs as an incentive may well play a role in increasing customer acquisition costs, or result in unwise consumer decisions due to lack of understanding. Neither is a good thing. Yes, third-party owners take a lot of this on their shoulders and simplify the decision-making process, but one has to question the logic of a system that makes an already complicated decision more complicated.

4) Some Parties Bear Disproportionate Amounts of Risk. Hopefully, I’ve established that the average residential system owner, small business system owner, or otherwise unsophisticated solar investor shouldn’t be forced into the SREC market. Unfortunately, under the current systems this is often unavoidable and these investors are consequently subject to market fluctuations they have no hope of anticipating. Call me crazy, but I really don’t think the completion of a solar farm 150 miles away should influence the financial incentive for the 5-kW system on my roof, or the 200-kW system on the local school. This isn’t to say that projects like the Dover Sun Park in Delaware (10 MW, and incidentally the focus of Delaware’s 2009 solar carve-out fix legislation), the Turning Point Solar Project in Ohio (50 MW), the Mt. Saint Mary’s Solar Project in Maryland (16 MW), or the hundreds of other large-scale solar projects in the PJM Interconnection Queue are bad for solar, but they are potentially bad news for a lot of small system owners. Certainly, the solar farm owner understands (or should be expected to understand) SREC price risk and is equipped to counter it in some way. The same is not true and should not be expected to be true for the small-scale owner.

Risk is distributed unevenly in other ways as well. In New Jersey, for instance, PSE&G has made significant investments in various types of solar projects under its Solar 4 All program, and it has indicated an intention to continue doing so. Great! I like to see utilities embracing solar. My complaint is that under the terms of the program, PSE&G can make this investment with no SREC price risk whatsoever. The utility makes the investment and earns a guaranteed rate of return on that investment. It has no SREC obligation itself, so it auctions off the SRECs generated by the project to suppliers that do have obligations. The revenue from SREC sales offsets the overall cost of the program, as does the sale of energy into the PJM wholesale market. No SREC upside to be sure, but no downside either.

A similar (but not identical) argument can be made for any investment by a utility or supplier that has an RPS obligation. Under standard ratemaking, the utility earns a return on its investment and recovers costs associated with RPS compliance. A competitive supplier is in theory subject to price risk in that if it builds beyond its RPS obligations, it could have unused SRECs in a low-priced market. But I’ll hazard a guess that suppliers know more about their long-term plans than you or I, and they make decisions based on that knowledge. It’s not unlike a card game, where utilities elect not to play but get a cut from house rake. Suppliers can opt-in if they like, with the added bonus of having a few extra cards that no one else can see. None of this is to say that utilities and suppliers shouldn’t have every opportunity to share in the market, but the playing field is most certainly not level.

5) SRECs Guarantee a Certain Amount of Added Cost. Pure and simple, SREC markets cannot function without the services of aggregators, brokers, traders, or other middlemen, and these services carry a cost. I’m not criticizing the occupation, and I’ve met some very smart (and nice) folks who happen to be of the SREC middleman ilk. To be fair, the costs are typically pretty modest and are probably worth it for the service. For instance, for small transactions, SRECTrade charges a seller’s fee of 2% of the clearing price and a buyer’s fee of $5 per SREC. The Massachusetts Solar Credit Clearinghouse charges the seller a 5% administrative fee, which amounts to $15 per SREC at the fixed $300 per SREC auction price. Not huge numbers, but costs that nevertheless represent one more aspect of the “death by a thousand cuts” series of soft costs that plague the distributed solar industry.

With all this in mind, what should we do with current suite of solar carve-outs? Transition them to feed-in tariffs? Not necessarily, but many would argue for such a path. One of the most fundamental errors people make when pondering solar carve-outs is assuming that a solar carve-out must result in an SREC trading market. A solar carve-out is simply a target; it is not a path toward meeting that target. The target has value in that it creates a long-term signal to the market, but it need not compel SREC trading. The California Solar Initiative (CSI) accomplishes the same long-term signal without establishing a solar carve-out. Perhaps the CSI is not as simple as some would like, but it is much easier to understand than an SREC market -- and much more predictable. States already have the targets; all that is needed is a more predictable system for meeting those goals.

The chief arguments against a more formulaic approach is that such programs are inherently more costly and self-limiting (i.e., capped in some way to limit costs). With respect to the first, the principal of net present value (NPV) should be considered. The NPV of a three-year strip of SRECs at $400/MWh (i.e., close to a hypothetical ACP), plus seven additional years at $65/MWh is equivalent to a 10-year strip of SRECs at $200 using a 10% discount rate. One can certainly play with those numbers, but the fact remains that in an NPV calculation, we would rather pay less now and more later. With respect to program limits, I expect that the industry and customers would prefer a program that sunsets periodically for a short period to one that could be sidelined for multiple years at a time if exuberance exceeds wise judgment. As a potential solar customer, I’d certainly rather miss one boat and have the chance to be on the next one than make an investment that does not meet my expectations for reasons that are generally beyond my ability to control or anticipate.

Distributed solar doesn’t need a huge upside to prosper; it needs a reduction in the downside risk. Distributed solar needs an incentive, but it doesn’t need SREC markets.


Want to learn more about the North Carolina Solar Center and DSIRE? Click here.

Want more comprehensive data on SRECs in the U.S.? Click here to learn more about GTM Research's SREC Market Monitor.

Emerging Solar Strategies, Part 3: DuPont’s Push for Quality Standards

Mon, 09/24/2012 - 13:00

Solar installations were removed from twenty-four San Diego Unified School District campuses after corrosion was discovered that threatened the possibility of electrical issues that could lead to fires.

The 4.3-megawatt installation was built in 2005-06 by Solar Integrated Technologies (SIT). SIT was acquired by Energy Conversion Devices (ECD) (PINK:ENERQ) in 2009. ECD’s Uni-Solar manufactured the panels. SIT built the integrated solar-electric systems made up of Uni-Solar PV panels and Sarnafil roofing material.

Both ECD and SIT filed for bankruptcy earlier this year. 

The panels were installed through a third-party ownership (TPO) financing agreement in which the school district made no upfront investment. SIT had responsibility for operations and maintenance. GE Financial Services (NYSE: GE) was the twenty-year lessor.

Due to the other parties’ bankruptcies, GE Financial Services took on the removal of the solar systems, at its own cost, though it had no legal obligation to do so. The only loss to the school district was the promised electricity bill savings.

It has been reported that a manufacturing defect in the panels allowed water seepage, corrosion and the potential for fire-inducing short circuits. “Workers have not yet reached a final conclusion as to the exact cause of the problem, and it would not be prudent to speculate,” GE spokesperson Christa Bowers told GTM.

This is a wakeup call for the solar industry. It explains DuPont’s recent initiative, in partnership with solar developer Distributed Sun (D-Sun), which finances, constructs, owns and operates PV power plants, to establish specifications for module materials that will “raise awareness of the importance of durability and reliability” of panels in the bankability of solar projects.

And it explains why DuPont Innovalight General Manger-Founder Conrad Burke is crusading for more quality control in module materials.

DuPont's (NYSE:DD) 2011 $1.4 billion in sales to the solar industry makes it one of the world’s biggest suppliers of panel and parts materials such as metallization pastes, resins, encapsulants, back-sheet materials, thin film substrates, silicon inks, vacuum seals and junction box structural materials. “Half of the approximately 300 million solar panels that have been installed around the world over the last 35 years have some kind of DuPont materials,” Burke said.

Low-cost modules and a rising tide of funding for TPO financing have fueled an unprecedented solar expansion in the last two years, but there is growing concern about the loss of quality.

The bankability of solar installations will come into question if major funders find themselves saddled like GE Financial Services did with the San Diego incident. Without their capital, financing would be harder to obtain and solar would be more expensive.

Yet intense competition among module manufacturers is driving them toward cheaper, less reliable materials, according to Burke. “There is a race for survival. Corners are being cut.” Some manufacturers are losing sight of the fact that “if you can make a solar panel last longer, your financial returns and your investment returns improve and materials matter a great deal in that.”

Burke foresees a $100 billion solar industry within a few years, but says that “between where we are today and getting to that point, I think we’re going to have some bumpiness.” Industry consultant SolarBuyer LLC, he explained, predicts that more compromised projects, like the one in San Diego, will emerge. “Consumers are going to benefit from cheaper solar panels and we’re all for that here at DuPont because it will make solar more affordable. But quality, reliability and performance should not be compromised.”

 

Once a design defect is eliminated, there are three kinds of testing of materials in “an integrated, quality focused procurement process,” explained PV Evolution Laboratories CEO Jenya Meydbray, who now does independent solar product testing after running SunPower’s supplier qualification program for five years. Meydbray wants to see the industry adopt practices like “upfront, long-term testing to evaluate the product, factory audits while the products are being manufactured, and spot checks of the product when it hits the ground at the project site.”

“We have statistical models,” Meydbray continued, “that define the conclusions you can make based on testing. If your bank wants you to be 95 percent positive that your products are defect-free, that means you have to test a specific amount, statistically. If your risk tolerance is a little bit looser, and your budget is a little smaller, maybe you can get away with an 80 percent confidence level.”

What happened in San Diego, he speculated, was “probably a combination of [problems with] workmanship, quality control, and materials.”

These are “early days,” Meydbray said, “in an incredibly competitive space where nobody is making profit. There is mass consolidation. People will have massive solar fleets where the warranty is worthless because the manufacturer doesn’t exist anymore. That will impact the residual value of plants, when they start changing hands.”

There are, he said, “a lot poor systems and negative investor returns from poor quality things going out there.”

He remains a staunch solar advocate, Meydbray said. “There are a lot of excellent performing systems and excellent products out there. But the reality of today’s market is you have to rely on what you’re buying, not who you’re buying it from.” 

BrightSource Energy Versus LA Times

Mon, 09/24/2012 - 00:29

This was the headline: "Taxpayers, ratepayers will fund California solar plants; A new breed of prospectors -- banks, insurers, utility companies -- are receiving billions in subsidies while taxpayer and ratepayers are paying most of the costs. Critics say it's a rip-off." The front-page Los Angeles Times (LAT) story last week raised questions about the economics of the newest generation of concentrating solar power (CSP) plants.

Because its Ivanpah solar power tower project got special attention, BrightSource Energy (BSE) responded.

LAT: “The cost for decades to come will also be borne by ratepayers.”

BSE: “Ratepayers have always funded power plants -- whether coal, nuclear, natural gas, hydro, biomass, wind or solar.”

LAT: “Confidential agreements between solar developers and utilities lock in power prices two to four times the cost of conventional electricity,” the paper reported. According to Stanford University economist and California electricity market authority Frank Wolak, the state's renewable energy strategy “could boost electricity rates ten percent to 20 percent” or even “by 50 percent.”

BSE: A 2012 California Public Utilities Commission (CPUC) report highlighted how “the falling cost of renewable energy is leading to cost-competitive prices for utilities,” BSE responded. “In 2020, the total statewide electricity expenditures of achieving a 33 percent RPS is projected to be 10.2 percent higher compared to an all-gas scenario [and] if California makes no further investments in renewable energy, this analysis projects that average electricity costs per kilowatt-hour will rise by 16.7 percent in 2020.”

LAT: Critics of CSP solar power towers told the Times that “solar entrepreneurs are getting too much government money.” San Diego-based electrical engineer and power plant consultant Bill Powers called them “a huge waste of money” and ”an old fashioned ripoff.”

BSE: Governments always use incentives to encourage the development of domestic energy resources, BSE replied, including “direct subsidies, tax breaks, market support, technology demonstration programs, research and development (R&D) programs, procurement mandates, information generation and dissemination, technology transfer, directed purchases, and government‐funded regulations.”

The biggest beneficiaries of federal energy incentives over the last 60 years, BSE added, have been oil and gas, with almost 60 percent ($490 billion). Coal got 12 percent ($104 billion). Wind, solar and geothermal got about 10 percent ($81 billion).

LAT: “The incentives allow solar developers to reap annual returns on their investments of 8 percent to 12 percent, as much as tripling their money in a decade. In some cases the returns could go as high as 17 percent,” the Times reported, drawing in “banks and Wall Street.”

BSE: “Subsidies reduce the cost to build a power plant, which in turn lowers the cost of electricity that must be charged to pay for it,” BSE said. In California, “renewable energy is procured through a competitive process, and subsidies are reflected in the bid prices. They do not line the pockets of banks, insurers and utility companies.”

LAT: “To make such projects economically attractive for developers, the government created a mix of federal loan guarantees, grants and tax incentives,” the Times reported. “Taken together, the incentives can provide solar companies with more than half a project's costs in cash, with the remainder covered by the federally guaranteed loans.” And, it also said, “the low-interest, government-guaranteed loans -- more than $16 billion for renewable energy projects so far -- pay up to 80 percent of a project's construction costs.”

BSE: “Lower interest rates (as a result of available loan guarantees) translate to lower energy rates in the same way a low-interest mortgage reduces a homeowner’s monthly payment.”

LAT: “The $2.2-billion Ivanpah Solar Electric Generating System is being built by Oakland-based BrightSource Energy Inc.,” the Times reported. “The Ivanpah plant was made possible by government-backed loans at low rates -- 4 percent to 4.2 percent. BrightSource and its corporate investors will receive about $600 million in federal grants once the plant starts producing.”

BSE: “Government-backed loans are paid back with interest to taxpayers, making the loans an investment, not a subsidy. [And] insurance and performance guarantees are required for all power plants to protect ratepayers if something goes wrong. Without those protections, a power plant -- renewable or fossil -- could not be financed and constructed.” The bulk of the upfront money provided to BSE “will be used to repay a portion of the guaranteed loan with interest,” it said.

LAT: “The California Public Utilities Commission, which approves all rate agreements, won't disclose the rate for Ivanpah,” reported the Times. But outside experts, it said, “estimate that Ivanpah power is priced at $90 to $130 per megawatt hour -- three to four times the cost of electricity in the state last year. BrightSource declined to specify the price but said it was in line with the PUC's recommended renewable rate of $129 per megawatt-hour.”

BSE: “The returns earned on renewable project investments are comparable to the returns earned on other large infrastructure projects of similar size with similar risk profiles. No more, no less,” BSE responded. “California utilities don’t earn profits on fuel costs, such as natural gas. Instead, they are passed through to ratepayers without a markup. Natural gas is a commodity, its price is volatile and it is projected to increase over time. In contrast, once a solar plant is constructed, the fuel -- sun -- is free as long as the plant operates.”

Lucid Partners With Honest Buildings

Fri, 09/21/2012 - 14:19

Honest Buildings is a free platform that connects the wide world of real estate, but it’s not necessarily all about energy.

Honest Buildings is like LinkedIn for the real estate market, connecting building owners, architects, engineers, contractors and other building services. While energy efficiency is one facet of building performance, a new partnership with Lucid will help bring energy information to the forefront.

“This kind of transparency changes the building performance market the way LEED changed the construction market,” said Andrew deCoriolis, director of marketing at Lucid.

Lucid will first post real-time energy and water usage for buildings that are using Lucid’s technology. Down the road, other buildings will be able to get Lucid’s service simply by clicking a widget on HonestBuildings.com and filling in information. For buildings that are already working with Lucid, a link to performance data will appear on the overview page of the building’s profile, just below the contact link.

“Lucid’s innovative, real-time energy monitoring technology adds another layer of rich information to our building profiles and will help people who use Honest Buildings make faster and more informed real-estate decisions,” Riggs Kubiak, co-founder and CEO of HonestBuildings.com, said in a statement. “It’s another great example of a cutting-edge company using the platform to accelerate the adoption of high-performance buildings.”

Both Lucid and Honest Buildings share a passion for social media and transparency through data sharing. Lucid is an energy dashboard company that is best known for its work in institutions using competition and social media to drive energy efficiency and automated demand response participation. 

In 2011, Lucid teamed up with Constellation Energy to allow companies to use money earned through Constellation’s demand response program to pay for Lucid’s building dashboard.

Honest Buildings is part of a growing group of freemium offerings in the building space, giving away basic offerings for free and charging for added services as part of a subscription model -- much like the way LinkedIn operates. DeCoriolis said that Lucid’s offerings through Honest Buildings will probably be the same. Some performance metrics will likely be free, or the first building or two of a portfolio may be free, and then there will be subscription services for deeper offerings. The startup recently closed a Series A round of funding

The timing for Honest Building coincides with a growing legislative push for buildings to disclose energy benchmarking information. In New York, the data has to be publicly disclosed, while other cities like San Francisco only require disclosure at the point of sale or lease.

There is increasing access to utility data through efforts like the Green Button, and a growing number of companies are making a business out of working with utilities to unlock data. “The cost per year per building comes down substantially with things like Green Button connect,” said deCoriolis. “It makes a big difference.”

At first it will be the buildings that are already performing well that will want to toot their own horn on Honest Buildings. But eventually, increasing transparency through disclosure laws and websites like Honest Buildings holds a lot of promise to drive efficiency, whether it’s building owners looking to draw better tenants or vendors being able to fine-tune their project acquisition process.

“The scale is exciting. The question for [Honest Buildings] and for us is, how do you make all of that data valuable and how do you make it valuable for different audiences?” said deCoriolis. “They’re trying to bring a level of transparency to the building market that was never there before.”

Emerging Solar Strategies, Part 2: SOLON

Fri, 09/21/2012 - 13:00

A recent panel of solar CEOs predicted that 2011’s approximately 1,500 solar module manufacturers will have been Darwinized to as few as 100 by 2016.

SOLON Corporation has turned toward innovation for survival. “We are prepared to deal with whatever we need to deal with to play in the market,” explained SOLON Director of Research and Development Bill Richardson.

SOLON SE, the Berlin-based parent company, Richardson said, began as a residential rooftop solar system kit provider, evolved into module manufacturing and then became an engineering, procurement and construction (EPC) provider. It built the world’s first utility-scale solar installation, a twelve-megawatt project. Established as a subsidiary of the now bankrupt SOLON SE, the U.S. company was part of the bankruptcy settlement in which UAE-based cell maker Microsol, took over SOLON SE assets earlier this year.

“Nothing changes for us,” Richardson said. “We are building SOLquick units, doing really fast installs on flat roofs, and looking five years ahead at system storage.”

“We were one of the first to get out of module manufacturing,” added Director of Marketing Patricia Browne. Even before the bankruptcy, “we realized we needed to adapt to the market changes and figure out how to survive.”

Instead of making modules, she said, “which are essentially commodities, we wanted to add value to the installation market. SOLquick is an integrated laminate and racking system. The traditional approach is having a module and a rack, and then clamping them together. We assemble a frameless module and a wood composite rack, all in one, at our factory in Tucson, and ship out a rooftop system, pre-assembled.”

SOLON Corp. is composed, Richardson said, of a product group and a systems group. The former makes and markets SOLquick and the latter is an EPC.

“Our strength in the U.S. has always been as an EPC provider,” Browne said. “We’ve partnered with PG&E (NYSE:PCG), TEP, and Duke Energy (NYSE:DUK) and we have built nearly 100 megawatts in the U.S.”

Sales and revenue numbers are held private, Richardson said.  “But what we can say,” Browne offered as a metric, “is that we are hiring.” The firm currently employs 75 people, the majority at the Tucson facility, and is looking to fill fifteen to twenty positions in sales, construction and technical R&D positions. “And we just recently brought on five to ten [more].”

While proceeding with development in the midsize ten-to-50-megawatt-project space, SOLON is also moving ahead on two innovation efforts: SOLquick, aimed at the near term, and at the SMRT (storage management research and testing) Site, aimed at the longer term.

SOLquick, Richardson said, “is geared for large commercial rooftops, 100 kilowatts and up to as big as a rooftop gets. That’s where it shines. The bigger it gets, the better it is.” It is, he explained, “a frameless laminate, a traditional module without the aluminum frame, which you adhere to a non-metallic substructure made from Fibrex, a wood polymer with a PVC coating.”

“Andersen extrudes the racking pieces and we assemble them in our Tucson factory where we used to manufacture modules,” Browne added.

SOLON has 100 patents on the integrated rack and module product, Richardson said.

Because the firm is emphasizing the SOLquick brand, it does not make public which module brands they use. “We can use SOLON laminates, but we have the flexibility to use any laminate we internally qualify that meets our standards,” Richardson said. “The quality and robustness of this is never at issue. BEW just came out with a third-party report on this product, independently assessing it, and said that the due diligence we put into it is far above the general due diligence and testing that is standard in the industry.”

“SOLquick comes with the industry standard 25-year performance, ten-year product warranty for modules,” Browne said, “but we apply it to the entire system.”

Traditional racking manufacturers argue that the unidentified module to which an installer is committed by choosing SOLquick is a disadvantage.

“Our Renusol CS60 is compatible with almost all 60-cell and some 72-cell modules currently in the markets,” Renusol America CEO Bart Leusink told GTM. That “allows for a broader adoption, without limiting the user or installer.”

As part of the University of Arizona’s Solar Zone, built to test solar technologies, SOLON built a 1.6-megawatt, ground-mounted installation with SOLON-made panels on its own single axis-trackers two years ago. Now, in partnership with inverter maker SMA (ETR: S92), Tucson Electric Power (TEP), and the University, the firm is readying SMRT, a five-year field test of storage technologies.

“When we built it, we designed in the ability to have this storage test site that we are now putting into place,” Richardson said. “We are commissioning the first storage technology next month, a lithium-ion battery from SAFT (EPA:SAFT).”

The undertaking will cover a range of technologies, Richardson said. The next test will be an above-ground compressed air energy storage prototype developed by the university. “After that, he said, “the university has a flow battery they are going to bring in.”

SOLON’s intent, Richardson said, is “to get good at integrating different types of storage, because we are going to need different types of solutions for different customers.”

There aren't many in the renewables industries who would take issue with SOLON's long-term interest in storage. The question is whether their integrated rack and module system will get them to the long term.

What Low-Income Utility Customers Want From the Smart Grid

Fri, 09/21/2012 - 12:55

Are low-income customers a problem or an opportunity for utilities’ smart grid plans?

The Smart Grid Consumer Collaborative decided to stop guessing at the answer to that question, and go ask U.S. low-income customers themselves. This week, the nonprofit group published the results of that survey -- and some of the answers may surprise the smart grid industry.

For example, low-income households -- those earning less than $30,000 for a family of three to four, or $40,000 for a family of five to eight people -- aren’t nearly as opposed to time-of-use and peak pricing plans as many may have guessed, Patty Durand, executive director of the SGCC, said in a Thursday interview.

Indeed, about 35 percent said they “probably” would sign up for a time-of-use pricing plan, and 12 percent said they “definitely” would, adding up to nearly half of all respondents. That’s actually a little bit higher than the 44 percent support found in surveys of the general population for programs that price power higher during “peak” times, usually late afternoons, in exchange for lower prices during low-demand nighttime hours, Durand said.

While that still leaves a little more than half of all low-income customers who probably or definitely do not want time-of-use pricing, it’s still a lot higher than most people in the industry might think, she said. TOU pricing is fairly rare today, though some parts of North America, such as Canada’s Ontario province, have rolled it out to all their customers, and other U.S. utilities are following suit.

Low-income customer interest in critical-peak rebates -- programs that pay people to reduce power use during a few critical peak demand times during the year -- is even higher, with 23 percent definitely interested and 34 percent probably interested, Durand said. That’s a little lower than the general population’s interest in CPP, which are implemented in states like California with big afternoon air-conditioning-driven peak problems to tackle.

Of course, that makes sense: people are more interested in getting paid to shave power use than being priced to encourage it. Still, rebate programs are good ways to get customers involved, and have been shown to generate more efficiency overall once they're in place.

What don't low-income customers like? Prepay, or pay-as-you-go, programs that charge them in advance for power. Only 7 percent were definitely interested and 20 percent probably interested in such a program, Durand said. That could be a problem for utilities and smart grid vendors that want to institute prepay regimes, though some utilities, such as Arizona’s Salt River Project, have large and successful programs, she noted. The main problem low-income customers have with prepay? The threat that they’ll have their power cut off.

Finally, low-income customers may be interested in managing their power use to save money, but they need to be reached via the technology they have, not the technology the industry might wish they had. For example, 42 percent of respondents lacked access to the internet, and only 58 percent have a mobile phone of any kind, the survey found.

But everyone has a telephone. About 43 percent of low-income customers were OK with getting automated calls from the utility asking them to change power use to take advantage of peak-time rebates or time-of-use pricing, while only 17 percent wanted to get email alerts, and only 10 percent wanted to go online to learn their pricing plans.

That’s a stark difference from the general population, where only 23 percent of respondents wanted to get robo-calls from the utility, versus 26 percent who preferred to get emails, Durand noted. It’s yet another reminder that utilities, for all the technological potential of their new smart grid systems, need to take their customers’ preferences into account when connecting to them.

 

Emerging Solar Strategies, Part 2: SOLON

Fri, 09/21/2012 - 12:00

A recent panel of solar CEOs predicted that 2011’s approximately 1,500 solar module manufacturers will have been Darwinized to as few as 100 by 2016.

SOLON Corporation has turned toward innovation for survival. “We are prepared to deal with whatever we need to deal with to play in the market,” explained SOLON Director of Research and Development Bill Richardson.

SOLON SE, the Berlin-based parent company, Richardson said, began as a residential rooftop solar system kit provider, evolved into module manufacturing and then became an engineering, procurement and construction (EPC) provider. It built the world’s first utility-scale solar installation, a twelve-megawatt project. Established as a subsidiary of the now bankrupt SOLON SE, the U.S. company was part of the bankruptcy settlement in which UAE-based cell maker Microsol, took over SOLON SE assets earlier this year.

“Nothing changes for us,” Richardson said. “We are building SOLquick units, doing really fast installs on flat roofs, and looking five years ahead at system storage.”

“We were one of the first to get out of module manufacturing,” added Director of Marketing Patricia Browne. Even before the bankruptcy, “we realized we needed to adapt to the market changes and figure out how to survive.”

Instead of making modules, she said, “which are essentially commodities, we wanted to add value to the installation market. SOLquick is an integrated laminate and racking system. The traditional approach is having a module and a rack, and then clamping them together. We assemble a frameless module and a wood composite rack, all in one, at our factory in Tucson, and ship out a rooftop system, pre-assembled.”

SOLON Corp. is composed, Richardson said, of a product group and a systems group. The former makes and markets SOLquick and the latter is an EPC.

“Our strength in the U.S. has always been as an EPC provider,” Browne said. “We’ve partnered with PG&E (NYSE:PCG), TEP, and Duke Energy (NYSE:DUK) and we have built nearly 100 megawatts in the U.S.”

Sales and revenue numbers are held private, Richardson said.  “But what we can say,” Browne offered as a metric, “is that we are hiring.” The firm currently employs 75 people, the majority at the Tucson facility, and is looking to fill fifteen to twenty positions in sales, construction and technical R&D positions. “And we just recently brought on five to ten [more].”

While proceeding with development in the midsize ten-to-50-megawatt-project space, SOLON is also moving ahead on two innovation efforts: SOLquick, aimed at the near term, and at the SMRT (storage management research and testing) Site, aimed at the longer term.

SOLquick, Richardson said, “is geared for large commercial rooftops, 100 kilowatts and up to as big as a rooftop gets. That’s where it shines. The bigger it gets, the better it is.” It is, he explained, “a frameless laminate, a traditional module without the aluminum frame, which you adhere to a non-metallic substructure made from Fibrex, a wood polymer with a PVC coating.”

“Andersen extrudes the racking pieces and we assemble them in our Tucson factory where we used to manufacture modules,” Browne added.

SOLON has 100 patents on the integrated rack and module product, Richardson said.

Because the firm is emphasizing the SOLquick brand, it does not make public which module brands they use. “We can use SOLON laminates, but we have the flexibility to use any laminate we internally qualify that meets our standards,” Richardson said. “The quality and robustness of this is never at issue. BEW just came out with a third-party report on this product, independently assessing it, and said that the due diligence we put into it is far above the general due diligence and testing that is standard in the industry.”

“SOLquick comes with the industry standard 25-year performance, ten-year product warranty for modules,” Browne said, “but we apply it to the entire system.”

Traditional racking manufacturers argue that the unidentified module to which an installer is committed by choosing SOLquick is a disadvantage.

“Our Renusol CS60 is compatible with almost all 60-cell and some 72-cell modules currently in the markets,” Renusol America CEO Bart Leusink told GTM. That “allows for a broader adoption, without limiting the user or installer.”

As part of the University of Arizona’s Solar Zone, built to test solar technologies, SOLON built a 1.6-megawatt, ground-mounted installation with SOLON-made panels on its own single axis-trackers two years ago. Now, in partnership with inverter maker SMA (ETR: S92), Tucson Electric Power (TEP), and the University, the firm is readying SMRT, a five-year field test of storage technologies.

“When we built it, we designed in the ability to have this storage test site that we are now putting into place,” Richardson said. “We are commissioning the first storage technology next month, a lithium-ion battery from SAFT (EPA:SAFT).”

The undertaking will cover a range of technologies, Richardson said. The next test will be an above-ground compressed air energy storage prototype developed by the university. “After that, he said, “the university has a flow battery they are going to bring in.”

SOLON’s intent, Richardson said, is “to get good at integrating different types of storage, because we are going to need different types of solutions for different customers.”

There aren't many in the renewables industries who would take issue with SOLON's long-term interest in storage. The question is whether their integrated rack and module system will get them to the long term.

Video of the Day: Where Wind Is

Fri, 09/21/2012 - 12:00

Through the presidential campaigns, the mainstream media has picked up the once-slightly-wonky fight over the extension of wind energy’s production tax credit (PTC).

As reported by GTM, Governor Romney has come out unequivocally against extension of the 2.2-cents-per-kilowatt-hour credit, and President Obama is all for it.

“We’re not affected by the PTC; we operate mostly under the ITC,” explained distributed wind vendor Talco Electronics President Tal Mamo, “but because of the politics being played on big wind, we get dragged into it.”

"Distributed wind" is the term for backyard, barnyard, schoolyard and parking lot turbines of less than one megawatt.

“There is a lot of politics being played around energy,” Mamo said. “A lot of it is around big money trying to protect what they have. Unfortunately, with that comes a lot of noise, a lot of misinformation.”

When buyers or installers of distributed wind approach local authorities for permits or zoning considerations, the misinformation creates a backlash, Mamo said. “You’ll have communities that say they don’t want turbines in their backyards. They’re thinking big wind farms. But we’ve got a farmer with 42 acres who wants to put a small turbine in the middle of his farm. And the local counties won’t allow it because neighbors are afraid because of what they’ve heard through the media.”

In an attempt to correct the misinformation, Mamo made a video. He wanted to show the true opportunity wind energy offers.

“A farmer can see how he can reduce his overall cost and save money for future generations,” Mamo said. “And parents and administrators can see how a school can save money by lowering their operational expenses and hopefully keep more teachers on board or hold to some of their afterschool programs. And homeowners and business owners can see how they can reduce their energy costs and save money for other things they need in this tight economy.”

The video is about distributed wind, Mamo said. “It is not big wind farms, where you don’t necessarily feel the effect on yourself. With distributed wind, you get to take advantage of all the positive effects of wind, personally.”

The video, Mamo said, “helps make energy, and specifically wind energy, more personal. You’re not getting energy from some mysterious power plant or utility. You’re producing the energy you are using and saving yourself money.”

What Low-Income Utility Customers Want from the Smart Grid

Fri, 09/21/2012 - 11:55

Are low-income customers a problem or an opportunity for utilities’ smart grid plans?

The Smart Grid Consumer Collaborative decided to stop guessing at the answer to that question, and go ask U.S. low-income customers themselves. This week, the nonprofit group published the results of that survey — and some of the answers may surprise the smart grid industry.

For example, low-income households — those earning than $30,000 for a family of 3 to 4, or $40,000 for a family of 5 to 8 people — aren’t nearly as opposed to time-of-use and peak pricing plans as many may have guessed, Patty Durand, executive director of the SGCC, said in a Thursday interview.

Indeed, about 35 percent said they “probably” would sign up for a time-of-use pricing plan, and 12 percent said they “definitely” would, adding up to nearly half of all respondents. That’s actually a little bit higher than the 44 percent support found in surveys of the general population for programs that price power higher during “peak” times, usually late afternoons, in exchange for lower prices during low-demand nighttime hours, Durand said.

While that still leaves a little more than half of all low-income customers who probably or definitely do not want time-of-use pricing, it’s still a lot higher than most people in the industry might think, she said. TOU pricing is fairly rare today, though some parts of North America, such as Canada’s Ontario province, have rolled it out to all their customers, and other U.S. utilities are following suit.

Low-income customer interest in critical-peak rebates — programs that pay people to reduce power use during a few critical peak demand times during the year — is even higher, with 23 percent definitely interested and 34 percent probably interested, Durand said. That’s a little lower than the general population’s interest in CPP, which are implemented in states like California with big afternoon air conditioning-driven peak problems to tackle.

Of course, that makes sense -- people are more interested in getting paid to shave power use than being priced to encourage it. Still, rebate programs are good ways to get customers involved, and have been shown to generate more efficiency overall once they're in place.

What don't low-income customers like? Prepay, or pay-as-you-go, programs that charge them in advance for power. Only 7 percent were definitely interested and 20 percent probably interested in such a program, Durand said. That could be a problem for utilities and smart grid vendors that want to institute prepay regimes, though some utilities, such as Arizona’s Salt River Project, have large and successful programs, she noted. The main problem low-income customers have with prepay? The threat that they’ll have their power cut off.

Finally, low-income customers may be interested in managing their power use to save money, but they need to be reached via the technology they have, not the technology the industry might wish they had. For example, 42 percent of respondents lacked access to the Internet, and only 58 percent have a mobile phone of any kind, the survey found.

But everyone has a telephone. About 43 percent of low-income customers were OK with getting automated calls from the utility asking them to change power use to take advantage of peak-time rebates or time-of-use pricing, while only 17 percent wanted to get email alerts, and only 10 percent wanted to go online to learn their pricing plans.

That’s a stark difference from the general population, where only 23 percent of respondents wanted to get robo-calls from the utility, versus 26 percent who preferred to get emails, Durand noted. It’s yet another reminder that utilities, for all the technological potential of their new smart grid systems, need to take their customers’ preferences into account when connecting to them.

Video of the Day: Where Wind Is

Fri, 09/21/2012 - 11:00

Through the presidential campaigns, the mainstream media has picked up the once-slightly-wonky fight over the extension of wind energy’s production tax credit (PTC).

As reported by GTM, Governor Romney has come out unequivocally against extension of the 2.2-cents-per-kilowatt-hour credit, and President Obama is all for it.

“We’re not affected by the PTC; we operate mostly under the ITC,” explained distributed wind vendor Talco Electronics President Tal Mamo, “but because of the politics being played on big wind, we get dragged into it.”

"Distributed wind" is the term for backyard, barnyard, schoolyard and parking lot turbines of less than one megawatt.

“There is a lot of politics being played around energy,” Mamo said. “A lot of it is around big money trying to protect what they have. Unfortunately, with that comes a lot of noise, a lot of misinformation.”

When buyers or installers of distributed wind approach local authorities for permits or zoning considerations, the misinformation creates a backlash, Mamo said. “You’ll have communities that say they don’t want turbines in their backyards. They’re thinking big wind farms. But we’ve got a farmer with 42 acres who wants to put a small turbine in the middle of his farm. And the local counties won’t allow it because neighbors are afraid because of what they’ve heard through the media.”

In an attempt to correct the misinformation, Mamo made a video. He wanted to show the true opportunity wind energy offers.

“A farmer can see how he can reduce his overall cost and save money for future generations,” Mamo said. “And parents and administrators can see how a school can save money by lowering their operational expenses and hopefully keep more teachers on board or hold to some of their afterschool programs. And homeowners and business owners can see how they can reduce their energy costs and save money for other things they need in this tight economy.”

The video is about distributed wind, Mamo said. “It is not big wind farms, where you don’t necessarily feel the effect on yourself. With distributed wind, you get to take advantage of all the positive effects of wind, personally.”

The video, Mamo said, “helps make energy, and specifically wind energy, more personal. You’re not getting energy from some mysterious power plant or utility. You’re producing the energy you are using and saving yourself money.”

The Reign of Residential PV in Japan

Fri, 09/21/2012 - 10:00

The following is a modified excerpt from GTM Research's recently published report, The Japan PV Market, 2012-2016. For more information on the report, click here.

The Japanese solar PV market is in a state of flux; since the market's inception, the ‘Big Four’ module suppliers -- Kyocera, Sharp, Sanyo (now owned by Panasonic), and Mitsubishi -- shaped PV in Japan while serving their primary suppliers. Now, foreign entrants such as Suntech, Canadian Solar, Yingli, Trina, and JA Solar, as well as Japanese newcomers such as Solar Frontier, threaten to dethrone the incumbents. While the country's new feed-in tariff (FIT), intended to develop the large-scale solar market, has positioned Japan as a center of global PV demand, the market's main driver is and will continue to be the residential sector.

The figure below demonstrates just how powerful the residential market sector is in Japan (note that this figure defines the residential market as systems below 10 kilowatts-DC). Over 96 percent of the cumulative PV capacity in Japan is distributed, with the remainder being centralized PV plants. This merits the question, what supply chains have helped Japan become the largest residential market?

FIGURE: Residential Market Share for Major Markets in 2011

Source: The Japan PV Market, 2012-2016: A New Era of Solar or the Beginning of a Boom-Bust Cycle?

One of the primary inhibitors for the Japanese market has been its high system prices relative to other markets. Residential systems in FY2011 averaged ¥543 per watt (US$6.93 per watt) for retrofits and ¥472 per watt ($6.02 per watt) for new homes. Some of the major factors contributing to these high prices include:

  • Significant subsidy programs in combination with a lack of downstream competition allowing installers to charge high prices – in other words, padded downstream margins
     
  • Use of higher-cost, domestically produced panels and BOS materials
     
  • Preferential use of expensive products such as high-efficiency panels, panels with black or alternative backsheets, or triangular panels
     
  • High cost of acquisition of customers
    - Expensive marketing schemes including television commercials
    - Door-to-door sales
    - Complicated distribution networks
    - Relatively small system sizes (average of 4.34 kilowatts per home in FY2011)
     
  • Sales of products almost exclusively in kits
    - Generally include monitoring and other high-cost items such as LCD screens for the monitoring systems
     
  • The Japanese yen is valued at a near all-time high compared to the euro or USD at August 2012 foreign exchange rates. This was true throughout 2011, as well.
     
  • High labor costs relative to other countries


It is worth noting that black backsheets and triangular panels are often used as differentiators.

The sales and distribution channels in Japan are unique and relatively complicated and inefficient compared to European or American markets. Until very recently, there have been very few solar specialists in Japan, and one of the main sales channels has been through home builders. Compare this to the United States or Germany, where the vast majority of residential systems are installed by companies that specialize in solar installations.

Many home builders integrate solar systems into the home during construction. In these cases, PV system costs are wrapped into the home mortgage. ‘Eco’ homes are now very popular, especially since the Fukushima disaster and resulting electricity shortages. Sales of home energy management systems (HEMS) and battery storage systems alongside solar systems are becoming popular as well. The percentage of new homes with solar in Japan is rising. The figure below demonstrates the growth of the new home starts solar market in Japan.

FIGURE: New Home Solar Integration Trends


Source: The Japan PV Market, 2012-2016: A New Era of Solar or the Beginning of a Boom-Bust Cycle?

This sales channel is very seasonal, and is dependent on the housing market as a whole. However, the figure above shows that the number of solar installations on new homes has been increasing by more than 55 percent per year since 2009. Housing data from the Ministry of Land, Infrastructure, Transport, and Tourism (MLIT) shows that the percentage of all new housing starts (including apartments, etc.) with solar was roughly 8 percent in 2011. We estimate that this number will increase to over 10 percent in 2012 and to nearly 15 percent in 2013.

It is important to note that the housing start data reported by the MLIT includes apartments in high-rise residential developments and other locations where solar is not feasible. The percent of detached houses with solar is therefore higher than we report. All of the top home builders now offer eco-homes equipped with solar and often HEMS and batteries, as well. GTM Research recently published a report titled The Smart Grid in Asia, 2012-2016: Markets, Technologies and Strategies which discusses EMS in Japan and forecasts that the HEMS market will reach $2.3 billion by 2015. Some of the largest homebuilders involved in solar include:

  • Sekisui Home
    - 77.9 percent of its detached homes in FY2011 were built with PV or fuel cells
     
  • Sekisui Chemical
     
  • Daiwa House Co.
    - Recently launched Endless Green Program
     
  • PanaHome (subsidiary of Panasonic)
     
  • Misawa Home
    - 30.7 percent of homes in FY2011 were built with PV
     
  • Mitsui Home
     
  • Mitsubishi Estate


Home builders such as Mitsubishi Estate or PanaHome naturally offer their own panels (Mitsubishi Electric and Panasonic, respectively); however, the others offer a range of products. We discuss the opportunities for entrance into this market in the full report. Home builders and remodelers also offer solar systems during remodeling and re-roofing and for pure retrofitting of existing homes.

FIGURE: Existing Home Solar Integration Trends


Source: The Japan PV Market, 2012-2016: A New Era of Solar or the Beginning of a Boom-Bust Cycle?

As the figure above demonstrates, retrofitting existing homes is less seasonal and is very dependent on the availability of local incentives. This market segment has grown at roughly 90 percent per year since 2009. A home remodeler and trading company, West Holdings, is the country’s largest residential solar installer. These trading companies have shown a greater willingness to use foreign equipment than some of the other residential channels (discussed in detail in the report). In fact, West Holdings sells panels produced by domestic and foreign manufacturers (including JA Solar, Yingli and Suntech) as well as its own brand, E-Solar (using Eversol cells).

To learn more about GTM Research's The Japan PV Market, 2012-2016 report and to purchase a copy today, visit www.greentechmedia.com/research/report/japan-pv-market-2012.

SRECTrade and GTM Research Launch Report Series on US SREC Market Dynamics

Fri, 09/21/2012 - 08:30

SRECTrade and GTM Research today release SREC Market Monitor, the solar industry’s first quarterly report series devoted to covering state SREC markets in the U.S. With SREC programs forecasted to account for nearly 25 percent of the 3.2 gigawatts to be installed nationally in 2012, understanding the risk and opportunity latent in SREC states will be imperative for industry players.

At 72 pages, SREC Market Monitor: 2nd Quarter 2012 provides qualitative state-by-state SREC market analyses, regulatory policy updates affecting these markets, quarterly bid/offer pricing by state, data on SREC supply by state, historical SREC pricing, as well as updated RPS figures for each SREC market. The reports analyze the following markets: Delaware, Maryland, Massachusetts, New Jersey, Ohio, Pennsylvania, and Washington, D.C.

FIGURE: SREC Info Map, Q2 2012


Source: SREC Market Monitor: 2nd Quarter 2012

“Over the past five years, SRECTrade has specialized in providing liquidity, transparency and an unparalleled amount of insight into the complex movements of SREC markets across the U.S.,” said Brad Bowery, CEO of SRECTrade. “Our partnership with GTM Research now allows us to go beyond structuring transactions and reach a larger audience who can employ the market monitor to better assess the risk and opportunity of these complex SREC mechanisms.”

“State markets driven by SREC incentives now make up nearly 25 percent of total U.S. installations annually,” said Shayle Kann, VP of Research at GTM Research. “Our quarterly report series with SRECTrade strengthens our U.S. PV foundation and provides our clients with the most timely analysis on the SREC potential, as well as the possible pitfalls, for their businesses.”

For more information on SREC Market Monitor and to purchase a copy, visit www.greentechmedia.com/research/srec-market-monitor.

SAMPLE SREC ANALYSIS BY STATE

  • NEW JERSEY: Trading volume increased in New Jersey as prices stabilized in anticipation of new legislation signed in July. Forward contracts have seen the largest increase in activity as the spot and forward price curves converge.
  • MASSACHUSETTS: After two years of significant undersupply and high SREC prices, rates of installation increased dramatically in Massachusetts, leading to a 50% drop in the 2012 SREC spot price. As market participants adjust to the reality of oversupply, it is clear that the market will trade well below the price support in the early part of the year.
  • MARYLAND: Maryland continues to find support in the legislature for its SREC program. In May, the solar carve-out requirements were moved forward by two years. While this change has kept Maryland from facing a pending oversupply, the market continues to grow at a rate designed to meet requirements under the new legislation.
  • DELAWARE: In April, Delaware launched the pilot of its SREC Procurement Program managed by the Sustainable Energy Utility (SEU) and administered by SRECTrade on behalf of Delmarva Power. The program represents a significant shift in the state’s SREC market that could become a model for other states struggling with SREC volatility. It is the first independent, statewide solicitation for long-term SREC contracts.
  • WASHINGTON, D.C.: The Washington, D.C. market continues to be a bright spot for the solar industry. Given the small, urban footprint of the district, the solar carve-out is an ambitious piece of legislation. Constrained by space, smaller solar installations will dominate this market, naturally preventing the wild swings in supply that have led to volatility in other markets.
  • PENNSYLVANIA: SRECs continue to trade in the $20 to $30 range with an occasional spike. Despite attempts by sponsoring lawmakers, Pennsylvania continues to struggle to garner support for a legislative fix that would accelerate the solar RPS and create demand for SRECs.
  • OHIO: The market was particularly slow in Q2 as 2012 trading activity concluded. In-state demand had been strong over the past few years, but there has been a slowdown as supply has steadily grown to meet that demand. Meanwhile, the OH-adjacent market, which includes SRECs from states that border Ohio, continues to be significantly oversupplied.
     


Interested in purchasing this quarter's SREC Market Monitor? Click here to learn more.

SRECTrade and GTM Research Launch Report Series on US SREC Market Dynamics

Fri, 09/21/2012 - 07:30

SRECTrade and GTM Research today release SREC Market Monitor, the solar industry’s first quarterly report series devoted to covering state SREC markets in the U.S. With SREC programs forecasted to account for nearly 25 percent of the 3.2 gigawatts to be installed nationally in 2012, understanding the risk and opportunity latent in SREC states will be imperative for industry players.

At 72 pages, SREC Market Monitor: 2nd Quarter 2012 provides qualitative state-by-state SREC market analyses, regulatory policy updates affecting these markets, quarterly bid/offer pricing by state, data on SREC supply by state, historical SREC pricing, as well as updated RPS figures for each SREC market. The reports analyze the following markets: Delaware, Maryland, Massachusetts, New Jersey, Ohio, Pennsylvania, and Washington, D.C.

FIGURE: SREC Info Map, Q2 2012


Source: SREC Market Monitor: 2nd Quarter 2012

“Over the past five years, SRECTrade has specialized in providing liquidity, transparency and an unparalleled amount of insight into the complex movements of SREC markets across the U.S.,” said Brad Bowery, CEO of SRECTrade. “Our partnership with GTM Research now allows us to go beyond structuring transactions and reach a larger audience who can employ the market monitor to better assess the risk and opportunity of these complex SREC mechanisms.”

“State markets driven by SREC incentives now make up nearly 25 percent of total U.S. installations annually,” said Shayle Kann, VP of Research at GTM Research. “Our quarterly report series with SRECTrade strengthens our U.S. PV foundation and provides our clients with the most timely analysis on the SREC potential, as well as the possible pitfalls, for their businesses.”

For more information on SREC Market Monitor and to purchase a copy, visit www.greentechmedia.com/research/srec-market-monitor.

SAMPLE SREC ANALYSIS BY STATE

  • NEW JERSEY: Trading volume increased in New Jersey as prices stabilized in anticipation of new legislation signed in July. Forward contracts have seen the largest increase in activity as the spot and forward price curves converge.
  • MASSACHUSETTS: After two years of significant undersupply and high SREC prices, rates of installation increased dramatically in Massachusetts, leading to a 50% drop in the 2012 SREC spot price. As market participants adjust to the reality of oversupply, it is clear that the market will trade well below the price support in the early part of the year.
  • MARYLAND: Maryland continues to find support in the legislature for its SREC program. In May, the solar carve-out requirements were moved forward by two years. While this change has kept Maryland from facing a pending oversupply, the market continues to grow at a rate designed to meet requirements under the new legislation.
  • DELAWARE: In April, Delaware launched the pilot of its SREC Procurement Program managed by the Sustainable Energy Utility (SEU) and administered by SRECTrade on behalf of Delmarva Power. The program represents a significant shift in the state’s SREC market that could become a model for other states struggling with SREC volatility. It is the first independent, statewide solicitation for long-term SREC contracts.
  • WASHINGTON, D.C.: The Washington, D.C. market continues to be a bright spot for the solar industry. Given the small, urban footprint of the district, the solar carve-out is an ambitious piece of legislation. Constrained by space, smaller solar installations will dominate this market, naturally preventing the wild swings in supply that have led to volatility in other markets.
  • PENNSYLVANIA: SRECs continue to trade in the $20 to $30 range with an occasional spike. Despite attempts by sponsoring lawmakers, Pennsylvania continues to struggle to garner support for a legislative fix that would accelerate the solar RPS and create demand for SRECs.
  • OHIO: The market was particularly slow in Q2 as 2012 trading activity concluded. In-state demand had been strong over the past few years, but there has been a slowdown as supply has steadily grown to meet that demand. Meanwhile, the OH-adjacent market, which includes SRECs from states that border Ohio, continues to be significantly oversupplied.
     


Interested in purchasing this quarter's SREC Market Monitor? Click here to learn more.

Emerging Solar Strategies, Part 1: Centrosolar America

Thu, 09/20/2012 - 15:00

Centrosolar America (PINK: CEOLF), the U.S. subsidiary of Centrosolar Group AG (ETR: C3O), is taking its parent company’s “complete solar solutions” marketing approach to new levels in its efforts to expand its U.S. presence in an intensely competitive marketplace.

If the move into the rapidly expanding U.S. market is successful, it could offset the Munich-based conglomerate’s struggle against market factors like the flood of inexpensive Chinese modules and the EU financial crisis which drove the company’s 2010 revenues of 403 million euros down to 293 million euros in 2011.

The Group’s sales volume by megawatt was up 6 percent in 1H 2012 over 1H 2011 but that gain was offset by a 38 percent drop in module price. The most recent financials suggest the company may get back to 250 million euros for the year.

“Our primary business is selling complete solar solutions, not just PV panels,” Centrosolar America Managing Director Deep Chakraborty said. “We look at ourselves as a complete systems distributor and we also manufacture some components.”

Centrosolar acquisition Renusol GmbH supplies racking systems and has recently established a U.S. subsidiary, Renusol America. Centrosolar Glass makes glass for solar panels in Germany and China.

“Seventy-five percent of our business globally is from solar system sales,” Chakraborty said, “and one-fourth is from component sales.”

To take advantage of the U.S. opportunity, Centrosolar America has, since being spun off the German parent in 2008, established a distribution system with warehousing and sales forces in the key markets of Arizona, California and New Jersey and built a network of some 400 installers. It is also preparing to enter new markets in Hawaii, Massachusetts and New York.

Soligent is probably Centrosolar's primary competitor. Formed in 2011 from the merger of solar industry veterans DC Power and Solar Depot by ITOCHU, their parent company, one estimate puts Soligent's market share at close to 30 percent. Centrosolar America, much newer to the U.S. market, has about 9 percent.

Centrosolar America and Soligent, an industry analyst explained to GTM, “package and sell modules, inverters, and balance-of-systems components, typically to installers, residential or small commercial, who aren't large enough to interface with the component suppliers directly.”

The CentroPack, Chakraborty said, “is, to our knowledge, the only complete solar kit in the market. Manufacturers have kits. They have a module, inverter and racking, the three main components. But the many other things necessary for an installation are all unique requirements that differ market-to-market.”

Centrosolar’s logistical setup and accounting and operational systems can ship and track “a typical homeowner five-kilowatt system, worth $20,000, and deliver a complete kit to the homeowner’s garage, ready for the installer.” Installers also have the option of ordering individual components, Chakraborty added.

Simplifying the installer’s buying cycle and eliminating the need for procurement and warehousing,” Chakraborty said, “is worth 20 to 30 cents per watt of soft costs improvement for the average mid-size installer.”

Taking its installer services the next step, Centrosolar America now offers third-party financing. “We have set up an online system where our solar installer customers can go out, prepare a bid for a homeowner online in five minutes,” Chakraborty explained, “and that bid is for a complete solar system -- the CentroPack -- and it’s offered for either a cash sale or, through the CentroLease, as a lease- or loan-sale.”

Like the other offerings, this is intended to eliminate installer soft costs. “The entire sales cycle for residential solar is 26 steps,” Chakraborty explained. “Our customers, the residential installers who buy through us, they have to go through those same steps. What we do is organize it into a single online system, CentroLease.com, where everything can be entered and tracked.”

All the installer has to do, Chakraborty said, “is show up at the homeowner’s kitchen table and make them a proposal.”

CentroLease was launched with ten installers in July 2011. After six successful months, Centrosolar took it statewide in California, Arizona and Hawaii at the start of 2012.

“In the first half of this year,” Chakraborty said, we achieved close to 100 percent month-on-month growth in the number of deals being sold. We are quoting at a level of over 1,000 homes per month now.”

Though Centrosolar’s closing rate is proprietary information, Chakraborty noted it is not divergent from the well-known industry standard of 10 percent to 18 percent.

The challenge now for Centrosolar is likely to be logistics. “We have to make sure we can deliver these systems on time with high quality,” Chakraborty said. “After all, this is a home goods product like HVAC or an automotive product in the garage.”

Complete solutions and one-stop-shopping are currently being offered by providers from SolarCity to Canadian Solar because, as MEMC CEO Ahmad Chatila recently told GTM, “When you own the customer, you own the price and you own the volume.” The questions now being answered in the marketplace are: Which players are positioned to take that ownership? And can the others survive?

Emerging Solar Strategies, Part 1: Centrosolar America

Thu, 09/20/2012 - 14:00

Centrosolar America (PINK: CEOLF), the U.S. subsidiary of Centrosolar Group AG (ETR: C3O), is taking its parent company’s “complete solar solutions” marketing approach to new levels in its efforts to expand its U.S. presence in an intensely competitive marketplace.

If the move into the rapidly expanding U.S. market is successful, it could offset the Munich-based conglomerate’s struggle against market factors like the flood of inexpensive Chinese modules and the EU financial crisis which drove the company’s 2010 revenues of 403 million euros down to 293 million euros in 2011.

The Group’s sales volume by megawatt was up 6 percent in 1H 2012 over 1H 2011 but that gain was offset by a 38 percent drop in module price. The most recent financials suggest the company may get back to 250 million euros for the year.

“Our primary business is selling complete solar solutions, not just PV panels,” Centrosolar America Managing Director Deep Chakraborty said. “We look at ourselves as a complete systems distributor and we also manufacture some components.”

Centrosolar acquisition Renusol GmbH supplies racking systems and has recently established a U.S. subsidiary, Renusol America. Centrosolar Glass makes glass for solar panels in Germany and China.

“Seventy-five percent of our business globally is from solar system sales,” Chakraborty said, “and one-fourth is from component sales.”

To take advantage of the U.S. opportunity, Centrosolar America has, since being spun off the German parent in 2008, established a distribution system with warehousing and sales forces in the key markets of Arizona, California and New Jersey and built a network of some 400 installers. It is also preparing to enter new markets in Hawaii, Massachusetts and New York.

Soligent is probably Centrosolar's primary competitor. Formed in 2011 from the merger of solar industry veterans DC Power and Solar Depot by ITOCHU, their parent company, one estimate puts Soligent's market share at close to 30 percent. Centrosolar America, much newer to the U.S. market, has about 9 percent.

Centrosolar America and Soligent, an industry analyst explained to GTM, “package and sell modules, inverters, and balance-of-systems components, typically to installers, residential or small commercial, who aren't large enough to interface with the component suppliers directly.”

The CentroPack, Chakraborty said, “is, to our knowledge, the only complete solar kit in the market. Manufacturers have kits. They have a module, inverter and racking, the three main components. But the many other things necessary for an installation are all unique requirements that differ market-to-market.”

Centrosolar’s logistical setup and accounting and operational systems can ship and track “a typical homeowner five-kilowatt system, worth $20,000, and deliver a complete kit to the homeowner’s garage, ready for the installer.” Installers also have the option of ordering individual components, Chakraborty added.

Simplifying the installer’s buying cycle and eliminating the need for procurement and warehousing,” Chakraborty said, “is worth 20 to 30 cents per watt of soft costs improvement for the average mid-size installer.”

Taking its installer services the next step, Centrosolar America now offers third-party financing. “We have set up an online system where our solar installer customers can go out, prepare a bid for a homeowner online in five minutes,” Chakraborty explained, “and that bid is for a complete solar system -- the CentroPack -- and it’s offered for either a cash sale or, through the CentroLease, as a lease- or loan-sale.”

Like the other offerings, this is intended to eliminate installer soft costs. “The entire sales cycle for residential solar is 26 steps,” Chakraborty explained. “Our customers, the residential installers who buy through us, they have to go through those same steps. What we do is organize it into a single online system, CentroLease.com, where everything can be entered and tracked.”

All the installer has to do, Chakraborty said, “is show up at the homeowner’s kitchen table and make them a proposal.”

CentroLease was launched with ten installers in July 2011. After six successful months, Centrosolar took it statewide in California, Arizona and Hawaii at the start of 2012.

“In the first half of this year,” Chakraborty said, we achieved close to 100 percent month-on-month growth in the number of deals being sold. We are quoting at a level of over 1,000 homes per month now.”

Though Centrosolar’s closing rate is proprietary information, Chakraborty noted it is not divergent from the well-known industry standard of 10 percent to 18 percent.

The challenge now for Centrosolar is likely to be logistics. “We have to make sure we can deliver these systems on time with high quality,” Chakraborty said. “After all, this is a home goods product like HVAC or an automotive product in the garage.”

Complete solutions and one-stop-shopping are currently being offered by providers from SolarCity to Canadian Solar because, as MEMC CEO Ahmad Chatila recently told GTM, “When you own the customer, you own the price and you own the volume.” The questions now being answered in the marketplace are: Which players are positioned to take that ownership? And can the others survive?