New England Clean Energy Council

Building enough new solar and wind capacity to meet California’s 33 percent renewables by 2020 mandate will not be easy -- but reliably getting the electricity generated by those resources to the places where it will be consumed may be even tougher. That is the responsibility of the California Independent System Operator Corporation (ISO).

The ISO has just released a five-year strategic plan that lays out what needs to be done in four steps.

First, according to the ISO’s CEO Steve Berberich, “We’ve been working on -- and will continue to work on -- our support of the state’s ambitious energy and environmental goal of 33 percent renewables.” The ISO, Berberich said, has “been doing studies to find out how much capacity we need on the system and how much ramping we will need when the sun doesn’t shine and the wind doesn’t blow.”

It is also working to make sure California has a reliable, cost-effective transmission system with adequate interconnections. Berberich said the ISO hopes to control costs by efficiently interconnecting new transmission with existing lines so as to rationalize development. The newest iteration of the ISO’s annual transmission plan proposes 29 new “reliability-driven transmission projects” at a cost of $647 million. That would add to the state’s $10.5 billion, 545-project transmission buildout, ongoing since 1998. 

Second, Berberich said, is making sure the ISO has enough non-renewable generation. “What we’re going to find with the generation we have now,” he explained, “are three forces acting on it.”

First, traditional generators are going to be selling less electricity as more renewable capacity is added. Second, there will be excess capacity between 2012 and 2017. And third, between 2017 and 2025, about a quarter of the conventional generation will be retired.

Less well known than the 33 percent mandate is California’s requirement that, as of 2017, power plants using coastal and estuary waters for cooling be retrofitted, repowered or retired. The state’s two nuclear plants have until 2024 to do this. This affects 11 natural gas plants providing 12,000 megawatts of capacity on the ISO grid.

“It takes five to seven or more years to develop a generator,” Berberich said. “When you look out to 2017, you don’t have a lot of years left.” To back up renewables, the conventional fleet must be as clean and as little used as possible, Berberich said, “but it has to be there." He added, "we have to act now to keep the capacity on the system.”

The third strategy, Berberich said, is to make sure state agencies, especially the California Public Utilities Commission (CPUC), the California Energy Commission (CEC) and the ISO, can “connect the dots.”

One example of connecting dots is demand response. “If we had a vibrant demand response program here in the state, I would make sure it was in our assumptions. But we don’t,” Berberich said. “It’s up to the CPUC to get it launched, [along with] energy efficiency. And electric cars -- how do we make sure they charge at night as opposed to the middle of the day?” If state agencies don’t "connect the dots" on these issues, the ISO’s only alternative is new capacity, Berberich explained.

Fourth, Berberich said, is collaborating with adjacent balancing areas to take the strengths that each has to offset weaknesses. Giving the ISO access to less costly out-of-state renewables could stimulate a healthy competition. And access to unused out-of-state conventional generation could help balance California’s variable renewables. Both options, he said, “could provide value to the ratepayer.”

Though Berberich stressed that the ISO is building all the capabilities necessary to smooth the addition of variable renewables, it was clear the supply of conventional generation looms large for him. “Assuming marginal load growth as the economy grows,” he said, “and taking out all the once-through cools, except the nuclear units, you have approximately 4,600 megawatts of ramping resources that you need by 2020.”

The flexibility offered by conventional thermal capacity, Berberich said, becomes progressively more vital as the ISO integrates more renewables. “We’ve had a couple of instances where wind has run out 800 megawatts in a half hour,” he said, “and that’s with about 3,500 megawatts of wind on the system. If you triple that, you can triple the run-out. We need to be able to respond to that.”

To reduce dependence on fossil generation, the ISO has introduced a flexible power market operating at sub-hourly intervals with advanced forecasting for wind and solar and in an expanded balancing area, Berberich said.

But the ISO also carries “about 450 megawatts of regulation up and about 350 megawatts of regulation down, and we manage the system on a four-second basis,” he explained. “When you run out 800 megawatts of wind, you exceed the amount of regulation and you get into reserves. When you get into reserves, you have the risk of a reliability issue. That’s with 3,500 megawatts of wind. Let’s say you triple that and you have a run-out of 2,400 megawatts of wind -- you’ve exhausted the regulation and you’ve exhausted all your reserves, as well.”

As the system operator, Berberich said, “we have to deal with asymmetric risk. By that, I mean we can’t afford to have reliability issues on the system. In a perverse way, if we start having reliability issues on the system, that’s the quickest way to derail renewable development. So keeping a reliable system is part and parcel of supporting renewable integration.”

Samsung Heavy Industries just made a 100-million-pound ($158 million) commitment to offshore wind in Scotland, where the harnessing of far-offshore, deeper-water wind was first proven. This investment in the future of offshore wind follows a 100-million-pound commitment from Mitsubishi Power Systems and a 40-million-pound ($63.3 million) commitment from Spanish wind turbine manufacturing giant Gamesa.

With Scotland’s 206-gigawatt offshore resource virtually untapped and the U.K.’s Crown Estate intent on building 30 gigawatts of ocean wind capacity by 2020, Samsung and the other two multinationals are betting that Scotland offers high winds, heavy industry and big returns.

The Crown Estate administers activity in the waters of the U.K.’s wide outer continental shelf. Ostensibly property of the British throne, revenues earned from offshore resources are, in fact, paid to the U.K. Treasury under the supervision of Parliament.

“Scotland has 60 percent of the U.K.’s onshore wind capacity,” explained Scotland Development International (SDI) Manager for Renewable Energy and Low Carbon Technologies Tom Lamb. But the U.K. has had difficulty finding sites for more onshore wind. “The U.K. government needs to develop renewables to meet its Kyoto targets,” Lamb explained, “and without offshore wind, it isn’t going to make it.”

In 2009, Scotland initiated the development of 5,700 megawatts of offshore wind at nine sites within the 12-mile boundary of its territorial waters. In 2010, the Crown Estate announced the development of 4,800 more megawatts in two zones beyond the 12-mile limit off Scotland’s eastern coast in the Firth of Forth.

Lamb noted that Scotland played a major role in the development of the U.K. offshore oil and gas industry in the North Sea during the 1980s and 1990s. He said the retired Beatrice Oil Field off Scotland’s northeastern tip was selected by the Crown Estate to test the feasibility of harvesting far-offshore, deeper-water winds, partly because it was one of the few offshore oil fields connected to the mainland grid. The Beatrice Wind Farm Demonstrator project, consisting of two gird-connected REpower five-megawatt turbines was completed in 2007.

Still operating, the Beatrice turbines have supplied valuable study data on offshore wind installation impacts such as noise, marine life and seabed habitat effects, ocean and migrating bird effects, commercial fishing and shipping interference, and aesthetic reactions.

The success of the Beatrice demonstration, Lamb said, led to the Crown Estate’s Round III offshore ambitions in deeper Atlantic and North Sea waters farther offshore than any previous undertakings.

The Beatrice project also anchored the manufacturing of offshore turbine substructures by Burntisland Fabrications (BiFAB) in Menthil, Fife. SDI and other Scottish development groups are now working to grow the Fife Energy Park near “impoverished areas on brownfield industrial land with quayside access,” Lamb explained. “In Samsung’s first move into European offshore wind,” he added, it will work at the Fife Energy Park “to design and test a seven-megawatt wind turbine already in engineering.”

BiFAB presently employs some 200 to 300 workers in a thriving manufacturing business serving Europe’s rapidly expanding ocean wind sector. Should the Samsung turbine go into production, Lamb said, it is projected to provide up to 500 jobs.

Gamesa’s commitment will lead to a research and development facility near Glasgow where it will work on its next generation of turbines. In doing so, it will be able to call on technical expertise from the U.K.’s only Doctoral Wind Energy Research Center at the University of Strathclyde. Mitsubishi will work on advanced drivetrain design in Edinburgh, calling on experts in renewable energy and fluid power research at the University of Edinburgh. “In both cases,” Lamb said, “we went out and pitched the companies and they came in.”

An underemployed Scottish workforce with experience in the fading North Sea offshore oil and gas industry and an underused infrastructure which was also serviceable in offshore oil and gas exploration and development are unique attractions to offshore wind developers.

Lamb said there is ongoing investment, now at 17 million pounds ($26.9 million), in upgrading the Methil site and nearby quay.

Scotland has also committed 330 million pounds to upgrading the 137-mile Beauly-Denny transmission system to increase its capacity and facilitate the carrying of onshore and offshore renewables.

A quarter of all the winds in Europe blow across Scotland. “The U.K.’s offshore development plans call for Scotland to have 10.5 gigawatts of offshore capacity by 2020,” Lamb said. Scotland’s government expects to obtain 80 percent or more of the country’s electricity from renewables by 2020.

Beyond developing its own offshore wind capacity, Lamb said, SDI wants Scotland to create a manufacturing center that will be a part of European wind’s massive infrastructure build out. EU plans call for up to half the continent’s electricity to come from offshore wind by mid-century. “To be a part of that,” Lamb said, “we had to bring turbine manufacturers into Scotland.”

Lisa Jackson, the administrator for the U.S. Environmental Protection Agency, headed to Mission Motors in San Francisco on Thursday to talk about clean jobs.

The company, which plans to double its workforce this year, is being highlighted as a shining example of using American ingenuity to build something -- in this case, electric powertrains for motorcycles and vehicles -- that contributes to a “green” economy and “green” jobs.

But there are opportunities far outside of the Bay Area. At a panel on Tuesday night, "Financing Greentech in the Post-ARRA Era: No Money, No Problems?" the panelists all spoke of the opportunities in efficiency -- in particular, in building efficiency and the shipping industry -- that are everywhere.

“I think energy retrofits are a perfect example,” said Ann Davlin, director of development at the Carbon War Room. “You can’t outsource retrofitting a window.”

She is not the first one to make that statement; it is an often-repeated refrain in the building energy efficiency space. But it is one that is only slowly seeping into policy. The Obama administration is working on passing HOMESTAR legislation that would help homeowners finance retrofits and a $4 billion “Better Building Initiative” that would make commercial facilities 20 percent more efficient by 2020.

But companies shouldn’t wait around, warned Davlin. “One of the challenges is that companies are waiting for regulation rather than making the market work for them today,” she noted.

The lack of supportive legislation at the federal level doesn’t mean that government cannot, or has not, been useful. In fact, this has in some way helped drive legislative and administrative innovation and creativity at the state and local level.  Nonetheless, the federal government will eventually need to get on board. 

At one point during the discussion, some contention arose over the issue of the role of government and the importance of the green jobs issue. “This is the dumbest part of the debate,” said Jason Scott, a partner with EKO Asset Management Partners. “What do you mean, are we just going to stand still? Are we not going to become a more efficient society?”

In exasperation, Scott went on to call the Solyndra debate even stupider than the jobs debate, noting that the collapsing price for solar has been a boon to other companies, not to mention installers. “It just matters what part of the solar industry you’re in,” he said. “We either move forward or stand still.”

The panelists were all bullish on cleantech, especially the possibilities in efficiency. Although Scott argued that the further you look out into the future, the more it makes sense, he said there were opportunities today that won’t take decades to achieve payback.

While they were on the topic of red herrings, the discussion naturally turned to subsidies. “Without a doubt,” said the moderator, Michael Molnar of Greentech Capital Advisors, “there are no free markets in energy.”

Besides the externalities like health problems with some generation sources, such as coal, Davlin also noted that water use isn’t fully analyzed when comparing generation. But no one on the panel was waiting around for governments to install carbon taxes or impose heftier pollution fines.

The praise for the entrepreneur and America’s risk-taking culture was a thread running through the discussion and the evening, concluding with the panelists all praising the need for such innovators to individually persevere in the face of adversity.

There was a consensus that 2012 might not be “the rosiest year” for companies seeking to get financing for cleantech and efficiency projects. But with renewable portfolio standards and emerging energy benchmarking programs in the U.S., there will be endless winners at both the high-tech and low-tech level. “This is the greatest wealth-creating opportunity of our lifetime,” said Davlin. “I encourage people to stick with it.”

We’ve had a rash of smart grid-to-plug-in car mashups so far this year, including Ford’s new mobile app for its upcoming Fusion PHEVs, and BMW picking Tendril for an EV-home charging demo.

On Thursday, General Motors jumped in with a call to developers to use its plug-in hybrid Chevy Volt as a smart grid asset. GM’s OnStar service has opened up the application programming interfaces (APIs) to demand response, time-of-use rates, charging data exchange and “aggregated services” like charging spot locations that it is building into all new Volt models.

Not that GM is going to open its platform to just anyone. The OnStar-utility integration work has been going on since last summer, when GM announced pilot projects with utilities including Duke, Progress and Motown’s own DTE Energy. GM didn’t name any developer partners in Thursday’s announcement, though it did note that selected developers were getting access to a proprietary API for mobile applications -- something it and all its other plug-in rivals, notably the Nissan Leaf, have been working on for years as well.

GM does have a long list of partners on its connected car vision, including Tendril for home energy controllers, Comverge for demand response, Google for mobile mapping apps, and most recently, General Electric. GE’s new demand response platform on display at DistribuTECH last week included a nearby Chevy Volt as one of the loads it could power down and up remotely. 

GM intends to name three or four more utility partners in the coming year, Paul Pebbles, GM’s OnStar and Volt chief, said in a Thursday interview. While consumer apps are possible, the APIs are really meant for utilities and energy companies to make plug-in cars an asset, rather than a liability, he noted.

Nissan has also been busy hooking its all-electric Leaf sedans to mobile and plug-in communications via partnerships with AT&T, GE and others. Of course, GM has sold fewer than 10,000 Volts so far, and Nissan has sold about 17,000 Leafs worldwide -- hardly a dent on the grid’s capacity. While certain neighborhoods (say, Berkeley, Calif.) may start to feel the grid impacts of too many plug-in cars earlier than most, it’s a problem utilities can solve by upsizing neighborhood transformers for now.

Eventually, however, plug-in cars could present huge challenges to the grid, simply because they’re more power-hungry than any other new technology out there. Adding the half-a-home power draw of a typical PHEV to even a few garages per block will require upgrading distribution grids to manage the unexpected demand, for example.

But the chief concern is not where, but when those plug-ins charge. Plug too many in during hot summer afternoons, and they’ll crash the grid or require massive new peak generation to handle. Plug them in at night, on the other hand, and they can capture cheap off-peak power, as well as wind turbines’ nightly surplus, which saves money for customers and utilities both.

That’s a fairly simple thing to program into cars or charging stations, and will likely be among the first applications beyond straight metering that utilities will provide. Pacific Gas & Electric has been testing out basic remote on-off switching in fleet vehicles with Silver Spring Networks and car chargers from Clipper Creek and Coulomb Technologies. In Austin, Texas, the Pecan Street Project is trying to tie 100 plug-in Volts to smart grid and rooftop solar systems to balance one neighborhood’s power grid.

On a broader scale, NRG Energy is deploying its eVgo public car charger network in Texas with the promise of linking them to so-called vehicle-to-grid (V2G) networks, though that capability is only being piloted with fleet vehicles right now.

OnStar’s expertise in linking its mobile assets -- i.e., its cars -- will be a big selling point. Volt drivers may leave one utility’s territory in the morning and charge in another’s all day. Even predicting exactly how many will be plugged in at any given time is a tough equation, though mobile tracking could make this much easier.

As for actually tapping car batteries for power, that’s a trickier proposition, since it can open up batteries to faster degradation, harming both car owners and battery/vehicle manufacturers in terms of warranty costs. Japan has made an aggressive push into V2G, partly in response to its power crisis in the wake of the Fukushima nuclear plant disaster. But most industry observers agree that a lighter-touch V2G method that shifts rates of charging, rather than actually tapping the car’s reserve, is a better way to go.

Fleet vehicles are another big market. General Electric said last year that it would buy roughly 25,000 electric cars to green its fleet, with the Volt first on its shopping list. It appears that deal may be delayed, however, according to a recent news report.

Last week, GTM Research unveiled its latest smart grid research report, The Networked Grid 150: The End-to-End Smart Grid Vendor Ecosystem Profiles and Rankings. This article is the second in a series of perspectives from the report's author. To read the first perspective, click here.

While The Networked Grid 150 'Top 10 Vendors in Smart Grid', which we announced here last week, includes many of the well-known, established players in the field, the majority of the firms included on our 'Top 10 Vendors to Watch' list are young companies that have aspirations to claim a greater share of the smart grid pie.

FIGURE: The Networked Grid Top 10 Vendors to Watch

Source: GTM Research

The two exceptions are French industrial giant Schneider Electric and U.S.-based Verizon.  While the smart grid space is a natural extension of Schneider’s existing T&D business unit (the company claims to be the world’s largest maker of low- and medium-voltage equipment), in 2010 the company made news with the roughly $1 billion acquisition of the distribution business arm of the former Areva T&D. Schneider then went on to make even bigger news in 2011 by taking over Spanish software player Telvent at a cost of roughly $2 billion (in a move seemingly intended to counter ABB’s billion-dollar acquisition of Ventyx).

Meanwhile, Verizon has had a very active 2011, becoming the first major public carrier to launch a commercial-scale home automation line of business, which the company intends to initiate by offering energy management and security services to its 5 million FiOS (fiber) customers. Earlier in the year, Verizon, in partnership with fellow Top-10 player eMeter, announced that the two firms are developing a cloud-based meter data management solution.

Echelon continued the evolution of its smart grid offerings in 2011 by marking its entrance into the software platform race (joining the likes of Tendril and Digi) with the announcement of its Control Operating System (COS) Software Platform and its new edge nodes (hardware) that leverage the platform.

While not quite shipping the same volume of meters as the market leaders, namely, Itron and Landis+Gyr, Elster continues to be ahead of the other metering players in understanding the need to provide solutions beyond AMI. The company has been active in developing technologies to support distribution automation (DA), electric vehicle charging equipment, and more. While Sensus has been rumored to be for sale for some time now, and while Itron’s stock has seen a steady decline over the past 18 months, making them a possible target for takeover, we wouldn’t be surprised to see savvy acquirers first target this Raleigh-based metering player.

While much of the smart grid conversation is focused on the coming tsunami of data, On-Ramp continues to win over utilities, partners and investors with its Ultra-Link Processing (ULP) networking technology, where the basic idea is offering a lower-cost network infrastructure that still delivers high capacity and coverage advantages, but is specifically designed for applications requiring small amounts of data per device.

The potential for OSIsoft to perform well in smart grid, due to its expertise in high-performance time series data storage and event processing, has been clear to GTM Research for some time. However, the company made news in 2011 when Technology Crossover Ventures (TCV) and Kleiner Perkins Caufield & Byers (KPCB) made a significant minority investment in OSIsoft totaling $135 million.

S&C Electric understands distributed or “edge” intelligence like very few other companies in the smart grid space, and while the firm might not have the market size and power of some of its industrial-strength competitors, we expect its technologies, such as the IntelliRupter PulseCloser, to continue to set the standard of excellence in distribution system protection and other DA applications for some time.

SAS is another example of a leading-edge software and analytics player just beginning to understand the fact that its offerings and the smart grid space appear tailor-made for one another. In 2012, we expect big things in smart grid from the largest privately held software company in the world.

SmartSynch went from being the foremost advocate for cellular technologies in smart grid networking (i.e., talking the talk) to claiming its spot among the smart grid elite (i.e., walking the walk) in September 2011 with the announcement that Consumers Energy had picked the firm to help network its 1.8 million customers.

Lastly, platform player Tendril Networks is arguably the most well known of the home energy vendors. By all accounts, the firm appears to be gearing up for an IPO. The latest announcement has Tendril in late November naming the former CFO of both EchoStar Corporation and the DISH Network Corporation as its new Chief Financial Officer.

Runner’s Up for this list include the following vendors: Consert, Cooper Power, Energate, QualComm, Sentient, and Trilliant. Full profiles for each of these companies are available in The Networked Grid 150: The End-to-End Smart Grid Vendor Ecosystem Report and Rankings.

To purchase The Networked Grid 150: The End-to-End Smart Grid Vendor Ecosystem Report and Rankings today, click here. Please note: to ensure GTM provides a way to get a useful reference report such as this to a broader audience, we have priced this report substantially lower than our normal rates.

You can receive this report for FREE by registering for The Networked Grid 2012. The Networked Grid 2012 is Greentech Media's 4th annual two-day smart grid summit to be held in Raleigh-Durham, North Carolina on April 4-5, 2012. Click here to learn more!

Earlier this week Adobe announced that it had added another 400 kilowatts of Bloom Energy fuel cells to its current fleet of Bloom Boxes.

I spoke with Mike Bangs, Adobe's Director of Global Facilities, about the installation. The two 200-kilowatt units installed at the company's San Francisco site are Bloom's next-generation design and put out twice the power of the previous 100-kilowatt model -- in the same footprint. Those two units provide about a third of the power for Adobe's San Francisco operation.

Although Bloom does have a Power Purchase Agreement (PPA) option, Adobe owns these boxes and qualified for the federal 1603 Investment Tax Credit, as well as the Self Generation Incentive Program (SGIP). Between those two generous programs, Adobe estimates that power costs it about $.085 per kilowatt-hour after the incentives. The company has also locked in its price for natural gas for a 10-year term.

For Adobe, this is "another step toward becoming Net Zero" with the potential for its buildings to be independent from the energy grid supply and have zero carbon emissions annually.

Adobe has already installed 12 100-kilowatt Bloom Boxes at its San Jose headquarters in 2010, providing 30 percent of that site's power. In both locations, the Bloom boxes are installed on open floors of parking structures, a new installation style for Bloom compared to previous installations, which had been at ground-level.
 
The fuel cells run 24/7 in the million-square-foot San Jose facility, which has a total load ranging from 3 to 5 megawatts. The units are not grid-tied.

"We feel like we're helping mature this technology," according to Bangs.

Bloom has raised more than $600 million in venture capital over the last decade from Kleiner Perkins, NEA, Advanced Equities, et al. The solid oxide fuel cell (SOFC) firm recently closed on its biggest project so far when Delaware regulators approved a plan to bill customers of utility Delmarva Power to build a factory for Bloom’s natural gas-powered fuel cells, along with installing 30 megawatts of its Bloom Boxes in the state.

Jeff St. John recently posed the question, can Bloom’s fuel cells compete with the natural gas-fired power plants that now serve the grid?

That’s a complex question, involving differences in cost per watt (gas turbines are still cheaper), the cleanliness of emissions (Bloom’s fuel cells are arguably cleaner, though they still emit CO2), the potential to capture waste heat for extra benefit (Bloom’s fuel cells don’t, while other gas-fired systems do), and the extra-complex question of whether or not Bloom’s natural gas-fueled devices are truly a “green” energy source.

The 30-megawatt project, which could grow to as much as 50 megawatts, is an order of magnitude larger than Bloom’s biggest projects so far with California customers such as Google, eBay, Adobe and AT&T, as well as Bloom’s pilot projects with California utilities Pacific Gas & Electric and Southern California Edison and Tennessee’s EPB.

California regulators recently proposed changes to the state’s Self-Generation Incentive Program (SGIP) that could put an end to such out-of-state biogas credits, although it won’t apply to projects already underway. Given that the old rules gave biogas projects almost twice as much subsidy money as non-biogas sources, that’s a big deal -- Bloom received $218.5 million in SGIP subsidies in 2010, nearly two-thirds of the total disbursed by the program that year.

Other stationary fuel cell makers like ClearEdge Power and FuelCell Energy make use of their combined heat and power characteristics, while Bloom does not. 

So far, Bloom has been able to ship its product into subsidy-rich regions. The big question is if Bloom can survive when those subsidies recede.

Only a quarter of the world’s utilities have yet to invest in the first wave of smart grid -- but more than half of them are already looking at Round Two.

Those are some of the results from Microsoft and OSIsoft’s latest global smart grid survey released at DistribuTECH last week. While only 24 percent of utilities have no smart grid projects underway, a full 52 percent say they need help tying existing smart grid systems into an enterprise-wide whole, the survey found.

That no doubt smells like opportunity for Microsoft, which has a long list of smart grid partners that claim compatibility with its Smart Energy Reference Architecture (SERA) program.

Of course, it’s also an opportunity for Cisco, SK Telecom, and some of the other grid giants that have launched network-of-networks management plays so far this year. Indeed, OSISoft is partnered with both Microsoft and Cisco’s smart grid programs.

It’s all part of the smart grid’s growing pains. Billions of dollars in federal stimulus grants have pushed millions of smart meters and grid devices into the field, and now utilities are overwhelmed with managing them. GTM Research predicts utilities will spend $8.25 billion by 2015 on smart grid enterprise services like customer engagement, business services and grid operations.

Even so, Microsoft and OSIsoft found that 72 percent of utilities haven’t yet started on enterprise-wide integration projects. That sounds like an opportunity from both sides of the smart grid. Smart grid networking upstarts like Silver Spring Networks and Trilliant are promising end-to-end platforms of their own, while Cisco and smart meter partner Itron collaborate on linking meter and grid assets in a unified whole. We’ve also got a slew of partnerships and smart-grid-as-service offerings seeking to bridge the gap between deployment and smooth operations.

Overall, the survey found smart grid implementations up 25 percent in 2011 compared to 2012, but also found that fewer utilities were expecting their smart grid budgets to increase in 2012 -- 63 percent, compared to 72 percent in the previous year.

In September of 2010, Greentech Media scored one of the first U.S. interviews with Claus Rubenius, CEO of the eponymous firm that was going to build the most massive electrochemical energy storage project in the world.

Rubenius was going to construct an "energy warehouse" of up to one gigawatt (or four to six gigawatt-hours) of NGK sodium sulfur batteries on 350 acres of land in Baja California to provide an energy storage resource to Southern California and Mexico. The cost for the project would be $4 billion over seven years. The Baja site was chosen because of its proximity to both the Baja California power grid and the U.S. grid, including the new Sunrise Power Grid expansion, according to the firm. Mr. Rubenius claimed to have already built one of the world's largest battery storage installations in the United Arab Emirates.

A spokesman for the Silicon Border Baja site said that there was an "agreement with one large utility for a portion of the first 50 megawatts."

A few months after the announcement, I checked in with Jacob Rikard Nielsen of Rubenius, and he said, "We are still in the development phase, but things are progressing. We should have some interesting stuff signed in the near future."

In September of the following year, I followed up with the CEO, who assured me that 1) the Baja, California project endorsed and authenticated by the President of Silicon Border, DJ Hill, is absolutely still going ahead, and 2) that a project of this scale does take time to come to fruition, and while parts of the project may be taking longer than anticipated, the endeavor is progressing well overall. 

In November 2011, Rubenius was talking about additional large-scale sites in Mexico and South America, according to reports. The company will break ground in Mexicali this quarter, as per a recent IEEE Spectrum report.

An energy storage expert said that Rubenius had done little research on the California market before making announcements, that the project was on the wrong place on the grid, and the firm had little coordination with NGK.

And now, Greentech Media has just learned of layoffs at the firm. A source close to the company said that the firm was "letting go of people left and right."

In the United Arab Emirates, the Amplex Group (a Rubenius subsidiary) has installed and commissioned the largest energy storage system in the world -- 350 megawatts, according to Mr. Rubenius. (Here's a citation from NGK of shipments to that region in 2010.) Sodium sulfur (NaS) batteries are bankable and they work, although they are expensive and can catch fire. NGK is the world's only volume producer of the product.

Energy storage at the utility scale can serve different needs, including:

    • Grid stabilization
    • Frequency regulation
    • Voltage support
    • Power quality
    • Load shifting
    • Energy arbitrage

Rubenius seems focused on massive storage capacity for price-based and diurnal energy arbitrage. This is noble, but a little miscalculated. Emerging commercial energy storage applications from independent storage provider entities like AES are not focusing on energy services, but rather on power services such as frequency regulation and moderating renewable ramp-rates.

There is a path to market for these ancillary services, but that's not the case for the massive load shifting that Rubenius has in mind. Not yet.

That's if Rubenius is in fact a viable entity with a real business plan and a balance sheet to match.

Can the right combination of technology and economic incentives get utility customers to turn down megawatts of power use fast enough to balance wind power’s ups and downs? Honeywell and Hawaiian Electric Co. (HECO) are going to try it out on the island of Oahu, using Honeywell’s automated demand response technology.

Under the two-year pilot announced Thursday, HECO plans to offer customers lucrative incentives to turn over their power loads -- factory motors and process lines, lights, air conditioners and the like -- to allow them to be turned down within 10 minutes' notice. Honeywell will connect the utility to customers with its Akuacom demand response servers, which use a standard called OpenADR.

It also will install its Tridium smart grid controllers at buildings to translate power-down signals into commands within the buildings. All told, the project is targeting 7 megawatts of power-down capacity, Jeremy Eaton, Honeywell’s vice president of smart grid solutions, said in an interview.

Honeywell’s been doing automated demand response projects like these for some time in California, Florida, the United Kingdom and China, but the Oahu project is its first specifically linked to balancing wind power, Eaton said. That requires a much faster response time than traditional day-ahead or hour-ahead demand response programs.

It will also require close coordination with the utility and its systems for communicating with the wind farms that connect to its grid. First Wind operates a 30-megawatt wind farm on Oahu's North Shore, and it is backed up by a 10-megawatt-hour, 15-megawatt battery system from Lyle, Texas-based startup Xtreme Power, designed to smooth power flow onto the grid.

All of that integration work lies in the future, Eaton said. Right now, Honeywell is working with HECO to identify customers and start putting its technology in place. The utility is offering a $5 per kilowatt payment just for signing up, much like the so-called capacity payments paid to traditional demand response participants today, as well as 50 cents per kilowatt-hour for the up to 80 hours per year they may actually be powered down.

Wind power’s fluctuations are easier to balance out on the mainland, where utilities can tap regional power reserves like natural gas-fired peaker plants to help manage the ups and downs. But Oahu gets the lion’s share of its power from burning imported diesel fuel, which makes balancing power expensive and hard to come by -- thus justifying the high prices HECO is willing to pay participants in the new program.

Hawaii also has a goal of getting 70 percent of its power from renewable resources by 2030, and while some of that can come from stable geothermal or biomass resources, a lot of it will come from intermittent wind and solar power.

This isn’t the only project aimed at balancing wind power with demand response. EnerNOC has been working with the Bonneville Power Administration on a stimulus-funded project aimed at matching the region’s growing share of wind power with big power customers like cold storage facilities.

The country’s biggest demand response aggregator wants to automate much of that process, both with its in-house technology and with other companies, utilities and agencies using the OpenADR standard. That’s the technology that Honeywell’s Akuacom servers use, but we’re seeing more companies build equipment to use the open-source technology, given that it’s being adopted by federal regulators as a smart grid standard.

Some demand response systems are aiming at even faster power-down speeds. In November, startups Viridity Energy and Enbala launched smaller-scale projects aimed at responding in seconds to play into frequency regulation markets for Mid-Atlantic grid operator PJM.

Last month, GTM Research unveiled its new report, The Networked Grid 150: The End-to-End Smart Grid Vendor Ecosystem Profiles and Rankings. This article is the third in a series of perspectives on the topic from the report's author. To read the first perspective, click here; the second piece is here.

At the moment, the mantra in smart grid is 'Software, software, software.' Across the board, the biggest players are snapping up the most promising software vendors, at a clip we’ve not before witnessed in this industry.

While there have been notable purchases in the past, the acquisition of Ventyx by ABB for over $1 billion (to strengthen the latter's network management business) was one of the early “Holy cow!” moments. Next was Schneider Electric with its roughly $2 billion takeover of Telvent (soon after having purchased the distribution arm of Areva T&D for more than $1 billion). Meanwhile, GE announced that it was putting much more emphasis on software across the entire company, opening a new facility in northern California and investing as much as $1 billion on software development through 2015. Further, in Q4 2011, GE announced that it is now offering a software-as-a-service solution as part of its solution portfolio, something of a new twist for the industrial giant. GE, it could be argued, has actually been the quietest of the titans on the software-acquisition front. However, having said that, GE did have a nice pickup with Opal at the end of 2010. 

Alstom snapped up a gem in Utility Integration Solutions (better known as UISOL) in an early 2011 acquisition. And Siemens, which already has serious grid software operations in place on the wholesale market side, and which in the summer of 2011 invested over $25 million in Tendril, pulled out its smart grid wallet again when it bought eMeter outright in the final days of 2011 for a rumored $200 million.

Not that software has been the only area of interest of late. Cisco Networks acquired wireless mesh networking player ArchRock in Q3 2010, but software does seem to be the missing piece that many electric utility vendors, especially the legacy players, are sorely in need of. Itron, for example, snapped up Asais, a French-based energy management and analytics company, at the end of 2010.

Smart Grid's 'Big Fish'

Based on market capitalization and market position, the following list represents the 25 largest companies in smart grid. While not all of these vendors are fully active in the smart grid space (Microsoft, Intel, AT&T), and while others currently exhibit merely the potential to be a leading player (such as Panasonic/Sanyo), we have denoted the companies that are currently active in the market with the nickname 'Big Fish.'

The term is fitting, as a smart grid feeding frenzy has been underway for the past 24 months and currently shows no signs of letting up. While the Big Fish noted in the following chart are actively leading this market today, due to their buying power, each of the companies listed could decide to quickly increase its smart grid offerings and join the ranks of smart grid's Big Fish, just as Toshiba did in March 2011 with the acquisition of Landis+Gyr for $2.3 billion. This move was surprising, not only because it seemed to come out of left field, but also because the rumors were contending that Toshiba substantially outbid the competition, to the tune of several hundred million dollars. If that is true, it certainly speaks to the buying power of the large caps.

FIGURE: GTM Research's Big Fish of Smart Grid

Source: The Networked Grid 150 (GTM Research)

To avoid confusion, we separated the market into three sub-verticals: hardware, software, and energy services. While our research breaks down smart grid into more detailed submarkets, this trichotomy allows for a quick understanding of where the Big Fish are presently active, as well as which area each of these titans are likely to approach.

For further clarity, we would like to distinguish between the significance of being labeled a Big Fish and being included on our list of Top 10 Vendor List. As mentioned previously, the companies in the GTM Top 10 all have the following characteristics:

• Best-of-industry technologies
• Utility-scale contracts with the largest utility-actors on the global stage
• Influence that extends beyond their particular domain expertise
• Excellent brand recognition in the smart grid
• Astute product marketing
• Integrated solutions that maximize utility investment, and
• An understanding of the changing needs of utilities, as well as the ability to anticipate these needs

Meanwhile, the criteria to be called a Big Fish are rather simple:

1. Being active and influential in the smart grid market (which we consider different than simply running a legacy utility business)
2. Having a market cap of greater than $20 billion

Note: There are four companies that are both Top 10 Vendors and Big Fish: ABB, IBM, Siemens and Toshiba (via Landis+Gyr). At the same time, there are other giants that we currently consider Big Fish, such as GE, and Cisco, that did not make this year’s Top 10 Vendor List.

To purchase The Networked Grid 150: The End-to-End Smart Grid Vendor Ecosystem Report and Rankings today, click here. Please note: to ensure GTM provides a way to get a useful reference report such as this to a broader audience, we have priced this report substantially lower than our normal rates.

You can receive this report for FREE by registering for The Networked Grid 2012. The Networked Grid 2012 is Greentech Media's 4th annual two-day smart grid summit to be held in Raleigh-Durham, North Carolina on April 4-5, 2012. Click here to learn more.

The California Public Utility Commission ruled today that Pacific Gas & Electric customers that do not want smart meters could pay to have an analog meter.

The long-awaited vote is being watched by other states, although California is not the first to formalize its smart meter opt-out plans.

Residents who are concerned about their smart meters, whether due to privacy issues or electromagnetic radiation health concerns, they can pay a premium to get an analog meter instead of the smart meter.

The added cost of not sending the information wirelessly means about $113.4 million in added costs to PG&E’s customers over the next two years. The $113.4 million was based on the cheapest option -- turning the radio off. The other options include ripping the radio completely out of the meter or replacing the smart meters with the old analog meters. Another option is hard-wiring the connections, although that is even more expensive than putting an analog meter back in.

PG&E was pushing for the ‘radio-off’ option, but the opposition argued that even without the radio, the meter still emitted radiation. PG&E did provide the information that the meters do in fact still emit some RF when the radio is turned off or removed completely, but the CPUC found it was still below the FCC allowable emissions.

For the pleasure of living in a smart-meter-free environment, customers will have to pay $75 upfront and $10 monthly for an analog meter. Low-income customers will pay $10 upfront and $5 per month. A radio off-meter did not meet the concerns of opponents, and a hard-wired meter was seen as too expensive. The difference in cost between putting analog meters back in versus turning the radio off was $416 versus $402, respectively. 

The upfront costs are less than what PG&E initially asked to charge customers, but they are also higher than what Central Maine Power is charging its customers. In Maine, customers are charged $20 for a meter with a disabled radio, and $10.50 per month thereafter.

“Today’s decision provides a choice to customers who would like to opt-out of PG&E’s smart meter installation program at a much lower cost than originally proposed," Commissioner Timothy Alan Simon said in a statement. “It is a great example of how public initiative and participation can result in better regulatory policy.”

Maine, which has had its opt-out program in effect since last summer, expects to see about 6,000 customers choose the option once everyone's request has been processed. But already, many people are opting out of opting out, so to speak, because the extra $10 to $12 a month is a higher price than they’re willing to pay.

In California, the stakes are far higher. PG&E’s cost calculations assumed that 148,500 customers would turn off the radios in the meters or move back to analog. However, CMP initially estimated about 9,000 people would opt out, and the figures are actually far lower.

If PG&E’s figures are correct, however, it could impede California’s aggressive smart grid plans for the big three investor-owned utilities. The utilities, including PG&E, are expected to move to more residential time-of-use pricing and demand response programs, which are nearly impossible to deliver seamlessly and automatically without fully enabled smart meters.  

“We remind parties that while we believe that residential customers should be offered an opportunity to opt out of receiving a wireless smart meter, the selected option should not impede state energy objectives,” the CPUC wrote in the decision. “As such, it is important that the selected opt-out option has the capability to allow customers to take advantage of smart grid benefits in the future.”

Many smart grid experts argue that those who opt out will just have to miss out on the benefits of detailed energy consumption and programs that could lower their bills in the future. Eventually, the CPUC had to agree -- for the time being -- and said it would go with only an analog opt-out option and revisit it once TOU pricing was being offered to all residential customers.

Unlike Maine, which has two opt-out options, the CPUC thought one option was less confusing for customers and less expensive for PG&E.

Perhaps even more importantly for PG&E, the CPUC did not make a determination in regards to a community-wide opt-out. The Commission will take the issue up in a second phase of the opt-out plan.

Aneesh Chopra may be stepping down as the nation’s first federal CTO, but his idea of a “Green Button” system to standardize smart consumer energy data across the nation lives on. Smart meter hardware and software vendor Aclara is the latest to join in, announcing last week (PDF) that it’s enabling Green Button data download for Pepco’s customer energy web portal, set to be rolled out to its 1.9 million customers over the coming years.

By April, Aclara says it will offer green button capability to the other 20 or so utility customers now using its customer presentment software, including Avista, Wisconsin Public Service, DTE Energy, Dominion Power and Duke Energy. While it hasn’t announced any customers beyond Pepco, Sempra companies Southern California Gas and San Diego Gas & Electric were likely partners, Robert DiBella, product manager for consumer engagement products, said in an interview this week.

Beyond Pepco, California’s big three utilities and Texas’ Oncor and CenterPoint have been the first to jump on the green button bandwagon, launched in September by Chopra’s Office of Science and Technology Policy. Chopra challenged utilities to agree on a standard format for sharing customers’ energy data, so customers can download, analyze, and ship it to third parties of their choosing, no matter what state they’re in.

Pacific Gas & Electric and SDG&E have started providing green button downloads on their customer Web sites, with help from startups including Tendril and Opower. (Both utilities are also using or plan to start using Aclara’s web presentment software, by the way.) In Texas, Oncor and CenterPoint are planning their green button data to run over the Smart Meter Texas portal, a statewide customer-utility platform built by IBM and run by ERCOT, the state’s grid operator.  

Pepco was the final utility to take up the first Green Button challenge last year, and now we know how it’s going to deliver it. Esco Technologies, Aclara’s parent company, brought in the expertise of utility consultant and recent acquisition Xtensible Solutions to help with the integration, DiBella said.

Aclara uses tricks like “on-demand data transfer,” or only uploading utility data to its cloud when it needs it, rather than in huge nightly batches, to ease the back-end integration burden, he said. On the front end, it packages data into customer-friendly formats, a field that has dozens of competitors seeking the magic formula to get people involved in their energy profiles.

It’s hard to get people to care about such a low-budget item as power bills, so companies have been trying “push” methods like emails and text message alerts, or “choice architecture” methods that help guide people to make the best decisions -- mainly by choosing them in advance and presenting them to people as a yes-no option, rather than as a confusing list. DiBella said that roughly 1 million of Aclara's 8 million web-enabled utility customers actively engage with their portals, though it's hoping to raise that over time.

Once the data’s available, startups like Simple Energy and others can ask customers for permission to look at it, analyze it, and present it back to them in new and innovative ways. Facebook and Opower are working on an energy data social media strategy, and lots of startups promise neighbor-to-neighbor comparisons, contests and other tricks to get people involved -- all while presumably keeping personal data protected from snoops.

Aclara has hundreds of utilities using its smart meter technology, most of them smaller ones, but it’s also doing a lot of business on the customer-facing software side, with 15 of the top 25 consumer engagement portal deployments in the country, according to a September study.

Those customers include Duke Energy, which is using Aclara’s software to link about 70,000 Cincinnati area customers to their Echelon smart meters. Duke has been slower to roll out smart meters in its other territories, and has run into trouble with Indiana state regulators over the cost of the project, compared to the benefit to the customer. Providing useful energy data could help utilities assuage state regulators’ concerns on that front.

Of course, with the green button standard just now emerging, “I don’t think anyone’s gotten that far with it,” Di Bella said. “I think we’ll see a lot in the world of mobile apps coming up, because they seem to get done faster.” Pretty much every home energy management startup has iPhone and/or Android apps that could incorporate Green Button data with relative ease, either as the simple comma-separated values files that it now comes in, or via XML, as utilities have promised to deliver later this year.

As for building third-party applications to do interesting things with green button data, Tendril recently launched a developers' platform for the purpose, and we saw some green button apps at last month’s Cleanweb Hackathon in New York. In the coming months, watch out for Opower and Honeywell: the two were showing off smart thermostat-smartphone technology at DistribuTECH that is likely to incorporate Green Button functionality pretty soon. 

PALM SPRINGS, California --- Reporting from the Clean-Tech Investor Summit.

Ira Ehrenpreis is the cleantech partner at VC-investment firm Technology Partners. For the eighth year in a row, Ehrenpreis is serving as the Conference Chairman of the Clean-Tech Investor Summit today and tomorrow in Palm Springs, Ca. He has been investing in cleantech since long before it was called 'cleantech.'

When Ehrenpreis first started investing in cleantech, "cleantech was niche, not mainstream" and represented less than one percent of the venture capital asset class. Today, cleantech is one of the fastest-growing sectors in the venture capital business.

VC investment in U.S. cleantech companies hit $4.9 billion in 2011, a drop of 4.5 percent in terms of capital invested compared to 2010, according to an Ernst & Young study based on info from Dow Jones VentureSource. This still represents a 29 percent increase from the $3.8 billion raised in 2009. 

"VCs would show the door to an entrepreneur without a long-term business plan," said Ehrenpreis, bemoaning the state of U.S. energy policy and its lack of a long-term plan.

"We're fighting to provide energy for the 1.3 billion people who lack access to electricity," added Ehrenpreis as he spoke about the $1 trillion global energy market, adding, "We're fighting for cheap, clean energy for our children without destroying the environment."

Ehrenpreis' main point in his kick-off speech was that "innovation is going to be the catalyst that changes the trajectory of the cleantech sector."

With regards to cleantech deployment, Ehrenpreis said, "While I've never been more bearish on U.S. cleantech, I've never been more bullish about global cleantech." He noted that R&D investment in energy is 0.3 percent of sales compared to software and pharma at more than 10 percent of sales.

Ehrenpreis addressed the misinformation in the media that the story of solar is not the story of Solyndra, but rather the 64 gigawatts of solar deployed cumulatively across the globe and the price of solar falling from $25 per watt to $1 per watt. He noted that the high-profile failures at Solyndra and Evergreen are just part of the Darwinian struggle in the cleantech business.

He acknowledged that there are challenges but reminded the crowd that the past 8 years have seen the emergence of the smart grid, new materials, new sources of energy, and new electric vehicles.

And Ehrenpreis pointed to the lesson that Steve Jobs could teach the cleantech sector -- Jobs' maniacal focus on innovation -- whether it be the iPhone or the iPad or the iPod. Ehrenpreis sees the cleantech sector as waiting for a revolutionary like Jobs to change the industry.

Ehrenpreis closed his speech with this thought: "To all the cleantech entrepreneurs around the world, come with us and help change the world of energy -- and the world we're leaving to our children and grandchildren."

***

Ehrenpreis is on the boards of Accelergy, CoalTek, Deeya, FloDesign, PowerGenix, Solexel, and Tesla.  He is also an investor in Alta Devices and Abound Solar.

Silverado Power believes its approach to development can avoid the controversies impeding the advance of renewables in Southern California.

In response to those controversies, major renewable energy projects got some not-so-great news from Los Angeles County’s Board of Supervisors in the last week of January. The Supervisors’ decisions threaten California Governor Jerry Brown’s ambition to obtain 33 percent of the state’s power from renewables by 2020.

NextEra Energy’s 200-megawatt Blue Sky wind project and Element Power’s 250-megawatt solar-wind hybrid project were both denied permits for meteorological towers by the Supervisors. Without the data that can be gleaned from those towers, those projects will not be able to obtain financing.

Developers are flocking to L.A. County’s Antelope Valley because of enormous wind and solar resources there and the sizable transmission system being developed by Southern California Edison (SCE). When complete, SCE’s lines will deliver thousands of megawatts of electricity generated by Antelope Valley’s wind and sun to California’s populous urban centers.

The controversies center on the ambiguous term 'mitigation.' It was originally associated with the impacts associated with the development of renewables. If harms could not be avoided, they might be mitigated by preserving adjacent portions of land for habitat, preservation and recreation.

More recently, 'mitigation' has come to also mean something like compensation to the communities being impacted by the projects. Neighbors of large projects contend that upheavals from construction and the interruptions of life as it was before development require this second kind of mitigation.

Silverado Power has a different approach, with which it hopes to minimize the need for both kinds of mitigation by being in touch with the community early and identifying the right sites.

Silverado was founded in 2010 by former executives of Recurrent Energy and Renewable Ventures. It is backed by Portugal’s Martifer Solar, which has recently been installing solar at the rate of 100 megawatts a year, according to Silverado Manager of Business Development Chris Wiedemann.

Silverado Power has 16,000 acres of land under site control and approximately three gigawatts of interconnection positions allotted to it across the U.S., largely in the Southwest. It has been granted 355 megawatts of use permits in the region and expects to soon have some 500 megawatts more.

Antelope Valley was one of the company’s first targets, Wiedemann said. But the company was aware of the mitigation controversies swirling around Antelope Valley Solar Ranch One, the 230-megawatt photovoltaic undertaking First Solar bought from NextLight in 2009 and is now building for Exelon, which it sold to last year. 

Drawing on the experience of “other players in the community who have had varying response to community outreach,” Wiedemann said, Silverado chose to aim for smaller, lower-profile projects. “Our focus in that region is between five and 20 megawatts” and is “interconnection-driven,” he continued.

That approach, Wiedemann noted, reduces the need for mitigation of the first variety through the selection of land “that has been previously disturbed: retired farm grounds or properties that are being actively dry-farmed or grazed.” This avoids “major mitigation hurdles” and “major backlash” from community groups, Wiedemann explained, and “takes the controversial issues out of the picture.”

An indication of the soundness of Silverado’s strategy, Wiedemann said, is that that company was "awarded 100 megawatts of PPAs [power purchase agreements] from SCE in the 2010 bidding for under-20-megawatt projects.”

Initially, Silverado has narrowed its focus to three L.A. County projects, Central Antelope Dry Ranch (52 megawatts), Lancaster WAD (5 megawatts) and Silver Sun Greenworks (20 megawatts).

They have received three conditional use permits (CUPs) from the City of Lancaster and one from the City of Palmdale, Wiedemann said. But those cities welcome renewables developers. The prickly and passionate stewards of L.A. County’s high desert are another matter.

“One of the biggest hurdles facing these projects right now is permitting,” Wiedemann said. “We’re putting a lot of time and energy into the L.A. County approval process” and “working very closely with County planners” so as to move ahead with development and the “jobs and investment” it will mean for the region.

As to the second type of mitigation, Wiedemann said, “Our approach has been to get out there early, meet with these groups, present the projects, address concerns in the earlier stages of development and not do an eleventh-hour outreach approach. We see ourselves as long-term community members and participants, and the only way to validate that is to get in front of these folks early and listen to the feedback.” Silverado, he added, has been in contact with “a majority of the town councils in the region.”

Demonstrating the challenge developers face in the Antelope Valley, a local Town Council member’s comment on the vigorous Silverado outreach was, “You better tell them to get their asses over here.”

Wiedemann is nevertheless cautiously optimistic. “Our hope is to maintain a strong relationship with the local groups and interests,” he said. “What we hope will not happen is being [viewed as] guilty by association with some of these other projects that are sited in less optimal areas. That’s the larger risk. Our process and our siting strategy will hopefully prevail: Smaller projects, lower profile and siting away from sensitive biological and cultural resources and local landmarks.”

Silverado, Wiedemann said, intends to be “a long-term partner in these communities, not a fly-by-night developer that comes and goes.”

Can solar play nicely with coal and natural gas?

Tucson Electric Power (TEP) is working with Areva Solar on a concentrated solar power (CSP) "booster" to the 156-megawatt Unit 4 at TEP’s H. Wilson Sundt Generating Station in Tucson. The Sundt plant is a dual-fueled unit capable of using coal or natural gas.

The Solar Boost Project will use Areva Solar’s Compact Linear Fresnel Reflector (CLFR) solar steam generators to produce up to 5 megawatts of power during peak power demand. Areva acquired the CLFR technology from KPCB-funded Ausra back in February 2010.

If and when fossil fuel prices rise or emission allowances are mandated, solar-augmented steam cycles might be a pragmatic option for energy companies.

A typical system would use steam generated by a solar field coupled to a conventional coal or natural gas-powered steam cycle, offsetting some of the fossil fuel required to generate power. Many energy companies are interested in adding solar power to their generating mix, but most solar technologies are not yet cost-competitive with fossil-fuel power generation.  

Why build a hybrid plant instead of a fossil-fueled plant or a stand alone PV or solar thermal plant?

• It reduces the amount of fossil fuel being burned
• A hybrid produces less emissions
• It potentially "greens" existing assets
• Hybrids can address regulatory pressures and potentially help meet Renewable Portfolio Standards   
• The transmission and Balance of Plant (like the power block) are already in place, as well as existing plant staff, along with permits and a water supply

Hybrid solar thermal is gaining popularity. There are more than a dozen projects in development with a total solar component of about 450 megawatts, including Xcel Energy's Cameo project in Colorado. The largest is the FPL project with 75 megawatts of solar in Florida.

The Sundt Solar Boost Project is part of TEP’s plan to expand its solar generating capacity to more than 200 megawatts by the end of 2014 in an effort to meet the Arizona RPS 15 percent by 2025.

Construction of the Sundt Solar Boost is due to begin in the spring of 2012, and it is expected to be operational by early 2013. 

Areva just broke ground on a 44-megawatt solar booster project for an Australian coal-fired power plant and currently has more than 540 megawatts of CSP projects in operation, under construction, or in development.

Other hybrid CSP-fossil fuel projects expected to start up in 2014 include:

• NV Energy at the Chuck Lenzie Station in Nevada, an 1100-megawatt natural gas plant with 95 megawatts of proposed solar
• Tri State G&T in Escalante, New Mexico, a 245-megawatt coal plant with 36 megawatts of proposed solar

Areva's Compact Linear Fresnel Reflector (CLFR) solar steam generators

Here’s some post-DistribuTECH smart grid news for the week so far, the lead item being Pennsylvania's emergence as the new gold rush market for demand response. The state legislature has commanded utilities to shave 4.5 percent of their peak load by next year, and utilities have hired EnerNOC, Comverge and Johnson Controls to help out.

The latest is Johnson Controls, which announced Monday it would build a platform for PECO to connect up to 100 megawatts of load. Furthermore, Johnson’s platform will bring together individual consumers, corporate assets and even other aggregators -- like Comverge and EnerNOC, for instance -- into a single view for the 1.6-million-customer electric utility.

The platform comes from EnergyConnect, a customer-facing demand response software developer that Johnson bought last year for $32.3 million. EnergyConnect started serving West Penn Power, a smaller utility, in July. But PECO will be much bigger, incorporating loads from industrial DR provider Hess and Viridity Energy, a Philadelphia-based tech startup that’s controlling fast-responding “microgrid” power assets in several different projects in its home state.

Kevin Evans, VP and general manager at EnergyConnect-Johnson Controls, wouldn’t say what other CSPs (curtailment services provider, i.e., EnerNOC or Comverge) it would be aggregating to give PECO its 100 megawatts. But he did say it would be built on an economic model, still being worked out, that will run alongside the big demand response capacity and economic markets run by grid operator PJM in the state. (It’s a bit like the project Comverge is doing in South Africa for utility Eskom.)

That doesn’t mean EnergyConnect won’t connect customers to those markets, Evans noted. The company has built a customer-facing portal that ties different power market programs into one view, and allows them to preprogram how much power they’ll drop in exchange for what prices (Constellation Energy is trying something similar with its VirtuWatt platform). That should allow them to claim credit both for cutting power for PJM and for their utility’s Act 129 goals, he said.

The 2008 law requires utilities to cut peak use by 3 percent by this year and 4.5 percent by 2013. That’s about 350 megawatts of load -- factories, warehouses, office buildings, small businesses and homes -- that can dial back power use with an hour’s warning.

Act 129 also calls for a three-percent energy efficiency improvement over that time. State regulators have allowed utilities to raise rates to cover the cost of getting there, but they’ve also asked utilities to lower customer costs in the long run.  

“These are the programs that allow those customers to get that money back,” Evans said. He didn’t say whether Johnson was targeting utilities beyond PECO for its platform. It has quite a bit of competition. EnerNOC has announced projects of 40 megawatts or more with Duquesne Light and FirstEnergy’s three Pennsylvania utilities, and Comverge has signed up the state government, a big Caterpillar equipment dealership and other customers in the state.

Comverge has also landed a 65-megawatt project for PECO to deliver residential, commercial and industrial demand response. Whether or not any of that might be run over the EnergyConnect platform, Evans wouldn’t say.

- In other news, we’ve got some capacitor bank news going on with recent ABB acquisition Thomas & Betts and grid tech company Schweitzer Engineering Laboratories (SEL). Cap banks, as they’re known, are an integral part of any grid, serving as shock absorbers for unpredictable ups and downs in power via voltage regulation and volt ampere reactive (VAR) compensation.

They’re also, mostly, dumb preset devices with limited ability to adapt to changing grid circumstances. Monitoring, controlling and automating them represents a one- to three-step process toward integrating them into distribution management systems or distribution automation schemes. ABB has a broad-based set of smart distribution grid solutions that a smart cap bank system could fit into.

Schweitzer has been working on a host of smart distribution grid projects with Progress Energy, American Electric Power and Xcel Energy’s SmartGridCity project in Boulder, Colo., which has demonstrated a lot of useful technologies despite its economic (and political) troubles. The Pullman, Wash.-based startup was named one of GTM Research’s Networked Grid Top 10 Vendors in January, indicating the important, if quiet, role it’s playing in the industry.

First Solar is the largest solar module firm by market capitalization, the largest thin-film solar firm, and one of the largest solar firms by capacity, shipments, and certainly by cumulative profits. The company is in the cross-hairs of every other solar firm and continues to set the bar in terms of solar panel value and corporate performance.

What first Solar does in the next few years is important.

Which is why more than 200 people showed up to attend a presentation by Alex Panchula, First Solar's Manager of Performance Analysis, presented by the Silicon Valley PV Society chapter of the IEEE.  

Last week we looked at the market issues that are compelling First Solar to innovate "beyond the module."

This week, we'll look at some of those innovations and some of First Solar's deployments.

According to Panchula, First Solar must deploy 65 gigawatts over the next 10 years in order to thrive, rather than continuing to play whack-a-mole and chase subsidized markets. First Solar's goal is to get new sales from utility-scale power plants in sustainable markets by 2014. That means eliminating the dependency on subsidies and getting the price of solar down to levels where it is genuinely at grid parity at utility scale in developing nations.

Panchula's presentation proclaims, "Our low-cost technology and captive U.S. project pipeline will help us remain profitable in a shrinking, structurally unbalanced industry."

The First Solar strategy is to go after "open markets" at utility scale. First Solar will not be addressing residential rooftops anytime soon.

The slide below shows a photo of the Agua Caliente installation, a 290-megawatt (AC) project currently under construction. One of First Solar's cost reduction techniques is to build these massive projects quickly. At one point, Agua Caliente was being built at a rate of 5 megawatts per day. That's more than 50,000 panels per day and about 35 acres per day at peak construction.

In "going beyond the module," First Solar looks to lower total solution costs in O&M, financing, balance of system, and cost of capital. Panchula remarked that the First Solar acquisition of RayTracker in 2011 was one of the moves to lower cost and optimize performance. Panchula spoke of more automated construction methods and lowering total BoS to $0.70 to $0.75 per watt, down from its current rate of $1.00 per watt.
 

Recent records for CdTe module efficiency of 14.5 percent and small cell efficiency of 17.3 percent show that CdTe performance still has some life left in it. Panchula is looking toward 14.5 percent to 15 percent module efficiency by 2015.

First Solar has more than 2 gigawatts of utility-scale solar power plants constructed or under construction.

 

Element Power’s proposed Wildflower Renewable Energy Farm, which would be composed of 150 megawatts of wind and 100 megawatts of solar, got dealt a significant setback on January 24 when the Los Angeles County Board of Supervisors unanimously rejected the company’s application for new meteorological (met) towers.

Without met tower data, Element Power is unlikely to be able to obtain financing to proceed.

Across Antelope Valley on the southern slopes of the Tehachapi Mountains, enXco’s Pacific Wind-Catalina Solar project, fully permitted by Kern County, has begun construction. Pacific Wind will be 140 megawatts and Catalina Solar will be 110 megawatts. Conceived separately but almost immediately adjacent to one another, the installations will share a transmission gen-tie and facilities at the point of interconnection, according to enXco Vice President for Southwestern Region Development Mark Tholke. It will be, Tholke said, a “world-class solar-wind hybrid.”

The project is positioned to take advantage of the new Whirlwind substation that Southern California Edison (SCE) is building as part of the Tehachapi Renewable Transmission Project (TRTP) for thousands of new wind and solar megawatts. The high desert has one of the country’s richest wind resources and is also “great for solar,” Tholke said. “The insolation is strong and it’s a little cooler because we have some elevation.”

Though California’s transmission system operator has advanced its management of variability, Tholke explained, a hybrid project makes the task somewhat simpler because, he said, studies show that wind and solar generate at different times. “Wind,” Tholke said, “might feed the transmission system 30 percent to 40 percent of the time. When you layer in the solar, that puts more power onto those same lines.”

Solar-wind hybrids are not uncommon in backyard setups in the U.S. and around the world. Where there is no grid service or in locations where someone wants to minimize grid reliance, a combination of solar panels and a small wind turbine may capitalize on local resources.

According to China state news agency Xinhua, North China Grid Co., a subsidiary of State Grid Corp, China's biggest transmission operator, recently brought on-line a 140-megawatt wind-solar hybrid project composed of 100 megawatts of wind and 40 megawatts of PV solar. It may be the only generating full-size, utility-scale, solar-wind hybrid project in the world. Described as a “demonstration project” in Hebei Province, the project reportedly also incorporates a 20-megawatt battery storage capability.

There are small utility-scale U.S. experiments combining solar and wind around the country. The first and most widely known is Western Wind’s “fully integrated” 10.5-megawatt system in Arizona. It is composed of five two-megawatt Gamesa turbines and a 500-kilowatt Suntech crystalline photovoltaic solar array. A number of developers have announced plans to retrofit solar energy systems immediately adjacent to producing wind projects to test their grid operators’ capability to integrate the two.

There is nothing in the U.S. on the scale of the enXco undertaking. It will use 70 two-megawatt REPower turbines and it will be the biggest Solar Frontier copper indium gallium diselenide (CIGS) PV installation in the world. EnXco has long aspired to build a hybrid project, Tholke said, to show how effective it can be to feed the grid with both resources. The physical proximity of Pacific Wind and Catalina Solar offered the opportunity.

EnXco has other hybrid projects in various stages of development, and, Tholke said, the company remains interested in the concept’s potential. Building this one has taught them much. “There are lessons learned along the way,” he said. “It would have, for instance, been more efficient if we had figured out the mechanics of how to share the gen-tie earlier.”

EnXco did not encounter the kind of local opposition that waylaid Element Power. That is partially due to a tradition of energy development in Kern County that goes back to its days as an oil center. Another reason was what Tholke called “a robust outreach to landowners in the vicinity.” Finally, Tholke noted, the wind-solar project involved “over 300 landowners” and therefore offered a lot of people a personal interest in seeing it go forward.

In the Supervisors’ decision against Element Power, NextEra Energy was also denied new met tower permits for its proposed 200-megawatt Blue Sky project. Local opponents of Wildflower and Blue Sky regarded the Board’s rejection of the met tower applications as a vindication of their ecological concerns.

NextEra Energy’s response to the decision carried a different implication. “Our current focus is on projects further along in our pipeline and executing our 2012 wind development program,” noted NextEra Director of Communications Steven Stengel.

NextEra is the leading U.S. wind developer. The vital production tax credit (PTC) that gives the wind industry a fighting chance to compete with the heavily subsidized oil, natural gas and coal industries may not be extended this year by a gridlocked Congress. U.S. developers are scrambling to get every turbine they can into the ground before the PTC expires on December 31.

Element Power declined to comment on the Board’s decision but is in essentially the same position.

The companies are not as concerned with their opponents in Los Angeles County right now as they are with getting turbines built before the end of the year. And the Supervisors will be more inclined to grant their met tower permits after being re-elected in November, when Governor Brown’s favor will supersede voter sentiment. In the interim, neither developer will forget the rich resources, available transmission and huge nearby demand centers that have been seized on by enXco.

The Department of Commerce Finding

· The U.S. Dept. of Commerce on Jan. 27, 2012 makes a critical circumstances finding on Chinese solar cells/panels.

· The finding was based on import data from Suntech Power and Trina Solar [Editor's note: see Trina response here] for the three-month periods of October to December 2011 vs. July to September 2011 and the four-month periods of September to December vs. May to August 2011.

· All the data points show that imports tracked greater than 15 percent in quantity and value, and in Department of Commerce parlance, this degree of activity is termed as 'Massive' if it happens in a short period of time.

· U.S. Customs and Border Protection's Port Import Export Reporting Service (PIERS) data shows a massive surge in solar cell/module imports in recent months. Suntech Power's imports have surged 76 percent in November 2011, compared with October 2011, and Trina Solar's imports have risen 209 percent in the 1H December 2011, compared with the 1H November 2011.

· We also note that PIERS data shows that Chinese imports of solar cells/modules in January through November 2011 are up 346 percent by quantity and 138 percent by value. In November 2011 alone, Chinese solar cell/module imports surged 438 percent in volume and 47 percent in value compared to November 2010.

· The critical circumstances finding is likely based on PIERS data, and if the Department of Commerce imposes countervailing duties (CVD or anti-subsidy), they will apply 90 days retroactively to all Chinese solar cell/module imports brought into the U.S. from December 3, 2011.

· We note that the preliminary determination on CVD is now scheduled for March 2, 2012 and was recently postponed from February 13, 2012, and was also previously postponed from January 12, 2012. We believe further delays are unlikely.

· We note that aside from CVD duties, the Department of Commerce is scheduled to issue a preliminary ruling on anti-dumping duties (AD) on March 27, 2012, with a separate finding on "critical circumstances" for the anti-dumping investigation. Further, a final determination of both CVD and AD will only be complete by first week of October 2012.

Bottom Line

· The "critical circumstances" finding is the writing on the wall for Chinese solar cell/module imports in terms of what to expect on March 2, 2012. The U.S. is sending a clear signal that rules of engagement on trade do matter.

· Given compelling evidence of China's state-sponsored asymmetric competition and predatory capitalism in solar PV, we are firm in our view that China's abuse of competitive/trade rules has destroyed capital efficiency, created structural imbalances across the industry, and suppressed price discovery, capital formation, risk and mitigation.

· Solar PV stocks are recovering from the sharp and vicious correction seen in 2011, and trade on tangible book value (TBV) based on survival economics, not earnings. We do not expect earnings for most c-Si players until 4Q12. We maintain our constructive stance on the sector (since November 30, 2011) despite ongoing challenges in the U.S., Germany and China, as cost elasticity will take time but will catch up to price elasticity.

· Despite some cries from solar rooftops that the U.S. imposition of tariffs on Chinese solar cells/modules will lead to major job losses, we believe that the solar industry and companies will adjust to the altered dynamic as they have to the reduction of subsidies every year, and if anything, will emerge stronger based on innovation and healthy competition.

 Ample Evidence in the Public Domain

• As we noted previously, the disconnect between solar module ASP and cost is not easy to dismiss. For 4Q11, shipment-weighted ASP guidance for Chinese solar PV modules tracks $1.04/W, but actual ASPs will likely be below cost, given module pricing in the ~$0.80/Wp to $0.90/Wp range in December, which saw a dramatic ramp in installations.
 
• We note that costs are sticky (despite lower poly/materials costs) and estimate that the Chinese c-Si module cost structure will track ~$1.03/Wp (including ~$0.07 adjustment for shipping, warranty, insurance, capacity ramp, and stock compensation).
 
• For reference, 3Q11 shipment-weighted ASP for publicly listed Chinese solar PV companies was ~$1.28/W versus costs of ~$1.24/W (and ~$1.15/W normalizing for write-offs). This is for leading, publicly listed companies and not the second- and third-tier names in the private domain that are largely scale- and/or cost-challenged. However, the true cost structure stacks up much higher when extensive, wide-ranging direct and indirect subsidies and other costs are included.
 

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Hari Chandra Polavarapu is the Managing Director of Solar/Cleantech Research at AURIGA USA LLC.

The Brattle Group has issued an economic analysis on the impact of a 100 percent tariff on PV cells imported from China.

Keep in mind that the study was commissioned by CASE, the Coalition for Affordable Solar Energy -- the group that opposes the tariffs sought by SolarWorld and its anti-dumping claims with the Department of Commerce.

Jigar Shah, President of CASE, said, "We are greatly concerned over the adverse impact of tariffs." He called the likely job losses "staggering" and potentially "devastating" to American workers.

The report looked at 50 percent and 100 percent tariff scenarios. The author of the report said a 50 percent tariff will effectively shut the majority of Chinese imports out of the U.S. and result in a job loss of 15,000 to 50,000 -- even accounting for production gains in the U.S. The report also considers that impact of Chinese retaliation in importing polysilicon, which could result in a loss of 11,000 jobs in 2012, for a total of up to 60,000 jobs lost by 2014.

The author of the report did acknowledge that there would be some gains among U.S.-based module producers -- albeit at higher module prices. GTM Research's Shyam Mehta has said that only about 6 percent of the world's solar panels are made in the U.S., all in highly automated factories. In other words, solar panel manufacturing is not a labor- or jobs-rich industry in this country. The jobs are created in downstream solar industries such as installation and project development.

According to The Brattle Group’s analysis, the imposition of tariffs will “slow the growth in domestic demand for photovoltaic systems by homeowners, commercial establishments and power producers, resulting in substantial job losses.”

Both tariff scenarios are lower than the up to 250 percent tariffs sought by SolarWorld. 

In a press release, Jigar Shah also noted that "the findings of this study are consistent with a recent story (“Get-Tough Policy on Chinese Tires Falls Flat”) in The Wall Street Journal in regard to tariffs placed on Chinese tires. As the Journal reported, 'The measure was meant to whack imports of passenger and light-truck tires and give a boost to manufacturers and job creation in the U.S. Yet, for a variety of reasons, it has apparently done little of either -- and has surely raised prices for consumers.' The WSJ tire story is illustrative of the law of unintended consequences in these types of trade cases."

Shah added, “Imposing tariffs on imported Chinese solar modules will have the same perverse results.”
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