Despite headlines of drought across the world and falling water tables, the business of water conservation using cutting-edge technology is just beginning.
On the municipal water front, WaterSmart Software is emerging as a quick software solution to help water companies empower their customers to save. The San Francisco-based company just signed three new customers in Orange County: the City of Newport Beach, Irvine Ranch Water District and South Coast Water District.
The expansion brings WaterSmart’s client base up to five, including a win with the East Bay Municipal Utility District in October. The single-digit wins may not seem extensive, but just a few months ago, the company -- which is like Opower for the water world -- released its first results from a pilot with an early customer.
WaterSmart uses a software-as-a-service platform to deliver about 5 percent savings through customer engagement. The company uses print and emailed home water reports, personalized recommendations for savings and comparisons to neighbors.
Unlike Opower, WaterSmart does not have the benefit of courting as many large utilities. The bulk of the U.S. is served by public water supplies, according to the U.S. Geological Survey.
After the pilot with the City of Cotati, Peter Yolles, CEO of WaterSmart, said that one of the most important advantages was not just the savings, but that people using WaterSmart were three times more likely to engage in other water conservation programs.
“WaterSmart’s products complement the work that the City of Newport Beach has been doing for years to educate our customers on water conservation strategies,” Shane Burckle, Conservation Manager of the City of Newport Beach, said in a statement. “In response to WaterSmart’s Home Water Reports, our customers proactively are asking us what actions they can take to save water.”
If that data point can be proven out across other utilities, it could build the appeal of WaterSmart in water-strapped states, like California and Arizona. But the West isn’t the only area where WaterSmart could find interest.
Last year, water prices rose an average of 9.4 percent for residential customers in 30 major metropolitan areas, and the largest relative rate increases were in Indianapolis and Milwaukee, according to Circle of Blue, an organization that reports on natural resource issues.
With crumbling infrastructure that makes the electrical grid look pretty good, water utilities will be scrambling for low-cost software solutions to reduce consumption while also planning for more significant investments in the basic infrastructure.
“This expansion into Orange County highlights the scalability of WaterSmart's products and their flexibility in adapting to Southern California’s unique requirements and needs,” Yolles said in a statement, adding that his company is also poised for growth into other regions in North America.
A cautionary report this week warned that California’s renewable energy ambitions could raise ratepayer’s utility bills, despite marketplace evidence of plunging solar and wind costs and rising coal and natural gas prices.
Rewiring California: Integrating Agendas for Energy Reform from the Little Hoover Institute, an independent 50-year-old California oversight agency, argued the state may be moving too fast toward meeting its Renewable Portfolio Standard (RPS) requirement to get 33 percent of its power from renewable sources by 2020.
“The Commission has been told by numerous people,” the report noted, “that California regulators and stakeholders are buried under a proliferation of new policies. The result may be greater costs and competing policies that ultimately may thwart the state’s efforts to achieve its environmental policy goals.”
Californians “already pay almost a third more for their electricity than the national average,” it stated, and in the rush to meet the 2020 mandate, the California Public Utility Commission (CPUC) signed more than 200 power purchase agreements (PPAs) for over 18.5 gigawatts of investor-owned utility (IOU) renewable capacity. “As a result, their customers may not benefit from lower costs as renewable energy technology matures and prices potentially decline.”
Worse still, the report cautioned, the rush to the RPS could result in “consumer anger that may erupt if a ‘rate impact bomb’ explodes in 2015 or 2016 and consumers begin paying for the electricity generated by the new renewable plants now under development.”
There could, indeed, be a "rate impact bomb" in the coming decade, according the CPUC’s Division of Ratepayer Advocates (DRA), but it will have little to do with renewables.
“The report properly suggests that the state needs to do what it can to control utility rates,” the DRA said in response to the report, because “rates may increase as much as 30 percent in the next eight years.”
Such an increase would be the result of “a number of factors,” the DRA said. “Replacing aging infrastructure and improving gas systems will likely be major cost drivers,” it noted.
But “the renewable premium,” DRA asserted, “should be in the range of 5 percent to 7 percent of total rate increases in the same period.”
The renewable premium is the difference between the cost of procuring renewables to meet the RPS and the cost of procuring non-RPS, mostly conventional natural gas, resources to meet electricity demand.
DRA used the 2010 long-term procurement planning (LTPP) model created by nonpartisan research firm E3, which provides technical analysis to the CPUC and other electricity market players, to calculate the long-term rate increase impact and the RPS premium. It used proprietary Pacific Gas and Electric usage information to model utility bill impacts.
“The 30 percent increase in system rates over the next eight years were caused by increases in costs in most IOU system components, including distribution, transmission, and generation,” DRA explained. “Both transmission and generation (both RPS and non-RPS) have relatively larger increases than other system components.”
More than one month after Hurricane Sandy battered many mid-Atlantic states, Chris Mejia of Consolidated Solar was dropping off two more solar generators to some of the hardest hit areas as part of the Solar Sandy project.
The power is back on, the gas lines are gone, but the need for generators -- now necessary for the massive cleanup effort -- continues.
Around ten of Consolidated Solar’s generators have been deployed to areas like Staten Island, Union Beach, N.J. and the Rockaways. The company, located in central Pennsylvania, has been working with Solar One, SolarCity and NYSERDA to bring the generators wherever they are needed, moving them as communities’ needs change.
At first, Mejia looked toward government organizations to bring the generators, which are made by DC Solar Solutions, to areas and those in need, but hit roadblocks and dead ends. Local and regional governments stockpile gas generators ahead of disasters (not to mention for large public events like marathons), but in the middle of disaster relief, government agencies didn’t seem interested in investigating new technologies. Eventually, he simply googled “Hurricane Sandy relief organizations” and found Solar One, a nonprofit clean energy group.
Consolidated Solar is a startup that could not afford to simply donate the generators outright, but Mejia could deliver the generators at cost. The systems are generally rented out to construction and outdoor events, such as fairs. For those jobs, the operating costs are almost guaranteed to be cheaper than gas generators, said Mejia.
For Sandy relief, Mejia has been bringing 10-kilowatt generators to where they’re needed. The arrays are large enough to power tools, laptops, phones, heat food and run basic lighting. He also has larger 20-kilowatt generators that can be equipped with batteries, which could be used for cell phone towers; alternatively, multiple 10-kilowatt generators can be linked to power entire buildings.
Nearly a month after the first generator was brought to the Rockaways, the organizations running Solar Sandy are exploring avenues to make solar generators a more permanent solution as part of disaster relief.
“My biggest intention when the hurricane hit was to get these out there to help people, but as a business, I’d love if this turned into a longer-term situation,” said Mejia, who launched the company less than a year ago.
Given the stress on gas supplies after Sandy, the renewable community is hoping that officials will be looking to diversify their options during a storm. Solar One’s building became a meeting place right after the storm, as its solar panels continued to keep the lights on in its building when the rest of the community was dark.
“We were able to get our solar system up and working within 24 hours. If there were more buildings that are like that, that’d be a powerful message,” said Sara Jayanthi, senior NYSERDA Energy $mart Communities Coordinator at Solar One.
Chris Collins, executive director of Solar One, envisions having mobile solar charging stations deployed in critical areas, where power is most likely to go out, before storms hit.
Having a vision and traversing the post-Sandy political landscape are very different, however. Solar Sandy advocates are currently knocking on doors and attending meetings to find out how more solar generators could be added to the mix of disaster relief. FEMA is the biggest catch, but there are a variety of local and regional organizations that could make use of the solar generators.
“It’s clean; it’s a money saver,” said Mejia. “There are a lot of applications and it’s just a matter of getting them out in front of people.”
A lot of factors go calculating the extra costs, and extra benefits, of LED lighting over traditional incandescent or fluorescent lights. One of the key costs remains the challenge of integrating light-emitting diodes -- semiconductors, with the fast development and tech turnover times of that industry -- into a lighting industry that doesn’t change much at all over the decades.
Bridgelux, the LED startup, launched its new Vero product line on Wednesday meant to make LED lighting fixtures simpler and more modular to build. Consider it another move toward integration in the LED industry, where both lighting giants like GE, Philips and Sylvania and startups like Bridgelux, Digital Lumens, LEDnovation and LEDWiser are competing to define what the LEDs of the future will look like.
Beyond coming with higher flux density and an increase in lumens per watt by up to 20 percent over existing Bridgelux LED arrays, the new Vero line of products also decouples the LED light engine from the body or frame that holds the engine in place, according to Jason Posselt, vice president of global marketing at Bridgelux. LED engines are built on metal circuit boards that have good thermal and lighting properties, but they need to be soldered to some kind of frame that holds them in place -- and because they’re good at conducting heat away from the LED, they’re also tricky to solder.
The new Vero line, by contrast, includes a selection of different LED engines, along with a set of plastic bodies that clip into place around the engine. That allows for faster and easier assembly in the factory, along with a host of quality control improvements like optic locators, bar codes for part traceability, and the like, he said.
Bridgelux, which works with a number of unnamed lighting customers, as well as named partners like Chevron Energy Services and Tyco International, has already worked with some partners to integrate its LED engines into plastic bodies from other companies, Posselt said. But putting the two together as one solution is far less common -- “I believe this is a first of a kind product in the market,” he said.
It’s certainly not the first move in the LED industry toward integration, however. According to this summer’s Enterprise LED market research report by Groom Energy and Greentech Media, the share of an LED fixture’s bill of materials attributable to the LED components themselves have fallen from 50 percent a few years ago to 20 percent to 30 percent of the cost -- and prices are expected to keep falling based on newer chip technology and manufacturing scale. That means balance-of-system costs -- optics, thermal management, mechanical structure and power, and of course, manufacturing and supply chain integration costs -- are big new targets for cost reduction and innovation in today’s LED marketplace.
The same logic has led to a string of acquisitions in the LED space, such as LED maker Cree’s purchase of lighting fixture manufacturer Ruud/Beta last year. Startups like Lunera and Digital Lumens are building their own fixtures in various formats to serve specific markets, such as high-end commercial spaces or warehouse lighting. We've also seen partnerships that are linking LED lights to smart lighting control systems from companies like Redwood Systems and Daintree Networks.
Of course, Asian competitors including LG, Panasonic, Samsung, Sharp and Toshiba have announced plans to enter the LED market as well. In the future, Chinese manufacturers are bound to offer stiff price competition to U.S. and European lighting giants and startups alike. Squeezing efficiencies out of every stage of the process will be critical for companies trying to grab market share in the new LED lighting market.
Bridgelux hasn’t come up with any hard numbers on how its Vero product line might help reduce costs and improve efficiency for its partners on that front. But Posselt said that the company is already testing the product with certain key customers, and expects general commercial availability early next year.
Silevo continues to make solar panel performance breakthroughs.
First, Sandia National Laboratories measured the proprietary tunneling junction cell architecture at a 22.1 percent cell conversion efficiency, up from its previous best of 21.4 percent. Business Development and Marketing VP Chris Beitel says this puts the Silevo modules in an efficiency category matched only by SunPower (NASDAQ:SPWR) and Sanyo (NYSE:PC) among crystalline silicon-based products.
Beitel said Silevo’s “hybrid solar cell concept” is cost-competitive with those manufacturers because it “couples the best attributes of materials characterized in solar and other industries for many years.” It has “a crystalline silicon substrate,” “an oxide layer,” “an amorphous silicon layer like that used in thin-film silicon solar technologies,” and “a copper-based metallization scheme," Beitel explained.
Silevo’s second performance achievement was earning a 93.5 percent PTC-to-STC ratio in the California Energy Commission (CEC) December rankings, the top number for the 295 watts-peak category. The ratio measures what part of the standard test conditions (STC) rated power a module can produce under the higher temperature conditions (PTC) it would likely face after long hours in the California sun.
A number of other manufacturers’ modules in the CEC’s 295 watts-peak rankings approach Silevo’s number, notably Suntech (NYSE:STP) (92.8 percent), SunPower (91.9 percent), and Trina (NYSE:TSL) (91.8 percent). But, in calling Silevo’s ratio “impressive,” PV Evolution Labs CEO Jenya Meydbray noted that “every fraction of a percent matters.”
Finally, the Triex module’s performance in the Renewable Energy Test Center's (RETC) cutting-edge Potential Induced Degradation (PID) testing was matched by only one other manufacturer’s modules, according to RETC VP Cherif Kedir. Silevo’s panels endured 1,500 hours of testing before losing power output and performance degraded beyond 5 percent only after 2,000 hours of testing. Few other modules were tested as many as 200 hours.
The PID rating measures a module’s performance if it is grounded in a manner not compatible with the system.
Renewable Energy Testing Center (RETC) VP Cherif Kedir called the Silevo PID test performance “pretty significant.” As part of an NREL-chaired panel to establish an industry-wide PID standard, he pointed out that Silevo’s RETC-conducted 2,000-hour test exceeded the proposed 96-hour standard and the temperature conditions were more demanding.
The proposed PID standard test would subject a panel in a 60-degrees-Celsius, 85-percent-humidity chamber to a voltage bias caused by incompatible grounding. RETC’s test put Silevo’s module in an 85-degrees-Celsius, 85-percent-humidity chamber and subjected it to a 1,000-volt bias.
“The reason the Silevo results are important,” Kedir explained, “is that of the close to 100 panels we have tested, some die off -- that is, lose 5 percent of their power output -- as early as 50 or 100 hours [into the testing]. The majority stay on for 200 or 300 hours.” Only one other panel, he said, matched the Silevo panel’s 1,500-hour performance.”
Meydbray said his lab typically tests for 600 hours and has found that modules either fail within 50 or 100 hours or show little degradation over the test period.
In 95 percent to 98 percent of cases, where a module’s grounding is compatible with the system in which it is configured, Kedir acknowledged, “you would never see this problem.”
There are other parameters important to the choice of a module, such as the quantification of how light induces degradation and how the angle of sunlight alters power output. And there is the question of the cost of the power.
“The solar space is stressed, but our belief is that it comes down to product value and product differentiation,” Beitel said, and these ratings and measurements differentiate the Silevo product by affirming its high value.
Beitel said the marketplace has also affirmed that value. “We have a 32-megawatt line in China and we are oversubscribed,” Beitel said. “The executive team is out right now surveying the next sites for manufacturing expansion. Our plan is to make a site selection, raise the necessary capital and expand our operations by 200 megawatts next year.”
Meydbray said that assessing a module’s quality, something increasingly vital to those who are being asked to put tens or hundreds of million dollars into solar projects and solar funds, is very complicated and necessitates a wide range of tests.
Silevo still must prove its real-world performance and find acceptance among customers. Or, as Beitel put it, “assemble installations, and work on bankability issues, and show performance and get validation of it, and show energy harvest benefit.”
China built 2.9 gigawatts of wind capacity in Q3 2012, according to the just-released GTM Research-Azure International China Wind Market Quarterly, and stands as the global leader in installed wind.
With 9 gigawatts expected to be completed in Q4, China wind should approach 18 gigawatts for the year, its highest annual installation number. That would put it at a cumulative 80 gigawatts of installed wind capacity.
But the numbers don’t tell the whole story.
“Curtailment remains one of the largest issues overhanging the future growth of wind power in China,” according to the publication. From 2009 to 2011, “China’s curtailed wind power resulted in a RMB 11.6 billion economic loss, which is equivalent to 6.77 million tons of coal, equivalent to 13.4 million tons CO2 emissions.”
Furthermore, “the ratio between wind capacity and peak demand would suggest” that curtailment “will worsen in areas already suffering” and will “expand to new areas. [... W]hile new transmission capacity will reach areas of high containment after 2014, it appears that it will fall considerably short of addressing the curtailment problem.”
Renewables, largely wind, represented about 26 percent of China's installed electric capacity in 2010, but only 18 percent of its generation and only 9 percent of final energy consumption, reported a recent study of curtailment in China by American Council on Renewable Energy Intern Liz Brody.
Part of the cause, Brody said, was the “lower-than-estimated capacity factors" of Chinese wind turbines.
But, she found, “the lack of grid connection, the throttling of wind energy, and turbine idling are the primary culprits.” This resulted, Brody’s study found, from policy failures that drove wind installation in remote provinces without drivers for new transmission and interconnection.
Mid-to-late 1990s policies moved China’s 74 megawatts of wind in 1996 to 344 megawatts in 2000. “The Renewable Energy Law, which created a national framework for pricing, grid connection, and incentive policies came into effect in 2006,” Brody reported. “Its target was the installation of five gigawatts of wind-power capacity by 2010. By the end of 2008, 12.15 gigawatts worth had been constructed across 24 provinces – 143 percent above target and two years ahead of schedule.”
But “as late as 2009, a whopping 30 percent of installations had not been connected to the grid.”
Newer policies have somewhat rectified the situation, Brody told GTM. This is verified in the Q3 Quarterly, which puts current average curtailment at 16.9 percent.
One key challenge, Brody’s study said, is “the unique, semi-private status” of China’s state-owned enterprises (SOEs) which deeply influence Chinese enterprise but “often act in the interest of their bottom line rather than in response to development directives from the central government.”
Another, Brody’s study added, is that China’s central energy agencies have limited influence over state-owned grid operators State Grid and Southern Grid.
And despite the newest laws, Brody said, incentives remain misaligned.
“The new requirement to obtain centralized approval from the National Development and Reform Commission for all wind projects is certainly better than the previous law that required central approval only for projects above 50 megawatts and resulted in a lot of 49 megawatt projects that were reportedly carved from unapproved larger projects.”
Projects under 50 megawatts were “approved at the provincial level,” Brody said. “The way local officials are incentivized makes them more willing to approve things that would not necessarily perform long term.”
More central approval “is good because it will put a cork in rampant new wind project development in areas already saturated,” Brody said, “but it can’t be the ultimate solution.”
Basic changes are needed, Brody said. “They have to stop giving the biggest contracts, discounted loans, free land and development priority to the SOEs because it disincentivizes smaller companies from innovating and slows technology advances.”
It might be necessary, she added, “to change the incentive structure so that developers are incentivized to build smaller scale wind projects closer to population centers or to integrate clean energy with buildings.”
An even bigger problem “is getting subsidies to the grid companies to help them pay for better interconnections,” Brody said. Because the grid companies are state owned and without competition, “the central government is going to have to shell out a lot of money to strengthen the grid.”
But the state is already building the biggest HVDC line in the world to connect the north and the south, Brody noted, and providing subsidies to the grid companies for interconnection. “The rhetoric has shifted from developing capacity to connection issues.”
Policies similar to U.S. renewables mandates now require regional grid companies to purchase a certain percentage of power in their localities, Brody said. “That seems like a good way to motivate grid companies to connect and turn on wind turbines,” she added, “but like anything in China, the questions are whether they can be enforced and whether there will be accurate reporting. It is a question anywhere in the world but maybe even more so in China.”
As new President Xi Jinping noted when he and Li Keqiang took office office during the just completed Eighteenth Congress, corruption has been endemic in China.
There is optimism that the new President, because he is next generation, has ties to the west, and is market oriented, may do more than pay lip service to fighting corruption. China’s soaring demand for energy and recent history of commitment to renewables, Brody added, fuels the optimism.
Powerit Solutions has completed a Series C financing round, raising $5.5 million. The industrial demand response company will use the funds to expand its work with strategic partners, launch its cloud product and integrate its Spara EMS into industrial automation and smart grid platforms.
The round includes $3 million raised in April and another $2.5 million investment from November. The Seattle-based company has raised about $23.6 million to-date. The company’s latest round of funding, which was led by Black Coral Capital, will also allow it to make a move into Europe.
Powerit announced its cloud platform earlier this year, SparaHub, which provides companies with a web-based dashboard that can connect different buildings’ energy use with utility rate schedules and demand response programs.
The company works with about 150 facilities, mostly large industrial sites like factories and steel furnaces. Powerit initially focused on the food and beverage manufacturing business and last year expanded into the metals market with an agreement with Inductotherm Corp., the market leader in equipment for the melting of metals and materials.
“Our investors are excited about Powerit’s expansion of strategic partnerships as well as the upcoming launch of Spara into the cloud,” Kevin Klustner, CEO of Powerit, said in statement. “We are pioneers in our field, and our hundreds of existing installations and active collaborations with utilities, OEMs, and system integrators are enabling us to help industrial facilities worldwide effortlessly control energy use for savings and sustainability.”
Powerit has been building channel partners to sell Spara and now works with four automation distributors: Border States Electric, French Gerleman, McNaughton-McKay Electric Company and Schaedler Yesco Distribution.
Not only is Powerit looking to expand channel partners, but Klustner also told Greentech Media that it could use SparaHub to embed controls in industrial devices themselves. The moves comes at a time when California’s three big investor-owned utilities are putting their weight behind OpenADR 2.0, the open standard to connect assets to the grid for demand response. Powerit’s platform is based on OpenADR standards.
"Powerit is uniquely positioned in the industrial automation market as the last mile linking facilities to the smart grid, so they can tap into savings and ever-more sophisticated demand management strategies,” Rob Day of Black Coral Capital said in a statement.
There are many other companies using increasingly automated and sophisticated software for building energy management, such as EnerNOC, SCIenergy, Serious Energy, General Electric, Honeywell, Siemens, Johnson Controls, Constellation Energy and Viridity Energy. But few companies are squarely focused on the heavy industrial market for automated demand response and energy markets the way Powerit is.
“The potential energy savings in the industrial market are still largely untapped,” added Day. “Spara is on track to be a key technology in this huge sector as energy prices continue to rise.”
This is the second piece in a series on the balance-of-system (BOS) tracker market from GTM Research. To read part one, click here. To learn more about the larger BOS market, its technology costs, leading players and market outlook to 2016, click here.
Operations & Maintenance (O&M) Cost
Tracking systems require more maintenance and, simply by virtue of having more moving parts, are more likely to malfunction. In areas with high labor costs, this can have a meaningful impact on project economics. O&M costs for 1-axis tracking can be as much as $0.01/Wp more than traditional ﬁxed-tilt systems.
However, tracker manufacturers like to remind skeptics that the duty cycle for tracker motors is a fraction of their capability. In response to the claim that trackers increase maintenance, a prominent tracker manufacturer remarked, “Nearly every home today has appliances with motors. Examples are washing machines and refrigerators. These systems are very reliable, and there is an infrastructure for O&M. Furthermore, solar trackers now have over a decade of operating experience. Note that solar trackers only turn one revolution per day. This equates to 7300 revolutions in twenty years. By analogy, with a simple wristwatch, this equates to the number of revolutions the second hand on a watch will make in 121.6 hours, or five days. Thus, the argument that trackers cost more to maintain is slowly ﬁzzling out with the increasing number of deployed tracker systems operating well.”
FIGURE: Comparison of Fixed and Tracking Systems
Source: Solar PV Balance of System (BOS) Markets: Technologies, Costs and Leading Companies, 2013-2016
The figure below shows the power curves of a fixed project and a tracking project located in Phoenix, Arizona. Tracker systems produce more energy later in the day than fixed systems. Utilities need energy from PV systems late in the afternoon, especially during summer, to help reduce peak loading costs as homeowners return from work and ﬁre up air conditioners, ovens, televisions, etc. Trackers provide energy to utilities when they need it most. That is reﬂected in some markets by the use of TOD pricing.
FIGURE: Energy Production Comparison, Fixed-Tilt vs. One-Axis Tracking
Source: Solar PV Balance of System (BOS) Markets: Technologies, Costs and Leading Companies, 2013-2016
Time-of-Delivery or Time-of-Day (TOD) Pricing
One of the major benefits of tracking systems is their ability to maximize generation during peak hours in the late morning and early evening. California utilities SCE and PG&E, for example, offer average TOD factors of between 1.25 and 1.30. In other words, PV projects in California receive an average of 25 percent to 30 percent above the base power purchase agreement (PPA) price as a result of peak generation. However, not all PPAs include TOD factors in their rates. Where TOD rates are available, tracking systems will maximize this benefit. The following figure explains the benefits accrued from the TOD factor.
FIGURE: Revenue Impacts of Fixed-Tilt Versus Tracking Systems
Source: Solar PV Balance of System (BOS) Markets: Technologies, Costs and Leading Companies, 2013-2016
A tracker system in a location with TOD pricing can generate up to 33 percent increased revenue over ﬁxed-tilt systems. In the non-TOD locations, this differential is 25 percent over ﬁxed-tilt systems.
- Soil type: Some soil types do not allow for the mounting rack to penetrate the ground (due to the pH level in that particular site), leading to a ballast system installation and hence a different cost structure.
- Wind loading has a significant impact on the design when higher-gauge steel is needed in order to prevent the system from damage. Many systems go into “stow” position when wind speed exceeds certain limits in order to prevent the damage of the system/modules.
Irradiance: Irradiance from the sun is another determining factor that affects whether tracker or ﬁxed-tilt systems should be selected for a specific project. The chart below illustrates the energy harvest in different locations compared with the percentage increase in energy harvest when using a 1-axis tracker. As is evident from the chart, there is a significant correlation between higher irradiance and the increased energy harvest when 1-axis trackers are used.
FIGURE: Energy Harvest, Fixed vs. One-Axis Tracking
Source: Solar PV Balance of System (BOS) Markets: Technologies, Costs and Leading Companies, 2013-2016
In summary, the choice between a fixed system and a tracking system is by no means simple. Cost, utility rate structure, conversion efficiency, land availability, and geographical factors must all be taken into account and compared against each other before a decision can be reached. In most locations, each system type will carry some benefits relative to the other, and developers will need to weigh the importance of each characteristic.
However, a few conclusions can be reached from this analysis. Energy harvest in high insolation areas is markedly improved using a single-axis tracking system. Previous to the free-fall in crystalline module pricing, for areas such as Arizona and New Mexico, with high temperatures, high availability of land, and no TOD factor in PPAs, ﬁxed-tilt projects with lower efficiency modules (e.g., CdTe) had an advantage in terms of energy harvest, as well as capital cost. The cost advantage has been weakened with the current comparability of thin-ﬁlm and crystalline module pricing. Thin ﬁlm companies are searching for alternatives to increase value to clients.
We feel that the move toward thin ﬁlm on trackers has been accelerated, perhaps before tracker technology is actually ready, because of the downward pressure on module pricing, thus the need to innovate and provide value to clients that can no longer be provided by competitive pricing. Nevertheless, each project will tailor its technology and mounting selection to the needs of the individual site and power purchaser.
A forthcoming book argues that the country's shale gas plays contain only about a quarter of the fuel that has been estimated by the U.S. Energy Information Administration, and other widely used industry and academic assessments.
Cold, Hungry and In the Dark: Exploding the Natural Gas Supply Myth by Bill Powers asserts that the quantity of unproved but technically recoverable natural gas in U.S. shale plays is approximately 127 trillion cubic feet, or about a quarter of the 482 tcf estimated by the EIA in its Annual Energy Outlook for 2012.
Powers, who publishes a newsletter for energy investors, argues that existing natural gas plays have not been nearly as productive as their backers predicted, and so cannot be expected to live up to expectations for future output.
"Recent drilling success has been extrapolated into the future," said Powers, who also sits on the board of the Calgary oil and gas company Arsenal Energy. "That's not supported by drilling history."
In Arkansas' Fayetteville Shale, 4,400 wells have produced 3.3 tcf since 2005, according to the Arkansas Oil & Gas Commission, or around a tenth of the 32 tcf that the EIA says is technically recoverable. In reality, Powers says, the Fayetteville Shale contains a total recoverable resource (TRR) of just 10 tcf.
In Louisiana, Arkansas and east Texas, the Haynesville Shale has produced around 5 tcf so far, Powers said. He predicted it has a total recoverable resource of 10 to 20 tcf, far short of the EIA's estimate of 75 tcf, a number Powers called "ridiculous."
Swimming Against the Current
He applies the same argument to Michigan's Antrim Shale, a play that has not been subject to the new wave of hydraulic fracturing and horizontal drilling that has made many shale beds economic, but whose long history since the mid-1980s shows production that he says has fallen short of expectations.
The Antrim has so far produced 3 tcf from some 10,000 wells, and its output has been declining since 1998, according to the Michigan Public Service Commission. Powers predicted the shale contains a TRR of 2 tcf, sharply lower than the 20 tcf predicted by the EIA.
Powers is the latest analyst to argue that the widely heralded shale gas "revolution" may be overblown. Other skeptics include Houston-based petroleum consultant Arthur Berman, who has long claimed that resource estimates are being overstated by energy companies seeking to defend their stock prices.
Berman, who writes the foreword to Powers' book, said the national gas resource, including proven reserves, is likely to equal about twenty-two years of consumption at the current rate, or less than a quarter of the 100 years' worth that is often cited by analysts and policymakers, including President Obama.
Berman's forecast is based on an estimate of probable reserves published by the Potential Gas Committee at the Colorado School of Mines, a 100-strong panel of company representatives that Berman called the "gold standard" of natural gas resource estimation.
"There is a great deal more uncertainty in this whole shale revolution than most people want to believe," Berman told AOL Energy. "There is definitely less gas than the propaganda says."
This is the first in a two-part AOL Energy series on the topic of U.S. shale gas reserves; check back soon for the conclusion.
Maybe the most important end node for the internet of things of the future will end up being the parking spot.
Networking giant Cisco and smart-parking startup Streetline plan to test that proposition with two projects announced Tuesday morning. The two will connect drivers to up-to-the-minute data on parking spots in two busy Silicon Valley commercial corridors -- San Mateo’s 3rd Avenue, and San Carlos’s Laurel Street.
It’s the first partnership for the two companies, though not Streetline’s first deployment. The Foster City, Calif.-based startup is up and running in Los Angeles, Washington, D.C., Knoxville, Tenn., Reno, Nev. and Fort Lauderdale, Fla. with its parking space sensors and management systems for city governments, private parking garages, and “Parker” app for iPhone and Android smart phone users.
Streetline has raised two rounds of venture investment, including a $15 million round last year from investors including RockPort Capital Partners, Sutter Hill Ventures and Fontinalis Partners, a firm co-founded by Ford Motor Co. chairman Bill Ford. In April, it set up a $25 million line of credit with Citi to finance its projects, which allow drivers (or, hopefully, less preoccupied passengers) to look up free parking spaces in their area, check pricing and special offers on hand from local garages, make digital payments and reservations, and map it all to their own GPS coordinates.
It’s not the only company applying big data and ubiquitous networking ideas to try and reduce time and fuel wasted looking for parking. Other companies have tried crowd-sourcing parking spot location apps, or aggregating parking garage availability data online, for example.
But Streetline is among the first companies to be mass-deploying a network of real-time sensors in city streets, CEO Zia Yusuf told me in an October interview at the SXSW Eco conference in Austin, Texas. The system costs about $200 per parking space upfront to install, and $20 per space per month to manage, he said. But cities can quickly recoup the embedded costs of these battery-powered, real-time sensor networks by fine-tuning parking management and pricing, as well as crunching the data for better urban and traffic planning, he said.
The City Network That Pays for Itself
So far, Streetline has used WirelessHART low-power wireless mesh networking technology from Dust Networks, a Bay Area startup that was acquired by Linear Technology last year, to link its nodes, which are embedded in parking meters or in the pavement itself. Siemens has been the startup’s partner on deployment and project management, and IBM, which named Streetline its 2010 global entrepreneur of the year, provides the data analysis tools to crunch all the data from parking spaces, garage booking systems, and the thousands of mobile users of Streetline’s Parker app.
With Cisco, Streetline can now incorporate its technology to an array of network devices, including multi-communications capable routers like those Cisco has built for the smart grid. That provides a way to incorporate Streetline’s data flow into Cisco’s smart grid wireless mesh networks being deployed via partners like Itron, Elster and Alstom, as well as SCADA systems at the heart of utility networks -- and, of course, to the cloud at large. Cisco is also one of a number of IT giants, such as IBM, Intel, Infosys, Microsoft and the like, working on “smart city” projects that link municipal services and networked sensors to better manage time, money and energy.
Of course, there’s a big difference between networking IT assets like laptops and smart phones, and networking the world of relatively simple, battery-powered devices around the home, office, or city street. The latter network has to be built to keep power-sipping devices attuned to one another, as well as the system’s needs, with an elegance that Wi-Fi or cellular networks don’t need to worry about.
“The internet of everything is where Cisco is focused,” Hardik Bhatt, director of Cisco’s Smart+Connected Communities initiative, said in a Monday interview. “The challenge is, connecting all of these unconnected things out in the street… that’s why we joined with Streetline, to allow us to build this network for the city.”
Parking, in turn, represents “a very interesting killer app” for getting the network to pay for itself, Kurt Buecheler, the startup’s vice president of business development and general manager of its ParkEdge (i.e., parking garage) business, said. When it comes to major revenue resources, “a city has taxes, then parking, then maybe something else, maybe nothing else,” he said. That makes parking a natural focus of city planners and budgeters alike.
Solving Parking’s Real-Time, Big Data Problem
At the same time, up to one-third of a city’s traffic consists of people trying to find a place to park, according to studies -- a maddening level of inefficiency in our transportation system that could be corrected, if street-level data can be collected, sent to the cloud and handed back to users in a timely fashion -- say, every minute or so.
Streetline’s system can pay for itself via improved enforcement, faster maintenance and repair and other such cost reductions, Buecheler said. But it can also discover new efficiencies and new revenue streams -- say, by linking local mall or restaurant specials to parking reservations, or guiding you to garages that offer lower rates to fill empty spaces, he said.
Then, once you have this network in, with these revenue streams driving it, “you have an easier opportunity to put a sensor on a water pipe, on a gas valve,” he said. “The world opens to these markets where they don't necessarily have a revenue model.”
Cisco and Streetline haven’t revealed what other types of street-level-to-cloud network and data analysis applications they’re eyeing for their joint deployments in San Mateo and San Carlos, which are relatively small compared to Streetline’s largest in LA and DC. First off will be simple applications, such as providing Streetline’s Parker app via Cisco’s Wi-Fi network in downtown San Carlos.
Beyond that, there are potential applications in devices ranging from streetlights -- another big-budget municipal item that can see big savings through networked sensors and controls -- to trash cans that tell the city when they’re full, Bhatt said by way of example. Streetline, for its part, is talking with various potential partners in the mobile and automotive space, Buecheler said, though he wouldn’t provide further details.
Wind sector consultants foresee this year’s ten-plus gigawatts of new U.S. installations dropping to perhaps three gigawatts in 2013 and not rising above five or six gigawatts for the foreseeable future, leaving wind developers face-to-face with severe consolidation.
West Coast-based turbine operations and maintenance (O&M) provider UpWind Solutions’ recent establishment of a new Canadian subsidiary, UpWind Solutions Canada, demonstrates that O&M, while perhaps not as glamorous as design and deployment, can be a sheltered harbor in a stormy market.
Though below the radar of many venture capitalists, O&M has often proven to be a reliable money-maker over time. Depot electronics maintenance and logistics player Data Exchange Corporation, which recently entered wind turbine maintenance through a European subsidiary, has used O&M for 30 years as a cash engine. The company never required equity funding, even as its disk and printer customers devoured each other’s profits (and each other) through the '80s and '90s, because the maintenance revenue continued to roll in.
The O&M business has two particular benefits. As a service industry, much of it on-site, it is immune to the kind of overseas competition and price-cutting that is currently hampering U.S. turbine tower makers. And installed wind turbines last long enough to confer immunity to short- and medium-term policy fluctuations like the current Production Tax Credit (PTC) expiration cliff.
UpWind Solutions, founded in 2007 in Medford, Oregon by wind industry veteran Bo Thisted and headed up more recently by Marty Crotty and Peter Wells, has received over $60 million from backers including Kleiner Perkins, Mission Capital, and Chrysalix. In May 2012, the company was listed in the Red Herring Top 100. In July 2012, the company closed a $29 million round, at a time when venture investing in wind companies is restrained.
Aside from the two gigawatts of wind the company maintains and repairs across North America, UpWind offers monitoring services for blades and drivetrain performance (UpWind Sentinel), for statistical analysis (UpWind Analytics), and for assessment reports (UpWind Reports).
The war room in Medford is lined with monitors displaying continent-wide lightning and turbulence warnings. “We feel a real mission,” VP of Sales and Marketing Robert Bergqvist said, “to keep making wind more competitive with fossil fuels, every quarter of every year.”
In 2010, UpWind entered the blade repair business by acquiring the Blade Services business of the Knight & Carver Wind Group, of San Diego California. It augmented that business in June 2012 through a partnership with Germany’s Smart Blade. Corporate headquarters were relocated to San Diego, although Medford continues to be the engineering center.
UpWind expects 35 percent year-on-year growth with the steep ramp of turbines, installed in the headiest days of wind’s 2006 through 2010 expansion, coming off five-year factory warranty over the next half-decade. Head count has grown from 40 in 2008 to 310 presently. Managing this growth has meant rapid learning curves. Human Relations director Heather Dennison was hired from Harry and David, a local Oregon boutique foods company. “One of the first things I did,” she said, “was to climb a turbine tower. If I was going to hire people to do this, I had to know. And it was so much fun.”
Privately held Upwind Solutions does not comment on gross revenues or profitability.
Other competitors in the O&M space include EDF Renewables/EnXco (EPA:EDF), Outland/Duke, Broadwind, Renew Energy, and Run Energy.
With the industry downturn, turbine makers such as General Electric (NYSE:GE), Vestas (PINK:VWDRY), and Gamesa (PINK:GCTAF) are moving into the O&M business to cover their own warranties and inherit the post-warranty opportunity. However, Bergqvist noted, “Customer satisfaction is better during the warranty period than afterwards.”
The following is a perspective from the author of GTM Research's latest report, Innovations in Crystalline Silicon PV 2013: Markets, Strategies and Leaders in Nine Technology Areas.
DuPont and Ferro recently announced sharp sales declines within their solar-cell-metallization paste divisions. Some have misinterpreted this news to mean that either the companies are losing significant market share to competitors or that solar panel installations are slowing. While 2012 has not been a strong growth year for PV, global installations do not appear to be decreasing.
Regarding the first point, these companies, together with Heraeus and Giga Solar, are still the clear leaders in the field, and are the unsung heroes of our industry – responsible for more steady improvements in cell performance and reduction in dollar-per-watt costs than any other industry sub-segment. The sales decline in silver pastes can largely be explained by the factors discussed below:
- The typical amount of silver paste used on the rear side of the cells has dropped dramatically (up to an 80 percent reduction) by printing segmented busbars with thin paste layers rather than continuous busbars with thick paste layers. In the future, with the new TinPad machine from equipment vendor Schmid, or the SmartWire approach from Meyer Burger, rear silver can be eliminated entirely from the cell design.
- The shift from two to three busbars has greatly reduced the amount of silver needed on the front side of the cells. Since the interconnect wires are closer together, the resistive power loss in the silver gridlines (fingers) is greatly reduced, and the fingers can be printed less tall.
As the selling prices of cells/modules has plummeted, the “optimum” height of the fingers has also come down. Paste, screen, and screen printer vendors are still bragging about how tall they can print their fingers, and it is true that the cell efficiency still improves as the finger height is increased. However, beyond a certain point, one reaches diminishing returns, and the additional module revenue does not justify the extra paste cost.
These last two points are clarified in the figures below. The first figure shows how for a particular 2-busbar cell design, back when modules were selling at $1 per watt, it probably made little sense to print the fingers taller than 15 microns high. The additional module revenue obtained by making higher-efficiency cells with taller fingers was less than the additional paste cost.
Now at $0.75 per watt, that number is down to around 13 microns, and it will drop further in the future. The cells designed when module prices were at $3 per watt clearly need to be re-optimized.
FIGURE: Calculation of the Tradeoff Between Silver Paste Cost and Additional Revenue From Higher Cell Efficiency as Finger Heights Are Increased for 2-Busbar Cells
Source: Innovations in Crystalline Silicon PV 2013: Markets, Strategies and Leaders in Nine Technology Areas
The next figure for 3-busbar cells (now the dominant cell design) shows the power of reducing the resistive power losses by decreasing the current path length in the fingers. It now makes little sense to print the fingers taller than 8 microns high.
FIGURE: Calculation of the Tradeoff Between Silver Paste Cost and Additional Revenue From Higher Cell Efficiency as Finger Heights Are Increased for 3-Busbar Cells
Source: Innovations in Crystalline Silicon PV 2013: Markets, Strategies and Leaders in Nine Technology Areas
New interconnect wiring equipment from multiple vendors will allow the finger heights to be reduced yet further and/or to enable higher cell efficiencies by adding additional wires, and in some cases by eliminating the front busbars.
- NPC: Stringer with 4 soldered wires
- Meyer-Burger/Somont: Stringer with 5 soldered wires
- Meyer-Burger: An array of round wires with no busbars in its SmartWire approach
Schmid: An array of round wires with no busbars in their Multi Busbar approach
Rather than printing taller fingers, the industry needs narrower fingers. This allows the fingers to be placed closer together to reduce resistive power losses in the silicon without increasing the shading losses. Plated contacts represent an attractive solution for the brave of heart, but the safer bet for most companies will be to ride the wave of improved pastes and printing equipment to bring finger widths down from around 85 microns now to less than 60 microns in the near future. Paste vendors, we need you as much as ever, but any of your customers that are “overmetallizing” their cells will likely not be around for long.
Want more competitive intelligence on the crystalline silicon PV materials market? Click here to learn about GTM Research's latest report, Innovations in Crystalline Silicon PV 2013: Markets, Strategies and Leaders in Nine Technology Areas.
However, the increased involvement of corporate VC arms and strategic investors is a relative bright spot in the cleantech investment landscape. Corporate venture investment in cleantech was $620 million in Q2 2012, up 319 percent from Q1 2012, according to CB Insights. Corporate funding has become a bit of a cushion for VCs in difficult times.
Bill Reichert of Garage Technology Ventures believes in a new approach to cleantech investing and working with corporate investors.
Reichert said, "We've seen a lot of pain in the cleantech market as cleantech VCs have backed away. But the corporates still need this innovation. We've seen corporates come in as VCs have backed away."
Garage has raised funding from an unnamed vendor as the initial LP in a new strategic corporate investment program. The new fund "is not set up with a traditional fund structure, because corporates have been frustrated by the typical fund structure." Garage is co-managing an investment off the corporate's balance sheet and is being paid a management fee "with an opportunity for upside."
The first fund is focused on energy technology and cleantech materials.
Reichert said, "This helps corporates get into the innovation ecosystem earlier. It's a way to work with corporate partners that have a strategically important need."
"The big guys usually invest in later-stage deals," Reichert added, and he contends that these investors don't have a lot of experience working at the earlier stage. Joyce Chung of Garage notes that this investment vehicle can help these corporate investors "understand the game of early-stage venture."
"The innovation for us as Garage, a trusted brand, is to act as a bridge between the entrepreneurs and the corporates. There needs to be a bridge that can talk to both sides, said Reichert, adding, "We are identifying their domains of strategic interest and identifying technologies that are not on their radar."
Corporate investors have different revenue expectations and timeframes than standard VCs. They also have potentially deeper pockets. But the traditional complaint hurled toward corporates by VCs is that the deals took too long and that goals were not always aligned. This type of investment vehicle might change that perception.
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.
Reichert wants the cleantech community to know that the investment firm is "open for business and looking for brilliant entrepreneurs" in advanced materials and renewables. He said, "There's fresh money coming into cleantech."
(On an unrelated note, Garage was one of the few parties, excepting perhaps recent CEO John Carrington, to land real returns from thin-film solar firm MiaSolé. Garage "sold a big chunk of stock in the third round," when MiaSolé stock had a valuation of $400 million.)
It’s official: California’s big three utilities are getting behind OpenADR 2.0, the latest version of an open standard for turning buildings, motors, microgrids and other distributed forms of “demand” into grid assets. Starting next year, Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric will ask their partners to support OpenADR 2.0-certified products and platforms for locational dispatch of both emergency and price-based programs.
That’s according to a Monday announcement from the OpenADR Alliance, an industry group that includes energy services heavyweights like Honeywell, EnerNOC and Schneider Electric, along with a host of startups and specialist technology providers working on the next generation of automated demand response.
OpenADR comes from a Berkeley National Laboratory and California Energy Commission-sponsored project to create a simple, common, open protocol for communicating utility messages to its customers. Early partners included demand response automation server (DRAS) maker Akuacom, which was bought by Honeywell in 2010, and software developer and architect UISOL, which was bought by Alstom last year.
Since then, we’ve seen a host of technology vendors jump into the standard, including Schneider Electric and IPKeys, and new Silicon Valley smart grid big data startup AutoGrid, which got its technology OpenADR 2.0-certified last month. Big demand response provider EnerNOC uses OpenADR 1.0 in deployments with various technology partners such as Powerit, as well as via acquired companies like Global Energy Partners and M2M Communications.
In the meantime, we’ve seen a host of Japanese companies join the OpenADR 2.0 fray, including Hitachi, Toshiba, Mitsubishi, NTT and Fujitsu, which just showed off its 2.0-compliant demand response server at the Grid-Interop 2012 event this week in Irving, Texas. All the while, Honeywell and Akuacom, which still dominate the market, have launched OpenADR-based projects in other parts of the U.S., in China and in the U.K., as well as with unnamed partners in Europe.
California’s big three utilities already manage about 260 megawatts of demand response via OpenADR 1.0, making it the biggest market for the technology. But OpenADR 1.0 has always had its limits -- a fact that has led much of the industry to pause and await the release of the 2.0 version, according to industry experts.
For example, beyond setting power prices and general “low-medium-high” type energy reduction alerts, OpenADR 1.0 contained little ability to take each individual customers’ power profile and dispatchable load into account. Indeed, once a utility’s OpenADR 1.0 signal got to the building, it’s up to the technology behind the meter, so to speak, to translate those commands or price signals into action, and then to verify that something had been done.
OpenADR 2.0 is meant to provide a much more fine-tuned level of communication between utility and end user. The OpenADR Alliance, an industry group including most of the above-named companies, released a 2.0a specification in April.
It’s important to note, however, that the industry is still waiting for OpenADR 2.0b -- a version that includes some of the most critical capabilities, including fast-response times of within 4 seconds, all running over the internet. That last feature will be critical for enlisting buildings in automatically adjusting power usage to balance grid instability, or helping to mitigate the intermittent nature of wind and solar power -- the latter a big issue for California as it seeks to reach 33 percent renewables by the end of the decade.
Finally, it’s important to differentiate the OpenADR standard’s development to another important standard in utility-to-customer energy management. That’s Smart Energy Profile 2.0, the technology developed by the low-power wireless ZigBee Alliance that also supports Wi-Fi and the data-over-powerline HomePlug standard.
The key difference between the two standards is that, while SE 2.0 is meant to contain all the instructions to command individual devices to take power-saving actions, OpenADR is more of a communications standard to get messages from utilities to their customers.
What the heck is going on in Illinois?
Last May, the Illinois Commerce Commission told Commonwealth Edison it had to cut about $146 million from the rates it could expect to collect from customers in 2012.
A few days ago, the Illinois Senate voted 47-4 for a resolution that protests the rate cuts imposed by the ICC, which ComEd says have hurt its efforts to carry through with modernizing its electricity grid.
Some of that money had to do with smart grid, but much of it did not. While the rate plan was rejected, the ICC did approve ComEd’s smart grid plan. The final approval of ComEd’s plan came about a month after the ICC rejected the Ameren Illinois smart grid plan altogether.
The ICC said it is asking Ameren for more information about how the technology would benefit customers before it allows the plan to proceed.
With the resolution that passed last week in the Illinois Senate, nearly nothing has changed, yet. The resolution is non-binding, but it “expresses the serious concern of the Senate over the Illinois Commerce Commission's orders implementing the Energy Infrastructure Modernization Act, commonly known as the smart-grid bill," Senate President John Cullerton (D-Chicago), told the Chicago Sun-Times.
The resolution calls for the ICC to allow for what the legislature’s Energy Infrastructure Modernization Act has already approved. Initially, ComEd had figured about $40 million to $50 million in cost reductions, but in May, the ICC told ComEd it had to quadruple the rate cut to about $146 million.
Many of the costs included in that figure have nothing to do with smart grid or its planned four million smart meters, and instead are related to pensions and other business costs that are not part of infrastructure improvements. It was unclear with the resolution last week from the Senate if the costs will be teased out separately.
According to Ameren, the resolution calls for the utilities to file changes to their rate tariffs that:
1) Apply an interest rate set at the utility's weighted average cost of capital; 2) set rate base and capital structure using final year-end values reflected in the Federal Energy Regulatory Commission (FERC) Form 1 rather than average numbers; and 3) correct errors the regulatory authority made.
This is hardly the final word in the Illinois smart grid saga, but rather the next chapter. Ameren said that it could not cover the investments of its smart grid plan based on the utility’s formula rate case, in which Ameren said its revenue would be cut by $48 million annually. But Ameren’s smart grid plan was not just rejected on a cost basis. In a news release after the rejection, the ICC stated that “Ameren’s Smart Grid deployment plan was 'vague and incomplete' and bordered on not being a plan at all, but rather a more of a general statement of intention to install smart meters in some parts of its service territory.”
Besides this issue being a multi-year power fight between legislators and regulators, the volleying over utility cost recovery in Illinois points to a larger issue that stretches beyond the state’s borders.
Last year, the ICC told Ameren Illinois and ComEd that it would have to prove the value of its smart grid investment, or pay the difference. The utilities will have to reduce outages by 20 percent, energy theft by 50 percent and inactive meters (those delivering power to unoccupied homes) by a whopping 90 percent under the new rules. These are the kinds of efficiencies that most smart meter projects out there promise they’ll deliver, but under Illinois’ new law, they’ll now be measured for year-by-year progress against those ten-year goals.
Other regulators are also holding investor-owned utilities’ feet to the fire, demanding that the technology investment -- which utilities argue will save millions in initial filings -- actually deliver those savings to customers. Many experts argue that it is the regulatory framework itself that also needs an overhaul.
This is the first year that some utilities are starting to show the value of some grid modernization projects. But clear examples of cost savings are still few and far between. Utilities that want to charge customers while reaping increased profits will increasingly be held to public scrutiny about what, exactly, the benefits are.
Moving into 2013 and beyond, measurement and verification of smart grid benefits -- from reduced outage times to better customer service -- will become not the exception, but the norm. In California, the three large investor-owned utilities need to report annually on various metrics to track the grid investments being made.
In Illinois, however, the smart grid saga is far from over. Stay tuned as grid modernization continues to be politicized well into 2013.
Fifteen years ago, Cal Poly Environmental Engineering graduate Judy Staley and former Air Force electronics technician Fred Sisson were looking for a "renewable energy concept" business that would make a difference. With a $100,000 mortgage on Staley’s mother’s house and credit cards, they built REC Solar into a leading system installer.
“I was always fascinated by solar power because it has no moving parts and is such a long-lasting technology,” Staley recalled. It was 1997. California had just instituted its net metering law. The Emerging Renewables Program, the policy precursor to today’s California Solar Initiative, was in the works. “Our goal became getting as much solar installed as possible. We started with residential customers and ramped up to doing commercial customers.”
“My first job out of school was at Diablo Canyon Nuclear Power Plant,” remembered REC VP and General Manager Ethan Miller, who came aboard in 2001 as one of the company's first salaried employees. “But I didn’t think that was the future of energy.”
When she and Sisson were able to pay salaries, Staley said, she realized the business was viable. She and Sisson were married then. They divorced later but remain “good friends.”
“We started by providing unique, custom solutions for customers’ needs,” Miller said. “If you wanted a wind system with battery backup and solar, too, and a generator, we could do it. But we realized we couldn’t offer a custom solution for everybody. I knew the business was viable when we were able to say ‘no’ to a few projects and focus on a specialized offering. That was in the 2003 to 2004 timeframe.”
“We were one of the first companies in California to focus on grid-connected solar systems,” Staley remembered. “Around late 2004-early 2005, we needed capital and I wanted somebody with more experience than me as President and CEO.” Angiolo Laviziano, previously with Conergy in Germany, took the job and invested in the company. They formed Mainstream Energy Corporation, now parent to both REC Solar and AEE Solar, the organization’s distribution arm.
REC Solar now has seventeen offices in six states and over 800 employees. It has installed 120-plus megawatts of solar at over 8,700 sites. In 2011, it installed nearly five times as many megawatts as in its first ten years.
But, Miller said, “we have stepped back from that growth trajectory. We have to be careful not to lean too far in. We’re dealing with much bigger numbers than in the early years but the growth rate has come down to a manageable level.” The emphases remain on “bringing solar to the mainstream” and on “a long term view of quality and customer service.”
Quality, Miller said, “means making sure that the systems will produce energy for the next twenty years.” Though REC Solar “placed some of the first purchase orders” with many of today’s panel makers and has long-term relationships with some, products are still selected cautiously.
Decisions on materials are made by REC Solar’s supply chain and engineering groups, Miller said. Panel selection is based on manufacturer specifications but also on whether the manufacturer can get the product delivered on time and on what the contractual and warranty terms are. “Price is important, but if we don’t take a holistic, end-to-end view, we are not going to get the lowest cost at the end of the day.”
REC Solar tests systems on its headquarters roof. “We have six different systems now,” Miller said. “I have had systems off-warranty, systems that I have seen through their full life cycle, ten-year-old systems without even one service issue, and technologies with a 100-percent failure rate.”
The company is typically not “the first on the bandwagon” with new technologies, Miller said, but he does foresee “an opportunity for some kind of smart module, whether with a microinverter or power optimizer, that hopefully will improve production and reduce costs.”
The company has moved to ballasted, non-penetrating racking for commercial installations.
The 2016 investment tax credit ratcheted down to 10 percent will not hurt solar, Staley said, if the total installation cost continues to fall. She expects financing to become more creative. “There was always the acknowledgement that better financing was needed,” she recalled. “Early on, before PPAs, we talked with banks about different loan programs to expand customers’ options. PPA models opened things up quite a bit.”
REC Solar was third-party-ownership (TPO) pioneer Sunrun’s “first partner ever,” Miller said. It continues to work “primarily, though not exclusively, with Sunrun.” TPO financing currently accounts for “roughly 80 percent of REC Solar’s residential installations and about half of its commercial installations.”
“Costs will continue to come down,” Miller predicted. “And consumer behavior will shift again. At a certain price point, you stop using financing vehicles. That is probably what keeps the leaders of the companies that do TPO awake at night. When Judy and I first started, the average home system might be a $40,000 purchase. Now it’s 30 percent of that and financed at no money down. The next step will be another total shift. It is on the horizon. It will become more like buying home security or windows.”
Solar startup Ampulse of Golden, Colorado is winding down its operations, according to sources. Calls to the CEO and the firm's VC investors have not been returned.
When we reported on the 150+ VC-funded solar startups in the last few years, we were clear that the majority would not survive and the shakeout would be painful. The loss of the ten-employee startup Ampulse is just a small step in this necessary consolidation.
Ampulse wanted to deposit a thin layer of monocrystalline silicon on a copper foil. Armed with substrate and buffer technology from Oak Ridge National Laboratory (ORNL) and Hot-Wire Chemical Vapor Deposition epitaxial silicon processing from NREL, Ampulse aimed to grow high-efficiency monocrystalline cells directly from silane gas.
The firm received more than $10 million from Globespan Capital Partners, El Dorado Ventures, Battelle Ventures and the DOE.
The firm was founded in 2008 when solar panels and silicon were a bit more expensive. In 2009, investor Daniel Leff of Globespan Capital said that Ampulse was on a “radically different cost curve" and would still outshine competitors even with the cheaper silicon and their push to improve efficiencies.
People close to the company observed very slow progress over the last few years and an inability of the Ampulse approach to support high (or even moderate) efficiencies.
Despite the apparent demise of Ampulse, the value proposition of cheaper and more efficient crystalline silicon remains valid. Although the cost of solar panels has plummeted, silicon remains a significant cost in the solar panel Bill of Materials. If less silicon can be used, if cells can be made more efficient, or if processing steps can be eliminated, there is still an opportunity for industry and entrepreneurs.
GTM Research just released a detailed report on new c-Si technologies, and report author Andrew Gabor speaks at length on the topic in this podcast. The report (and our ongoing online coverage) explores the benefits of thin silicon, ion implant technology, and other kerfless technologies, as well as diamond saws, encapsulants and new cell architectures.
Renewables in northwest Russia could make a better investment than the multi-billion-dollar DESERTEC North Africa solar undertaking, according to researchers at the International Finance Corporation (IFC).
Backed by many of Europe’s biggest financial institutions, the DESERTEC proposal would invest an estimated 400 billion euros in solar power plants and wind projects across North Africa and in new, sub-Mediterranean HVDC transmission to the EU grid. Funded by a consortium of 56 shareholders in fifteen countries that includes multinational financial giants like Munich RE, Deutsche Bank (NYSE:DB), ABB (NYSE:ABB), E.ON, and HSH Nordbank, DESERTEC could meet as much as 15 percent of Europe’s 2050 electricity needs.
The IFC’s RUSTEC would capture northwest Russia’s wind, hydro and biomass resources, which, because they are abundant, concentrated and underutilized, could be more cost-effective to develop. Existing and new transmission and enhanced or new interconnections could deliver the renewables-generated electricity to the EU grid, according to a paper by the IFC’s Patrick Willems and Anatole Boute. IFC’s Russia Renewable Energy Project (RREP) has commissioned an independent study to develop cost, timeframe and capacity potential details.
The paper addresses the possibility of opposition from Russia’s oil and gas interests, but, it notes, RUSTEC could benefit the oil and gas industry because Russian natural gas resources will be needed as balancing reserves for the grid integration of renewables.
“IFC’s RREP is exploring the feasibility of the RUSTEC idea,” explains Boute. “EU and Russian stakeholders have confirmed a clear interest in the concept and recognize its potential benefits. Investors are also working on the idea.” But, he underscored, there have been no “clear commitments.”
“We do expect a slightly different group of stakeholders involving more private developers, along with governmental agencies,” Willems notes.
Developing resources outside the EU, the RUSTEC proposers acknowledge, would prevent EU member nations from reaping all the social and economic benefits of developing domestic resources. But it may eliminate barriers to new renewable capacity, such as affordability and NIMBY opposition.
RUSTEC has two big advantages over DESERTEC, Willems and Boute say. Onshore wind’s LCOE is more cost-competitive than solar power plant technologies, as well as competitive with traditional grid generation sources in some places, and whatever new transmission and distribution infrastructure is needed to facilitate RUSTEC will be far more affordable than a new sub-Mediterranean transmission system.
Like DESERTEC, the RUSTEC driver would be the EU’s mandated 20 percent renewables by 2020 target and proposed 80 percent by 2050 goal. The EU directive establishing the 2020 target explicitly allows member states to draw on outside resources, the paper points out, if there is “a large renewable energy resource base that can easily be interconnected to the EU.”
“It is possible to implement projects before 2020 so as to enable EU Member States to meet their national targets at least cost,” Boute believes, if EU-Russia cross-border issues are resolved.
Russia’s electricity systems, the Boute-Willems paper said, “are interconnected with the network supervised by the European Network of Transmission System Operators for Electricity.” There is transmission already in use between northwest Russia and Norway, Finland, Estonia, Latvia, and Lithuania. New capability would be needed. Some plans are already in place.
“In the absence of interconnection reinforcement,” Boute believes, “renewable energy projects in Russia under joint projects are limited to existing Russia-EU electricity exchanges.”
“The northwest of Russia is characterized by a particularly favorable and relatively cost-efficient renewable energy resource base,” the paper reports. “Onshore wind patterns are comparable to offshore conditions in the North Sea” with “an estimated 40 percent capacity factor.”
Forest biomass potential could be as much as 60 terawatt-hours. Hydropower can be significantly expanded and used as pumped storage. A recent report on hydro and wind power in northwestern Russia, Willems and Boute note, found a potential for 16.2 billion kilowatt-hours per year.
“The instability and unpredictability of the Russian investment climate negatively affects the business case,” Willems and Boute observe. But improved EU-Russian cooperation could result from RUSTEC if strengthened contractual, regulatory and political agreements reinforce power purchase agreements (PPAs) and bilateral investment treaties.
RUSTEC would need to balance EU economies’ loss of domestic opportunities with improved opportunities to export intellectual property and high-tech equipment. Russia must balance the consumption of its renewable resources with the development of its renewable industries and infrastructure.
Past disruptions to natural gas supplies from Russia to Europe may concern some EU member states. But, the paper notes, “There is thus no risk of interruption due to conflicts between Russia and transit countries, as was the case with the Ukraine–Russia gas interruptions.”
The building of pilot projects delivered through existing infrastructure is a feasible short-term “way forward,” Willems believes. “A pilot 200-megawatt wind project in the northwest of Russia is possible.”
For the longer term, the paper proposes an agreement between participating nations on ‘‘appropriate steps’’ toward further development and interconnection capability. It also suggests the possibility of using proceeds from the EU’s Emissions Trading Scheme (ETS) to fund intermediate steps.
“The large renewable energy resource base in some parts of Russia, including the northwest, presents a cost benefit,” Willems and Boute believe. “Careful analysis will have to determine whether other costs such as network issues and risk premium could outweigh this benefit.”
Global Solar Energy was a CIGS flexible thin-film solar vendor notable for its small but real production volumes of 11-percent-efficient solar cell product.
According to Inside Tucson Business, Tucson-based Global Solar Energy has laid off about 95 of its employees and ceased operations. The company had a product line of portable solar charging equipment, flexible modules and building-integrated PV (BIPV). Global Solar had been selling CIGS products on a flexible substrate for more than eight years.
The firm was founded almost twenty years ago by UniSource Energy and ITN Energy Systems. Solon acquired Global Solar for $16 million in 2006.
The plummeting cost of crystalline silicon solar panels from China has eroded the value proposition of CIGS thin-film solar which has so far failed to meet its promises of low cost and competitive efficiency.
GTM Research has these estimates for CIGS solar production numbers in 2011:
- Solar Frontier, 577 megawatts
- Solibro, 95 megawatts (Sold to Hanergy)
- MiaSolé, 60 megawatts (Sold to Hanergy)
- Solyndra, 40 megawatts (Bankrupt)
- Avancis, 25 megawatts
- Global Solar, 19 megawatts (Now selling only consumer solar products)
- Soltecture, 14 megawatts (Bankrupt)
- Nanosolar, 10 megawatts
Other CIGS casualties include AQT, which closed its doors in August.
All of these CIGS vendors use vastly different technical approaches, but seemingly almost all will have similar fates -- either closing shop or selling at a loss to an Asian rescuer. MiaSolé found Hanergy, HelioVolt found SK Innovations, Ascent Solar found its own white knight in TFG Radiant.
Solar Frontier, the leader in CIGS production, sells 13-percent-efficient modules.
Solar Frontier, Stion, SoloPower, TSMC, NuvoSun, Nanosolar and a few others CIGS players are soldiering on in this materials system but still don't meet the price and performance of silicon photovoltaics. Nanosolar recently shipped more than 10 megawatts of CIGS solar to an installation in Valencia, Spain.
"ISET is in the process of launching a new spinoff, Pioneer PV Solutions, focused on growing into a Tier 1 supplier of microsolar components to OEM’s. Our sprayable CIGS with monolithic integration provides customization capability along with superior quality, yield, scalability, aesthetics, diffuse-light performance, and pricing than c-Si scrap wafers. [...] Our existing prototype line (batch) is ready to be replaced by Gen 2 (inline) now that our process specs are well defined. ISET’s R&D function will be relocated separately from the new Pioneer PV effort."
The firm will build small solar panels for integration into battery chargers and for DC power applications -- the same market once pursued by Global Solar.
Bankrupt lithium-ion battery maker A123 is headed for the auction block next week, setting the stage for an international bidding war over the assets of a once high-flying, government-backed green technology startup now fallen on hard times. Beyond would-be U.S. rescuer Johnson Controls and previous Chinese suitor Wanxiang, we’ve seen more than two dozen other parties jump into the fray.
All have different ideas of which parts of the Waltham, Mass.-based company’s core assets they’d like to buy. But parties to the Dec. 6 auction, ordered by U.S. Bankruptcy Judge Kevin Carey earlier this month, will have to contend with some severe political uncertainty in making their plans.
That’s because the U.S. government, which has given A123 about half of the money in a $249 million grant awarded in 2010 to help it build its Michigan factory, filed court documents this week stating any sale of A123 assets associated with that grant should have to get federal approval.
While the filing by principal deputy assistant attorney general Stuart Delery didn’t specify whether the government opposed or supported any specific bidders, the move is widely seen as an attempt to forestall a foreign takeover of A123. The prospect of China getting ahold of U.S. government-backed technology has raised an outcry from Republicans in Congress, who have already demanded investigations of A123 and other struggling, Department of Energy grant-backed companies in the wake of Solyndra’s bankruptcy.
China’s government, which isn’t exactly friendly with the U.S. on green technology trade issues right now, gave its approval this week to automotive technology giant Wanxiang’s plan to buy A123 outright. That proposal is in conflict with Johnson Control’s proposal to buy A123’s automotive energy storage and management business, including its DOE grant-backed Michigan factory, for $125 million. Other companies, including Germany’s Siemens and Japan’s NEC, have expressed interest in taking part in next week’s auction, according to news reports, and 25 parties have filed confidential statements of interest.
A123, founded in 2001 and funded by about $200 million in venture capital investment, went public for a $2-billion-plus valuation in 2010, only to crash and burn amidst consistent losses, slow growth for its electric vehicle battery business, and a fatal recall of batteries supplied to key EV partner Fisker Automotive.
Indeed, the fate of Fisker and A123 seem to be increasingly intertwined. Earlier this week, Fisker announced that it has idled production of its Karma plug-in hybrid sports cars due to A123’s reduced output, though it hopes to see the situation improve after next week’s auction brings clarity to who actually owns the business.