Combinations of onshore wind, offshore wind, and photovoltaic solar, paired with battery and hydrogen storage in a widespread grid system, could meet 90 percent to 99.9 percent of expected 2030 demand at almost no increased cost, according to a new study.
“The common view,” University of Delaware researchers noted in their report, “is that a high fraction of renewable power generation would be costly, and would either often leave us in the dark or would require massive electrical storage.”
The priority of the Regional Renewable Electricity Economic Optimization Model (RREEOM) was to see if demand could be met largely with renewables at an affordable cost.
The model used prices that left out federal and state subsidies but included the costs of fossil fuel externalities.
With storage, according to report co-author Cory Budischak, “we can run an electric system that today would meet a need of 72 gigawatts 99.9 percent of the time, using 17 gigawatts of solar, 68 gigawatts of offshore wind, and 115 gigawatts of inland wind.”
Reliability in a fossil fuel-based system, in which the operating principle is “burn when needed,” requires no computers, digital high-speed communications, or weather forecasting, the report noted. But “the ability to reliably meet load will still be required of systems in the future, despite the variability inherent in most renewable resources.”
To approximate a grid operator’s real world imperative to keep the lights on, the researchers modeled into RREEOM the PJM Interconnection system, a thirteen-state load that accounts for about 20 percent of U.S. electricity demand at approximately $0.1745 per kilowatt-hour.
The transmission model was limited to PJM’s grid and ignored reserve requirements, within-hourly fluctuations and ramp rates, all of which, it assumed, would be easily met with the hypothesized storage.
The varying sufficiencies and costs of more than 28 billion different combinations of renewables and storage were studied over a hypothetical four-year (35,040-hour) time period using actual PJM historical data to approximate real demand and real weather patterns. Historical insolation and wind data from DOE and NOAA were used for each hour being modeled.
“We find that 90 percent of hours are covered most cost-effectively by a system that generates from renewables 180 percent of the electrical energy needed by load, and 99.9 percent of hours are covered by generating almost 290 percent of need. Only nine hours to 72 hours of storage were required to cover 99.9 percent of hours of load over four years,” the report calculated.
So much free fuel from renewables would be available across the geographically dispersed 72-gigawatt PJM grid region that it would not only almost eliminate the need for natural gas reserves, but would also keep the power price low and minimize the need for incurring the cost of battery storage.
The result would be electricity at very near current prices supplied by between 90 percent and 99.9 percent renewables, because “over-generation is cost-effective at 2030 technology costs even when all excess is spilled. If excess generation displaces heating fuels, the cost is lowered further.”
Drawing on the “excess generation of renewables is a new idea,” the study went on, “but it is not problematic or inefficient, any more than it is problematic to build a thermal power plant requiring fuel input at 250 percent of the electrical output, as we do today.”
When there was excess generation, the model stored it. When there was inadequate supply, the model first used the stored generation and then, in a very few instances, natural gas for heating.
Cost assumptions, based on referenced studies, included improved renewables technologies and economies of scale but no unforeseen breakthrough changes. “At 2008 technology costs, 30 percent of hours is the lowest-cost mix we evaluated. At expected 2030 technology costs, the cost-minimum is 90 percent of hours met entirely by renewables. And 99.9 percent of hours, while not the cost-minimum, is lower in cost than today’s total cost of electricity.”
The most potentially controversial assumptions in the study were 1) that the price of renewables will be 50 percent lower by 2030, though operations and maintenance costs remain constant, and 2) that fossil fuel prices will include external costs now paid by taxpayers and health insurers [quite an assumption, even with a carbon tax -- Editor].
Renewable resource supply is adequate, the researchers noted, referencing studies that concluded “a shift to renewable power will increase the energy available to humanity.” Such studies have shown, the report noted, “that global energy demand, roughly 12.5 terawatts increasing to 17 terawatts in 2030, can be met with just 2.5 percent of accessible wind and solar resources, using current technologies.”
A study from Stanford’s Mark Jacobson and Mark Delucchi, the study noted, used eight renewables in conjunction with increased transmission and vehicle-to-grid storage technology to meet the entire world’s electricity needs.
Greentech Media published approximately 1,500 news articles in 2012. Here are fifteen of our favorites:
GTM Research's Shyam Mehta deconstructed solar industry myths, while Carolyn Campbell delved into "Life After the Solar ITC" (parts one, two and three). Our team of smart grid analysts provided the world with a list of the networked grid's movers and shakers.
Herman Trabish has been covering the wind and solar markets, and he shined in pieces covering AMSC and a China-U.S. IP battle and SolarCity putting teachers in the classroom. Here's a quote from his article on Clean Power Finance: “What you see in the last six months is literally billions of dollars getting committed for residential solar.”
One of our notable guest posts included Recurrent Energy's Sheldon Kimber on "Why Solar and Natural Gas Will Be Central to U.S. Energy Policy." Jigar Shah called out electrical utilities in his piece "Let's Make a Solar Net Metering Deal."
Jeff St. John took a long, careful look at the travails of a green building startup in "Serious Energy in Serious Trouble." The green drywall and windows company spent the past few years pushing into building energy-efficiency software and financing, and then abandoned those lines of business to refocus on its building materials core. It was a stunning reversal for the Sunnyvale, Calif.-based startup with $140 million in VC cash.
And Katie Tweed ably covered how the smart grid can limit outages during events like Hurricane Sandy; she also took a look at how "Microgrids Can Help Get Electricity to One Billion People" and "How Benchmarking Can Drive 7 Percent Cuts in Building Energy."
Thanks for reading Greentech Media in 2012.
We published part one of our interview with Lyndon Rive, the CEO of newly public distributed energy provider SolarCity, last week. It included Rive saying, "For the longest period, people used to call SolarCity the largest solar installer in the country. Argh. It would bug me. I would grind my teeth when I heard that."
We spoke with Rive about the treasury investigation on the 1603 grant program amidst questions that companies such as SolarCity, Sunrun, and Sungevity have been embellishing the prices claimed on grant paperwork.
Here are Rive's comments on 1603 and CSI data:
-"Depending on how far back you go with the CSI data -- when you pull out the application, you put in the price -- but we haven't sold it yet to the fund so we don't know what the fund is going to pay for it. So we would put in the maximum price that we could justify based on the income of the asset. Not much later, we may actually sell it to a fund, so that pricing may or may not be the final number [at which] we sold it to the fund. Depending on how far back you go, if you look at the current data, we're using our EPC [engineering, procurement, and construction] prices instead of the number that we are selling to the fund. That's what the market's all focused on. Seventy percent of the market is financed. Because SolarCity is the only vertically integrated company, historically we have put the number that we sold to the fund, not the EPC number. So all the numbers you see are only the EPC numbers."
-"So you see Sunrun buying an asset, you see Sungevity buying an asset, you see Clean Power Finance buying an asset, you see SunPower buying an asset. Those assets being bought are not being sold for the same number -- that's a very bad business. You don't need to be a mathematician to figure that out. To buy a system for $5 and to sell a system for $5 -- you cannot make that up in economies of scale. What they do is they include the overhead and the profit and they sell it for something higher than $5. That data is not available in the CSI, although 70 percent of the systems had a developer, margin and overhead tied to it."
-"So what is the market price of a system when 70 percent of the systems don't show their market price?"
-"That's the first [indication] that the CSI is misleading. The CSI only focuses on the EPC number, not the profit overhead of the developer. The developer has to include his cost and overhead -- otherwise, 70 percent of the systems sold would not be sold. It's a stupid business to be in if you can't include your cost and overhead. Even with that said, if you do an analysis of our pricing, SolarCity's pricing is still within the range of the EPC pricing."
-"No doubt we are in the upper end of the range. Not that I have an ego -- but we're the Mercedes-Benz; we're not the little Mickey Mouse car. I'm not going to be pricing at the average; I am going to be pricing on the upper end."
-"Look at the turnover rate in this industry. If you had a choice of buying a system -- one from Joe Schmoe who may not even be here next year or from a company that has big infrastructure, a large [number of] employees, who has a long-term vision -- who are you going to buy it from? Wouldn't you pay more for that one? So to say that we have to price at the average -- that statement is wrong."
-"But we are not pricing above the range. Take the average -- we are pricing within one standard deviation of the range -- but it is one standard deviation of the range of the EPC prices. That's key. [...] It's annoying because we're held to a different standard than others because people just think of us as an EPC. But we're not an EPC; we're a fully integrated company. But even within EPC, we're still pricing in the range."
Back to the subpoena itself:
-"The treasury came up with guidance. Since guidance has come up, we started pricing at their guidance. In fact, we priced below their guidance. They recently came out with guidance again. We're now adjusting and will try to price at the guidance again. The subpoena is a broad-based subpoena. It went out to a few companies. It's a documentation request. There are no allegations made."
- Jonathan Bass of SolarCity added, "Bottom line is, we haven't done anything wrong. We're happy to participate in the review. We've provided information as part of it. We haven't been able to discuss it because we've been in a quiet period. But that's the only reason we haven't discussed it."
-"We expect the process to take some time. We're not expecting to see anything probably in the next year. At least that's what we've been told by the lawyers who have gone through many other subpoenas before."
-"They are asking for essentially every single thing for the last six years. We've given them everything for the last six years. And that's what takes time for them to review."
-"Just to be clear -- there are many companies [that are being subpoenaed]."
Politics, nuclear power, Tesla's electric vehicle business, and CPV elicited the most vocal responses. Here are the GTM articles from 2012 that attracted the most comments from our readers:
Candidate Romney’s Energy Plan
Romney accused the Obama administration of having an "unhealthy obsession with green jobs."
Amonix closed its Nevada factory and laid off staff. Concentrating photovoltaics (and my handling of the topic) was a hot topic in this comment thread. Rumors are afoot that we'll hear from Amonix in early 2013.
John Peterson is entitled to his opinion on electric vehicle batteries and EVs. As is our audience -- which voices its opinion about the author.
Nick Butcher rebuts Peterson's claims on the greenness of EVs and engages his readers in this convincing article.
A highly charged and highly technical discussion by our readers on nuclear's safety and necessity on the grid.
Thanks to our lively and intelligent commenters. We value your contribution to this site. Happy New Year.
A barrier to advancing the development of the massive ocean thermal energy conversion (OTEC) resource is its potentially adverse biological impact, but a new DOE-funded study carried out by Makai Ocean Engineering found the biological impact can be minimized.
This is expected to remove a significant regulatory obstacle to permitting pilot projects and clear the way for OTEC developers to move toward building 100-megawatt deep ocean power plants.
OTEC uses the higher temperature of the ocean’s surface water to turn liquefied ammonia, which has a very low boiling point, into a vapor that drives a turbine in the same way steam from water boiled by nuclear energy, fossil fuels or concentrated solar energy drives a turbine to generate electricity.
For a 100-megawatt plant on a floating platform much like a deep water drilling rig, tugboat-sized engines would pump the 25-degree-Celsius surface ocean water into an evaporator that vaporizes the ammonia. The vaporized ammonia then passes through the turbine, thereby compelling it to move, and is recaptured.
Engines then pump cold ocean water of approximately 5 degrees Celsius into a condenser that cools the recaptured ammonia back into a liquid so it can be cycled back to the vaporizer in a closed-loop system.
The potential biological impacts would come from the water discharged into the ocean. It cannot be discharged at the 20-meter-to-40-meter, near- surface, light-permeated depths of the evaporator and condenser where ecosystem-sustaining phytoplankton populations thrive.
The cold water brought up to the condenser from a kilometer below the surface has sources of nutrients in it that could cause a phytoplankton proliferation or an unwanted algal bloom.
The published report on Makai Ocean Engineering’s research, entitled "Modeling the Physical and Biochemical Influence of Ocean Thermal Energy Conversion Plant Discharges" indicates that if the water is returned to a depth of approximately 70 meters, it would not cause an ocean environment perturbation of biological significance.
“This is a significant advance,” explained Makai Senior Ocean Engineer Pat Grandelli. “The first unknown that affects OTEC’s economic feasibility is the ability to get a permit. The National Oceanic and Atmospheric Administration [NOAA] is the licensor of OTEC plants, but has no regulations in place right now. The [agency doesn't] even have an application form.”
Permitting is “a key hurdle for OTEC,” Grandelli said, because small startup companies don’t have “the deep pockets” to get through a long and rigorous application process.
Because Makai Ocean Engineering worked closely with NOAA on its research, Grandelli suggested, the regulatory agency is now in a position to more readily approve OTEC applicants with biologically non-impactful water discharge designs.
“From a practical engineering standpoint, it makes the design of a real-world OTEC plant possible,” Grandelli said. Now, he explained, design engineers know to plan for a 100-megawatt OTEC plant’s nine-meter-diameter water discharge pipe to go approximately 70 meters into the ocean.
OTEC’s potential to provide baseload power is immense, Grandelli said, perhaps ten or even 100 times that of wave power. He cited a standard engineering textbook calculation of eight times 10^21 potential British Thermal Units (BTUs) in the world’s oceans between 20 degrees north latitude and 20 degrees south latitude, where there is the requisite 20-degrees-Celsius temperature gradient.
Makai Ocean Engineering is working with Lockheed Martin (NYSE:LMT) on a kilowatt-sized demonstration project on Hawaii’s Oahu Island and on the design of a 10-megawatt project.
A 100-megawatt floating OTEC platform, Grandelli said, would resemble a moored, deep water oil platform and be “more narrow and deep, like a barge.” Such a power plant would require a number of tugboat-sized engines, each pumping 750 metric tons of ocean water per second.
French state entity DCNS Group is moving ahead with plans for a 10-megawatt project in the Caribbean, off Martinique. OTEC International, backed by the Abell Foundation, is working on plans for a 1-megawatt pilot project in conjunction with the state of Hawaii.
Greentech Media CEO Scott Clavenna talks with Herman Trabish, GTM's editor covering the wind market, about what happened in 2012 and how the wind market will take shape in 2013.
It is the best of times and the worst of times for certain: the PTC is about to expire in the U.S., while Chinese suppliers saw profits erode by over 90 percent this year. In the meantime, wind markets are heating up in Mexico, Brazil, Eastern Europe and India. Offshore wind remains a wildcard in the U.S. and continues to flourish in Europe.
Regardless, 2013 will be rough one, characterized by transitions in every area of the market, from markets to suppliers and the continued development of innovative technologies to drive down costs and make wind competitive with fossil fuel around the world.
Our weekly podcasts let you hear from GTM research analysts, editors, reporters and the occasional special guest. Stay tuned and thanks for listening.
Subscribe to the podcast series through iTunes. Click here to visit the iTunes store.
The millionth First Solar (FSLR) solar module was installed in October at the 550-megawatt (AC) Topaz Solar Farm owned by MidAmerican Solar. When complete, the largest PV power plant in the world will field 9 million panels across thousands of acres on California's Carrizo Plains. Construction began less than one year ago. Expected to be complete in early 2015, PG&E will purchase the electricity from the Topaz project under a PPA. The solar farm was not the recipient of a loan guarantee.
Here's a chart of the top ten U.S. PV power plants under construction in the U.S.:
Source: Utility PV Market Tracker
Check out the GTM Research Utility PV Market Tracker for much more information on utility-scale solar deployments in the U.S.
The findings repeatedly show that people don’t really know much about it at all, but when given a little information, they generally like the idea of a more intelligent electrical grid.
“In summary, we’ve found that once consumers are educated about smart grid, they are supportive of it,” Patty Durand, executive director of SGCC, said in a statement. “So the opportunity to further engage with our consumers only gets bigger. Armed with research, facts, figures, knowledge and a vision, industry can continue to educate its customers.”
The organization concluded that 2013 is ripe for customer outreach. Utilities, which increasingly have chief customer officers, would argue that education is going on all of the time. But research shows there’s still a long way to go, and that some of the messages might not be the right ones.
Here are six key points the SGCC found in its research in 2012:
Many non-financial benefits of smart grid upgrades are as compelling to consumers as those that can save consumers money. Besides, a smarter grid, in and of itself, is not necessarily a money-saver for the average person.
Consumers see some smart grid benefits that they consider to be worth paying more for -- such as outage restoration after storms like Hurricane Sandy. Customers are interested in better outage management, but there are also other services they’d be willing to pay more for, according to SGCC, including access to renewables and distributed generation, better usage information and more pricing options.
More than half of consumers found time-of-use pricing and peak time rebates appealing. As noted above, different pricing options aren’t a bad thing if people can choose their plan. Whether it’s to save money or help with reliability, there are different drivers for different consumers. From cell phones to cable packages, people shop around all the time to find the right deal; they’re willing to do it with energy too.
The better they understand it, the more consumers support smart grid and smart meters. A little education goes a long way, and it doesn’t have to be about saving money (see #1).
Low-income energy consumers are less aware of electricity grid modernization technology than the general population, but they find its benefits compelling nonetheless. There is a lot of misunderstanding and misinformation about how the smart grid and smart meters could affect low-income and elderly customers. There is research that shows both groups also benefit -- sometimes more than the general population -- from a smarter grid, which can make it easier to put programs such as pre-pay in place.
Consumers are interested in various smart-grid-enabled pricing programs and services and are increasingly likely to use social media to access energy information. Consumer awareness has barely shifted in 2012, with about half of all people still completely unaware of the term "smart grid." Maybe that doesn’t matter. Smart grid, as a term, is nebulous anyway. The better question is: are people happy with their utility? That means they are not just happy with their electric service, but also happy with how they can interact with the utility, which increasingly includes online services and social media access.
“The modules all met the same basic safety requirement yet performance was different from one manufacturer to another," according to Intertek Group testing services Regional VP Sunny Rai.
Performance stakes are high, Rai said, so “what banks, developers and manufacturers want to prove is very similar.” Manufacturers want to prove their product provides the promised return on investment (ROI). Banks and developers want to verify they will get the promised ROI.
To do this, Intertek developed its bankability testing. “Bankability is all about performance and ROI,” Rai said.
“The National Electrical Code requires products to be certified safe by a nationally recognized testing laboratory,” Rai said. “UL 1703 is the U.S. safety standard for solar modules.”
Safety testing of a solar module has two parts, Rai said: construction evaluation and actual testing.
“Construction evaluation verifies the product is built to meet the standard, including evaluation of its components, the junction box, back sheet, cells, grounding methods, connectors and wires.” It also includes making certain the components are properly certified and are used properly, secured in place and spaced properly, properly labeled, and so on.
“Once we finish the construction evaluation,” Rai said, “we come up with a plan to verify the module’s compliance with the testing part of the standard."
Tests of different solar modules can vary slightly but are similar “because solar modules are used in similar places and face the same things, like light and rain and wind and snow,” Rai said.
“Because they are expected to be used outdoors for twenty to 25 years, they are subjected to certain tests that we refer to as accelerated aging tests. This is done in conditioning chambers,” Rai said. A set of modules are subjected to “standard test conditions (STC) of 25 degrees C and a perfect one sun light exposure, which is the equivalent of 1,000 watts per square meter of sunlight exposure, from a solar simulator.”
The tested power output after that, Rai said, becomes that module’s rated output.
The set of modules is then divided into three groups. One is “put through the accelerated aging test with temperatures from minus 40 degrees C to plus 85 degrees C in a six-hour cycle over 1,000 cycles.”
Another set is subjected to similar temperatures and a similar rate of change but with 85 percent humidity, “so you are not just heating and cooling it, you are freezing the humidity onto the module, thawing it, heating it, and cooling it back down.”
A third test, not required by the UL standard but required by the IEC standard, Rai said, “is what we call a damp heat test. The module is under heat of 85 degrees C with 85 percent humidity for 1,000 hours non-stop -- a constant damp heat.”
The safety standards don’t require monitoring the modules’ output during these procedures.
“This is where we transition from a safety test to a bankability test. We are monitoring the modules to see how the degradation caused by the temperature and the humidity impacts performance,” Rai explained.
The tests are the same, but output is monitored more closely. “For bankability testing, we don’t necessarily only test for 1,000 hours. We test for 200 hours, pull it out, see what the output degradation is, put it back for another 200 hours and, in some cases, we continue until the output of the module drops below a certain level pre-agreed with the manufacturer or whoever asks for the test.”
Testing can last for up to 2,000 hours. “We have observed that a product’s degradation is accelerated in the first 500 to 600 hours,” Rai said. After that, “the degradation is very slow. In most cases, we stop between 1,500 hours and 2,000 hours.”
The correlation between the number of hours tested and the years on a roof “has still not been done,” Rai said. “NREL has a PV Quality Assurance Task Force that is looking at that. There are not yet enough installed years to establish that correlation.”
Intertek’s bankability testing can include other procedures or time frames. “It is targeted to a specific type of installation and modified based on what we are trying to prove or determine. Some buyers or manufacturers want to create a worst-case scenario.”
Each test, Rai said, takes "from 40 to 45 days to complete. You are looking at over six months for testing and, in between, you are doing other testing.”
Testing to UL and IEC standards “used to cost $120,000 to $130,000,” Rai said. “Now it is more like $70,000 to $80,000.”
The price drop, he explained, is because there are fewer new products and “a significant capacity for doing the tests, based on the demand of two years ago.” Smaller labs, he said, “are exiting the business. Larger labs are consolidating. Change is as considerable on the testing side as on the manufacturing side.”
The cost for bankability testing is “similar to the safety standard test,” Rai said, though it could be as low as $10,000 or $15,000 if we are doing a very basic test or trying to test a very specific type of function.”
This is the second article in a series on module testing procedures. See part one here.
Things are a little different down in Texas. The Lone Star State marches to the beat of its own drummer in many ways.
As the most deregulated electricity market in the U.S., retailers in Texas have to fight to win and keep customers. Two of the state’s largest retail electricity providers, Reliant Energy and TXU Energy, launched new smart thermostat programs this past summer to help customers manage their summer AC bills. As Jeff St. John noted at the time, “If it helps the state beat summer peak loads without sky-high power costs or brownouts, all the better.”
While Reliant Energy employed EcoFactor, TXU used Comverge’s platform for its iThermostat program. For both utilities, the focus on consumer-facing platforms has been a relative success.
TXU reported more than 100,000 downloads of its smartphone app to-date. About 60,000 of those came in the first year of the program (when only an iPhone app was available), with another 40,000 in the last five months of this year, which also had an Android offering.
TXU and Reliant are also seeing hundreds of thousands of customers using at least one of their products, whether a smartphone app, email or text bill alert or web portal, to better understand their usage.
The most popular tools include alerts (text or email) when bills get high and weekly email reports with energy use.
For utilities in other states, Texas is worth keeping an eye on in 2013 and beyond. The retailers can even show regulated, investor-owned utilities what kinds of programs that customers want.
If nothing else, many utilities that are deploying smart meters (or not) could take a page out of Texas retailers’ books when it comes to website design.
The websites are bright, clean, and most importantly, customer-focused. On Reliant's site, there are images of people on their smartphones, playing with their Nest thermostats. TXU shows off its iPhone app on its residential page and touts its iThermostat platform.
In 2011, we questioned how competitive Texas really was. As we head into 2013, we’re happy to say that competition is revealing different offerings, from smartphone apps to various smart thermostat programs that are far more awesome than your Grandma’s old load-control programs.
Of course, TXU and Reliant, while large, are just two of many retailers in Texas. We expect to see the proliferation of smartphone apps not only across Texas, but also across the U.S. in 2013.
The United States pretty much invented the term “demand response” to describe the business of turning down big power loads to help the grid avoid peak demand problems like blackouts. Today, of course, the term has expanded to include everything from energy-smart homes and commercial buildings to energy storage -- but the majority of the business remains in the big industrial and commercial sector, and in the United States.
Even so, we’re starting to see other parts of the world turn to demand response to help manage everything from grid instability and congestion to solar and wind power integration, albeit slowly. Outside the 40 gigawatts or so in the U.S., the second biggest market for DR would probably be the U.K., where the Short Term Operating Reserve (STOR) program has a little more than 800 megawatts, being served by a variety of companies including aggregators Flexitricity, a U.K. company launched in 2008, and EnerNOC, the U.S.’ biggest demand response company (here’s a full list of companies in the space).
Another new entrant is KiWi Power, which since 2009 has grabbed a significant share of the country’s available DR market -- about 100 megawatts, co-founder and director Ziko Abram told me in an interview this week. The London-based startup is backed by investors including Better Place backer Idan Ofer, and has raised an undisclosed amount of money, though Abram described it in the single-digit millions of dollars range.
With that, KiWi has built a demand response platform from soup to nuts -- including everything from GPRS-connected smart meters and load control devices, to a back-end system that manages all of it in real time, he said.
But perhaps more importantly, KiWi offers its customers a low-risk deal on the financial side, said Abram. The company’s DR services include a commitment to finance the installation, as well as guarantee that the customer won’t have to pay any penalties for missing a utility response call, and installation, he said.
“We tell the clients, we’re getting paid one dollar, you get X, and we get Y -- and we get our payment back in demand response payments,” he said. Abram didn’t get into details about how a startup with limited capital was managing to finance such deals upfront, though he did say that the company’s installations were capable of paying themselves back in a matter of months.
KiWi’s task, as with other demand response providers, is to turn down lights, chillers and fans, pumps, motors and other power-hungry gear on utility command, whether that’s a phone call or via new automated technologies like OpenADR. Current clients include a hospital, a hotel chain, and the distribution centers of Sainsbury’s, a big U.K. grocery chain, he said.
Like EnerNOC and other big DR aggregators, KiWi also taps generators at hospitals, data centers and other sites with backup power. The trick is to shift demand from peak times to off-peak times, he noted. The company has put together a list of ways that DR can pay for itself in cases like these, like making sure your quarterly tests of the backup generator happen to occur at the 5 p.m. afternoon peak, rather than at the middle of the night, he said.
There’s little doubt that the U.K. needs to grow its ability to turn down power for grid stability. Tightening regulations on coal-fired power plants are driving a shortfall in reserve margins, or the amount of generation needed for peaks and other emergencies, from about 14 percent this year down to about 4 percent by 2015. (Most other markets have seen less pressure, as power demand has dropped along with economic activity, though Texas could be facing a shortfall like the U.K.’s in coming years.)
The U.K.’s STOR program also requires participants to respond in twenty minutes, which is faster than most of the markets operating in the United States today. But the push toward automation is going to make things faster still, Abram said. Frequency regulation services require responses in minutes or seconds, and KiWi is working on delivering that speed of response from its current deployments, he said.
Already, about 95 percent of the company’s clients have automated their DR responses, so that they, or KiWi, can respond within minutes, he said. The cloud-based service can be managed by the customer or by KiWi itself. That move to remote building energy management is one also being followed by industry giants like Schneider Electric and Honeywell and startups like Blue Pillar, Viridity Energy and BuildingIQ, to name a few.
In the long run, KiWi sees itself exporting its business to other markets, including the United States, Abram said. The startup is working on pilot projects in other European countries, he said, though he wouldn't provide more details.
ClearEdge Power of Hillsboro, Oregon, a manufacturer of proton exchange membrane (PEM) fuel cells, is acquiring fuel cell industry veteran UTC Power.
UTC Power is a maker of large-scale phosphoric acid fuel cells (PAFCs), although the firm also has experience with PEM, alkaline fuel cells (AFCs), solid oxide fuel cells (SOFCs), and molten carbonate fuel cells (MCFCs).
UTC Power has a long history, but it's a tiny piece of the $58 billion aerospace-technology conglomerate UTC (NYSE: UTX). Some sources report annual revenue of $40 million for the fuel cell unit, but UTC Power's revenue is not broken out separately. The firm "currently has approximately 380 employees and they are all part of this acquisition, which covers both the stationary and transportation businesses," according to a UTC spokesperson in an email today.
ClearEdge has raised just north of $100 million in VC funding since its inception in 2006 and has fewer employees and presumably less revenue than UTC. Details of the terms or structure of the acquisition were not disclosed. Neal Starling, ClearEdge Senior VP of Sales and Marketing, would not comment on the terms of the deal, but did say, "This acquisition will help solidify our position as a leading provider of cost-effective, clean, continuous, distributed power solutions."
Kohlberg Ventures is an investor in ClearEdge -- as well as Applied Ventures, the investment arm of Applied Materials, Big Basin Partners, and Southern California Gas Company.
The acquisition extends ClearEdge's power range, courtesy of the UTC 400-kilowatt fuel cell. The acquisition also creates in ClearEdge somewhat of a fuel cell industry powerhouse.
ClearEdge's core product is a modular PEM going after combined heat and power (CHP) applications at hotels, multi-tenant buildings and schools with power ranging from five to 200 kilowatts. ClearEdge claims its fuel cell can reduce CO2 emissions by up to 40 percent, along with producing "negligible" NOx and SOx. The fuel cell runs on natural gas, propane, or methane and can export excess heat for hot water, forced hot air, or hot-water cleaning. Other players in the small stationary fuel cell space include Ceramic Fuel Cells, Panasonic, and Ceres Power.
When last we checked, a 5-kilowatt ClearEdge unit had a $56,000 list price and an installation cost ranging from $10,000 to $20,000. There is a $15,000 investment tax credit. California has a Self Generation Incentive Program (SGIP) that can return $12,500, more if biogas is employed. There is the potential to exploit the SGIP for another 20 percent if the vendor is a California supplier (the approved list is currently limited to Bloom, FlexEnergy, Calgen, and Stem). New York, New Jersey, and Connecticut also have aggressive state incentive programs.
According to an earlier interview, in a 20-year light commercial application, factoring in the cost of the unit plus the gas, maintenance, replacement parts, taxes, and installation, power ends up at $0.091 per kilowatt-hour with the CleanEdge fuel cell. Starling verified this number today.
ClearEdge might be able to outperform batteries and other fuel cells, but the problem is that the real competition is the grid and diesel gen-sets. And few if any fuel cell vendors have proven that they can go head-to-head with those incumbent technologies on a per-kilowatt-hour basis. Fuel cells can be distributed and do have less emissions. Natural gas is cheap. But for fuel cells dependent on the natural gas grid, there's the downside of volatile prices and the sometimes less-than-green processes used to extract natural gas.
Fuel cells have benefited from state and federal subsidies, or in the case of Bloom -- Delaware ratepayer bill subsidies. The justification for renewable energy subsidies is often debated in these pages. But in the case of fuel cells, even after incentives, the fuel cell is expensive compared to the grid or to a diesel gen-set.
What happens to ClearEdge, UTC and the fuel cell industry when those subsidies subside?
A renewed emphasis on solar module quality raises the question of how quality is evaluated.
Module manufacturers are only required to meet the UL and or IEC safety standard. “Everything else is imposed by developers and financial institutions that require not only long-term performance guarantees, but also reliability guarantees.”
Renewable Energy Testing Center (RETC) Engineering and Operations Senior VP Cherif Kedir explained his company’s procedures.
“We have different programs,” Kedir said, “depending on what [companies] want to accomplish.”
The banks, Kedir explained, are concerned about the return on their investment. “If a project is supposed to turn profitable after seven years, they want to make sure that is going to happen after seven years and not eight or nine years.”
Developers are more interested in the shorter term, he said, “unless they are planning on holding the development.”
But between the two, “they end up getting the whole gamut of tests, because each has slightly different needs and they don’t want to concede them.”
Once the manufacturer, the developer and the financing institution develop a working relationship, Kedir added, there is less demand for testing.
“The basic performance validation we do is modeled against the IEC 61853 standard,” Kedir said. “The next level is the reliability tests.”
Performance testing ensures that the panels a manufacturer ships perform according to their claims. An RETC report affirms that the product, Kedir said, “will perform in the field the way it is expected to.”
RETC performance tests measure how much power the modules will deliver under different light and temperature conditions. “We test at 15 degrees C, 25 degrees C, and 75 degrees C. and we measure at between 100 watts and 1,100 watts per square meter.”
The last part of performance testing is for light-induced degradation (LID). “We take a set of panels, measure the power output at standard test conditions [STC] of 25 degrees C and 1,000 watts per square meter, and then light-soak them outdoors or in simulated light and keep measuring until the power output stabilizes.”
Knowing that initial degradation, Kedir said, is important because it could be anywhere from 0.6 percent or 0.8 percent to as high as 5 percent or 6 percent. “Then they stabilize and the modules will degrade at maybe half a percent every year or so.”
RETC’s reliability protocol is called Thresher Test Flow. It is a model for a formal reliability testing protocol being designed by an NREL-led task force of which Kedir is a member. Thresher Test Flow includes extended chamber tests for thermal cycling, humidity freeze, damp heat, and biased damp heat.
“The standard IE certification requires 1,000 hours of damp heat chamber exposure. That’s 85 percent humidity at 85 degrees C. It is supposed to simulate 25 years of operation. But in reality, what we are finding is that under operation some panels have shown unexpectedly higher degradations,” Kedir said.
RETC’s reliability tests use established IEC test procedures for performance and safety, with extended exposure times.
RETC has found that some products that pass at 1,000 hours often fail at 1,100 hours or 1,200 hours. “If you add just 10 percent more stress, they may fail dramatically,” Kedir said. “A lot of our customers are opting to go beyond the 1,000 hours to 1,500 hours, 2,000 hours; some go as high as 3,000 hours. Once the product fails, we help them figure out what failed. The manufacturers then go and improve their products in those areas.”
"We take a lot of the basic tests and we apply [the conditions for] two times or three times longer," Kedir said.
For damp heat, the module is tested at 85 degrees C and 85 percent humidity for 1,000 or more hours. “Then we do another test, the PID [potential induced degradation], which is very stringent," Kedir said. “It is the same test conditions, but with a system voltage bias added.” It is performed for between 100 hours and 2,000 hours.
“What a lot of developers and banks are saying,” Kedir explained, “is that the basic certifications are a manufacturer’s price of entry into the market. But it is not the gate of entry into purchase agreements. In order to be considered, the modules have to undergo additional tests. They have to prove they are better than the rest.”
With more rigorous testing, Kedir said, “we are finding issues with encapsulation, back sheets, and components such as junction boxes and connectors and cables. We are finding issues with diodes. A lot of things are showing up that before didn’t register when everybody was passing, but performance in the field was not up to par.”
Warranties and other protections make it possible for developers to recoup losses, Kedir said, but “they don’t want to wait until they see a shortfall in their production and go and seek remedies. They want to make sure they take care of it upfront, before they invest in these products.”
From comparative testing of “different products from different manufacturers tested at the same time,” Kedir said, “you can actually see whose product is better.” The results have impressed developers. “They said now they can’t sleep at night because they have some of those potentially bad modules in their developments.”
Interviews with Intertek and PV Evolution Labs are scheduled for future articles in this series.
Last year, we brought together our love of the holiday season and our passion for cleantech by answering a burning question: Should Clark Griswold have switched to LED Christmas lights?
The answer is not cut-and-dried. Even with LED prices falling 24 percent in the past two years, this decline has not trickled down to the Christmas light market, where prices are pretty much the same, and in some cases, are even higher than last year in the fickle online marketplace.
Many of us are like Clark, using the same tangle of lights until they give out completely, even if professionally we tout the long-term benefits of moving to LEDs. This year, we want to know, who has invested in LED holiday lights? And if you missed it last year, read on below to find out whether Griswold would be wise to make the switch.
***Have you switched to LED holiday lights?
Clark Griswold has a lot on his plate. After all, planning the perfect family Christmas is nearly impossible, as he finds out in what many argue is the best Christmas movie of all time: National Lampoon’s Christmas Vacation.
Hats off to the Griswolds for getting a real tree instead of using a fake one, as a real Christmas tree is a more sustainable option than a plastic tree. But why stop there? With his bonus check already spent before it arrives, should Clark Griswold consider switching to LED Christmas lights (assuming it’s not still 1985) to stop his electric meter from spinning out of control?
Pretending that Clark doesn’t already have a tangle of Christmas lights in his garage, let’s say he’s starting from scratch. In that case, he’ll need 250 strands of 100-bulb strings of lights. General Electric makes both LED and classic incandescent Christmas lights, so in the interest of making a direct comparison, we’ll use those.
Clark seems like the kind of guy who would shop on Amazon, where you can get General Electric micro LED lights in 100-bulb strands for about $16 each. Old-fashioned lights run about $10 a strand for the same amount of bulbs. Overall, that’s $4,000 in LED Christmas lights, compared to $2,500 for traditional technology. No wonder he doesn’t have enough money to cover the down payment for the pool.
The good news for Clark's son Rusty is that with LED lights, even if one of the bulbs is out, the rest of the strand will still work, said Jeff Cloud, lighting program manager of GE Lighting. The popularity of LEDs has been growing year over year, with GE seeing about 30 percent growth in sales each year and LEDs claiming about half of the market.
Although not having to toss an entire strand when one light goes out is tempting, the real appeal of LED lights is the clean, bright light for 80 percent less energy. A traditional strand of GE lights uses about 40.8 watts of energy, compared to 8 watts for the LEDs.
The average home runs their lights about six hours a day for six weeks, according to market research by GE. (Apparently, many people start decorating just after Veterans Day. By next year, it will likely start around Halloween.)
Obviously, Clark Griswold wasn’t so organized, so let’s assume the house is lit up for two weeks -- but for twelve hours a day. After all, this is a 'go big or go home' project.
If Clark has 250 strands of regular incandescent lights running for 168 hours during the holiday season, it will run him about $126 in utility bills, assuming he’s paying about 7.4 cents per kWh living in the suburbs of Chicago. If Clark paid the national average of 11.5 cents per kWh, he’d be out nearly $200.
The switch to LEDs, however, would cost about $25 at 7.4 cents per kilowatt-hour. However, the original cost was still $1,500 more for the strands of LEDs. For the average Christmas reveler, who doesn’t wait until just before the crazy in-laws arrive to hang the Christmas lights and pays the national average for electricity, five strands of LEDs would cost about $1.18 for the season, compared to about $6 for incandescents. The payback would still take years, but hey, at least you wouldn’t have to toss an entire string when a single bulb blows out.
Clark’s real problem, however, is not the kilowatt-hours added to the bill, but the ampage. All of those incandescent lights would pull about 85 amps, more than most houses would have on a single circuit. By comparison, Cloud said just one breaker could easily accommodate the LEDs.
As the costs of LEDs continue to come down, the energy savings will keep looking better. But as for Clark Griswold, we don’t really want him to ditch classic Christmas lights. “We’d have nothing to laugh at,” Cloud said.
While the nation has been focused on new sources of natural gas and shale oil, few noticed the slow decline of an older energy source: nuclear power. Today, commercial nuclear power is struggling to stay in the game.
The power markets are hammering the nation's nukes. Over a decade ago, several regions decided to create Regional Transmission Organizations (or Independent System Operators) and use the market to set power prices. Today, North America has ten independent RTOs/ISOs, where wholesale power is auctioned every few minutes.
Power auctions are about energy, not power plants. Auctions don't care how power plants produce energy; they only care about the bid. The primary focus is on the last bid that clears the auction; it sets the price for all participants. That's why the last bid is called the market-clearing price.
The difference between the market-clearing price and the generator's production cost is the gross margin. The last bid is technically on the margin and it earns little to no gross margin. But every dollar above production costs contributes to the generator's fixed costs.
Most nuclear units are "must-run plants" and they will produce power even if market-clearing prices fall below production costs. Recently, some nuclear plants have been booking negative gross margins. They hope they can make up losses with subsequent gains and average a gross margin.
But a gross margin is not always enough. Nuclear units must pay all their bills and leave something for shareholders. Recently, some nuclear units have been achieving modest gross margins, but without enough left to pay all the bills or achieve any earnings.
Just ask Dominion Resources. The company recently announced that its Wisconsin nuclear plant would be retired twenty years early. Dominion claims it sought buyers for its Kewaunee Power Station. None could be found. It appears that not only did Dominion conclude that its nuclear plant would remain unprofitable, but that Dominion's competitors also concurred.
It turns out that Kewaunee is located near NextEra Energy's Point Beach Nuclear Plant. Point Beach operates in the same market and shares a similar design. It would seem that Point Beach must be as economically challenged as Kewaunee.
It's likely because the nation's largest fleet of nuclear power plants is operating nearby and they are financially challenged. Exelon owns ten generating stations and seventeen reactors, which are located in Illinois, Pennsylvania and New Jersey. As a group, these power plants are struggling to provide their owners with earnings to the point where Exelon's management warned shareholders they might be forced to cut dividends.
A Different Picture in Regulated States, But Challenges Remain
Nuclear plants operating in regulated states are faring better. While consumers' demand for electric power is down, nuclear power plants are safely embedded in states' rate bases. Owners of regulated nuclear assets are protected, up to a point.
Two nuclear power stations are finding their state regulators are losing patience. One is Duke Energy's Crystal River Nuclear Generating Plant operating near Tampa, Florida. The other is Edison International's San Onofre Nuclear Generating Station operating in Southern California.
Both stations are experiencing unusual and costly maintenance expenses. Crystal River's containment repairs could exceed $2 billion, a price that state regulators may find excessive.
San Onofre also incurred unexpected and costly maintenance challenges. But San Onofre's 2,350-megawatt capacity is a critical resource for Southern California, and without that resource, California could see rolling blackouts. Nevertheless, San Onofre's problems provide new opportunities for opposition groups to pressure regulators and political leaders. San Onofre could survive, but it is at risk of early retirement.
Entergy is at war with two states at the same time. Vermont wants Vermont Yankee Nuclear Power Station to retire twenty years early. Politicians and regulators are fighting with everything they have to prevent Entergy from continuing nuclear operations.
The State of New York wants Entergy's Indian Point to retire twenty years early and it is vowing a fight to prevent further operations. Governor Cuomo believes the state can import enough power from Canada to provide it with enough power to assure regional reliability. But in the case of New York City, existing transmission lines are inadequate. New lines will be needed to deliver Canadian power to the energy-hungry city.
New Jersey regulators already negotiated the early retirement of Exelon's Oyster Creek Nuclear Generating Station. Oyster Creek is 630-megawatt facility and it will go on the scrap heap ten years early in 2019.
A pattern is developing. It may take a few years, but it appears small nuclear plants will face increasing pressure to retire early. They cannot compete, particularly in soft markets. Some plants will find their costs consistently exceed any benefits they earn and their owners will be forced to retire and dismember plants.
Natural gas may replace retiring nuclear plants. New turbine technologies and low fuel costs allow some gas turbines to outperform nuclear power plants. But it is unlikely fuel prices will remain low for the next 60 years, which is the design life of a new nuclear unit.
Glenn Williams worked in the nuclear power industry for over 20 years. At the time of publication, he had no position in any of the stocks mentioned.
ASAT, based in Calgary, specializes in managing the data coming off of distribution substations and using that for operation, maintenance and asset management. The company’s server helps integrate intelligent control devices with substation computers.
ASAT had been working with various competitors of Alstom, including ABB, General Electric, SEL and Siemens. The company had a reseller agreement with GE. ASAT had also been working with Areva, which Alstom bought part of in 2010 for just over $1.9 billion (Schneider Electric bought the other portion of the company). Alstom also has an alliance with S&C Electric.
“Companies like ASAT are becoming more important as utilities continue to move beyond legacy communications to more standards-based communications. The solutions provided by these companies ensure compatibility for legacy as well as future equipment deployments while improving the transmission, management, and authorized presentment of data from intelligent electronic devices to various utility silos,” said Ben Kellison, smart grid analyst at GTM Research.
Earlier this year, Alstom partnered with Cisco to integrate the latter’s end-to-end IP network for connecting intelligent devices on the smart grid.
Alstom is embedding Cisco’s IPv6-capable platform in its substation gear. Cisco has various smart grid partners, including Subnet Solutions, which offers substation automation solutions similar to ASAT, according to Kellison. Cisco also told Greentech Media it is looking at launching new substation products beyond its core routers.
“This acquisition is a great opportunity for Alstom Grid to help accelerate the development of ASAT business while broadening our smart grid ready offerings to the market,” Hervé Amossé, vice president of Alstom Grid Substation Automation Solutions, said in a statement.
Alstom’s purchase of ASAT will enhance its U.S. presence and solidifies its interest in gaining a foothold in the substation market.
Demand response -- the business of turning down electricity use at homes, offices, factories, and other such sources of demand, to help manage grid needs -- has changed a lot over the past few years. What grew up as a specialized, utility-focused enterprise has, with the growth of the smart grid, expanded to include all kinds of new technologies and business models.
That means smart-meter-connected homes, as well as smart building technologies that shave and shift energy consumption for commercial and industrial clients. The purpose of demand management has also expanded, from the hour- or day-ahead power-down calls of the past to fast-reacting, automated systems to help balance grid frequency, ease congestion on specific power lines, or even mitigate the ups and downs of wind and solar power.
So what are the top developments in this strangely named, sprawling line of business? Here are a few takeaways from 2012:
1) It’s been a tumultuous year for the U.S. demand response industry, but it looks like the tumult has ended up in the industry’s favor. The United States is the core market for demand response, with some 40 gigawatts of capacity -- much of it conducted via markets set up by Mid-Atlantic grid operator PJM and similar grid entities in California, New England, Texas and the Midwest.
The Federal Energy Regulatory Commission (FERC) regulates these ISOs and RTOs, and back in March 2011, it issued FERC Order 745, which essentially requires demand response assets to be paid on par with the generators that supply grid power. This year, however, a dispute between PJM and big U.S. demand response provider EnerNOC threw into question the implementation of that order in the country’s biggest DR market -- with a commensurate effect on EnerNOC’s stock price.
That dispute was settled this summer with FERC ruling largely in demand response’s favor -- and that’s helped ease the uncertainty that has dogged the industry. At the same time, we’ve seen certain markets like Texas turn to demand response to mitigate a lack of new generation capacity that’s putting pressure on power reserves -- one way that demand response can help reduce the need for peak power plants.
Not all companies managed to navigate the challenging climate over the past year unscathed. Comverge, which had been the other publicly traded demand response provider in competition with EnerNOC in the U.S. market, was bought by private equity firm H.I.G. Capital for $49 million, a fraction of the value it had once commanded on the public markets.
2) Demand response markets are opening up in other parts of the globe as well -- but each market has its own priorities and special characteristics that need tending to. Europe doesn’t have big afternoon peak loads driven by air conditioning to contend with -- instead, it’s mainly trying to shape big industrial loads to manage its peak problems. And abundant pumped hydroelectric energy storage capacity in Scandinavia does provide much of the continent’s peaking needs.
But individual countries in Europe are still facing some significant challenges. Not only are countries like the U.K., Germany and the Netherlands struggling to keep up with their needs for peak generation capacity, they’ve also got a large and growing shares of intermittent wind and solar power making up that mix. Some of Europe’s biggest countries, including Germany, have also pledged to phase out nuclear power over the course of the decade, which will only increase the need for demand response.
In Japan, of course, the nuclear plants have been shut down ever since the Fukushima disaster, which has left the country in a major power crisis. To meet it, Japan is both importing lots of natural gas to generate power, and engaging in a major push for new wind and solar power, along with energy storage, building load controls, and campus-wide microgrid and “smart city” technologies to help out.
Other demand response markets are also emerging in Australia and New Zealand, in South Africa and in the Middle East -- each with its own challenges.
3) Automated demand response is real -- in fact, it’s going to be the new normal. Traditional demand response relies on a whole range of old-fashioned methods, from phone calls to plant managers who crank up generators and turn down factory lines to mitigate peaks, to emails or web portals that inform customers that a peak day is coming and they’d better turn down power. But two-way digital communications and control technologies are at the heart of the new breed of demand response, which can act faster and more reliably – and also open up participation to a whole new range of end users.
The main challenge for fast and automated demand response is integrating all those building-side power controls with the network that currently manages the grid. In the United States, one important standard for doing this, called OpenADR (for automated demand response), has really taken off in the past year. New entrants, including giants such as Schneider Electric and Lockheed Martin, as well as smaller contenders like Stonewater Control Systems, Powerit Solutions and IPKeys, are starting to pose a challenge to incumbent Honeywell, which bought OpenADR server maker Akuacom in 2010 and has since rolled out projects in the U.S., Europe and China. California, as the single biggest market for OpenADR-enabled demand response, will be a critical market to watch on this front.
4) New technologies have opened up new markets for the “negawatts” that demand response can provide. Another critical driver for fast and automated demand response comes from FERC’s Order 755, which should increase the value of fast-reacting energy storage and demand response assets used for frequency regulation, or the critical yet relatively little-known market for power that keeps the grid’s frequency from getting out of whack.
That requires a lot of preparation on the part of both end users and grid operators. For example, we’ve seen companies like Enbala and Viridity Energy launch demand response projects with customers in Pennsylvania that are delivering negawatts of load reduction to frequency regulation markets. PJM, for its part, just announced that it has launched an Order 755-capable upgrade to its demand response management system, in partnership with French power grid giant Alstom, via its acquisition of OpenADR software developer UISOL in 2010.
Another application for demand response that flips the concept on its head is using building resources to absorb extra power. Wind farms are usually oversized to make sure that they can deliver a certain minimum amount of power during calmer days -- but that means that during windy days, they may be producing a lot more energy than the grid needs. We’ve got undertakings ranging from U.S. projects in the Pacific Northwest with EnerNOC and in Hawaii with Honeywell, to projects in Europe using cold storage, plug-in vehicles and other “power sinks” to help manage extra wind power.
5) Smart building technologies and demand response are becoming increasingly intermingled. One challenge for demand response is that relatively few building owners (or occupants) are willing to risk messing with their building’s core functions, like keeping the lights on and offices comfortable, or running factories at top efficiency, just to make some money on a sideline. But as buildings themselves get more energy-efficient, and start installing technology to track and manage that energy use, new vistas for demand response can open up as well.
We’ve seen a host of companies bringing these kinds of building-smart technologies to market, and 2012 saw some significant steps forward for a number of noteworthy competitors on this front. Air conditioning optimization startup BuildingIQ landed a partnership with Schneider Electric and a big project with Las Vegas’ NV Energy, for example. “Virtual power plant” technology startup Viridity Energy raised $15 million from Japan’s Mitsui and expanded its work in the U.S. and abroad. Blue Pillar, a specialist in power management for hospitals and other backup-generator-equipped clients, and Powerit Solutions, which specializes in power sensor and control networks for industrial settings, both raised money as well.
At the same time, we’ve got established energy services giants like Honeywell, Johnson Controls, Schneider, Siemens, Eaton, Emerson, ABB and General Electric all integrating smart building technologies and services in ways that could serve demand response’s needs. Possibilities range from simplifying the process of signing up for and executing demand response via building services platforms like Johnson Controls’ Panoptix or Constellation New Energy’s VirtuWatt platform, to harnessing the capabilities of microgrids, or remotely powered buildings or campuses, which proved their ability during Hurricane Sandy this fall.
We’re seeing the demand response industry recognize that broader energy efficiency is going to be a bigger market in the long run. EnerNOC has built up its building efficiency software and service business to manage more than 200 million square feet of customer real estate, for example.
SolarCity is a distributed energy provider that has grown fast and gone public on the promise of selling consumers cheap electricity.
Since SolarCity (Nasdaq:SCTY) lowered its offering price to $8.00 per share last week, the stock has spent the last few days between $11.00 and $12.00 and is currently trading at $10.66 per share. But to quote CEO Lyndon Rive from an earlier interview, "What matters is what the price is in four years, not what the price is today."
We spoke with Rive today on this, the one-week anniversary of the firm's IPO.
Lyndon Rive on the IPO and IPO process:
-"Once you get used to not sleeping, it's great. It does take a toll, but actually I think it's a very good process -- you get to meet 100 investors in a ten-day period. It's hard to match that."
-"The reason why we ended up pricing at lower than the range was primarily because of the cleantech sector and the scars that investors have had in the cleantech sector. If you peel the onion even further and look in solar, the scars are very deep. They've heard many companies before us say, 'no, no, no -- we're different.' Now SolarCity is really different. But they've heard that before. So, they did not want to take a risk and in order to get them to be interested -- we had to give them a deal which was essentially at a large discount in a low-risk investment with big upside."
-"We wrestled with it. Were we better off to go out or better off to do a private round? [...] The space that we're creating is so new; no one has done it, there are no comparable comps. The feedback from the investors was, 'Come up, let us understand your business over time, and grow with you over the next four years' -- versus coming back in a year and a half or two years later."
-"There is no comparable company. Distributed energy generation is new. Historically, the solar industry has either been in the manufacturing side, in the installation side, or in the financing side. But those are all clearly different vertical businesses. Most of the publicly traded companies are in manufacturing, which hasn't been performing well at all. Margins have been severely compressed."
-"There is no business that's an energy provider or a distributed energy provider. [We had] to educate investors on this -- that we're not an installer, we're not a financier. We sell energy and we create the energy at the place where you need it, and we sell energy at a lower rate than you can get from a utility. It's like saying that a utility company is an installer or a financier. They're going to do all the same stuff we have to do. They have to build up the infrastructure, finance it, and charge for a kilowatt-hour. We do exactly the same stuff."
-"For the longest period, people used to call SolarCity the largest solar installer in the country. Argh. It would bug me. I would grind my teeth when I hear that."
Rive also said, "Installing solar is a means to actually deliver the energy. We're not an installer. We're actually not a financier. Often I hear, 'SolarCity, the solar leasing company.' No -- we sell energy. And financing is just part of the product in order to get energy on the roof."
Rive speaks about the Treasury investigation of 1603 financing, SolarCity's energy efficiency business, and underwater hockey in Part 2, to be published tomorrow.
The year continued with the 50th anniversary of the light-emitting diode (LED) in October and ended in December with yet another Greatest LED.
Despite overcapacity and slim profit margins, Cree (Nasdaq: CREE) and other manufacturers bounced back to confound naysayers and short-sellers. LED streetlights began to seriously climb the S-curve of adoption. And LEDs in lighting are staging a reported 44 percent year-on-year gain, with 9.8 percent growth for LEDs overall.
Here's our 2012 LED Top Ten:
One: The phaseout of the 100-watt incandescent nominally began on New Year’s Day (implementation funding was delayed nine months in a congressional deal). Lower wattages will get axed each year thereafter.
Two: The 50th anniversary of the invention of the modern LED by Nick Holonyak at General Electric was observed in October. Solid-state light emission had been observed by Oleg Losev in Russia in 1927, and by H.J. Round in England as far back as 1907.
Three: Osram announces major progress on silicon substrates in January. Potentially cheaper than sapphire, it appears possible the silicon substrates may be shipped in volume in 2013.
Four: Soraa unstealths in February, revealing a gallium nitride (GaN) substrate LED -- a major achievement by a heavyweight team -- along with questions as to why the firm is only shipping MR-16 lamps.
Six: Cree releases the most efficient production LED yet, the XM-L2, at 186 lumens per watt.
Seven: 3M announces the Advanced Light Bulb to be sold by Walmart. Coming from a major materials company rather than a lighting company, the bulb uses innovative light-pipe technology to tackle the perpetual Edison-bulb problem, namely, that LEDs just don’t like to emit light in all directions.
Eight: Home interiors chain Ikea announces that it will phase out all non-LED lighting products and store lighting by 2016.
Nine: China turns to U.S. suppliers in an official backlash against domestic LED streetlight quality problems.The city of Chongqing, in June, completes China’s largest LED street lamp installation, using 1.9 million Cree LEDs in 20,000 lights on 119 streets. China momentarily claims four of the world’s five largest LED streetlight installations.
Ten: The Osram non-IPO twists in the euro wind. LED investors and founders hoping for a headline exit story will have to wait until 2013. Siemens revised its IPO of Osram into a share conversion and then delayed it repeatedly as the Eurozone struggled.
Few of the LED products, projects, or milestones of 2012 have emerged from a government subsidy or mandate. Contrast that with the solar photovoltaic (PV) market, which lives in terror of plunging off of subsidy cliffs.
We've reported on the antics of solar bounder James McKirdy, age 66, since early 2011. In the years that we've been reporting on him, he's been accused of bilking tens of thousands of dollars from solar panel consumers who have partnered with him or tried to buy McKirdy's mythical solar panels. We have heard from well-meaning realtors, investors, installers -- all who have been on the receiving end of the McKirdy solar scam.
Below is a recent photo of James Archer McKirdy of Off Grid Solar in the arrest records of Florida's Volusia County Corrections Office from a November 27 booking. This arrest is not necessarily connected with McKirdy's solar business -- we're working on getting at those records.
More recently McKirdy has been selling "Tesla Coils." People are buying the Tesla Coils along with these claims:
- McKirdy and Off Grid Solar claim to be using a technology which provides solar panels with better than 50 percent efficiencies. McKirdy has claimed that his solar development company has orders for 850 megawatts of his NXGen solar panels.
- The firm claims that the panels are "not adversely affected by temperature; the operational window is between -300º & +600º Fahrenheit. This makes them highly effective even in extremely hot or cold conditions, since energy is produced at a consistent rate."
- In an article in the Sun Sentinel from March 2010, McKirdy said he received "a $400 million order for panels from a firm developing solar energy farms and has agreements with distributors to help market his product in Tennessee and Texas."
- Earlier this year, we received reports of him promoting his company to PREPA, a utility in Puerto Rico, and to interests in Arizona.
- An Off Grid Solar document includes a list of projects "under development and contract": "At the end of the 2012 year, Off Grid Solar intends to be in a position to bring to market over 800mW [sic] of annual production. This would make OGS the largest completely American owned and operated solar module producer."
- McKirdy has also claimed that DuPont is making the panels for his firm. We've contacted DuPont -- and its Apollo solar subsidiary is not a supplier of product to Off Grid Solar.
The only due diligence McKirdy's victims had to perform was a Google search. Hopefully, this article helps inform potential victims. Do not engage in solar business with Jim McKirdy -- his technical and business claims are suspect.