Energy Matters – Page 88

Climate change puts us all in the same boat. One hole will sink us

But despite the mounting evidence of negative impacts, reaching a deal will not be easy. It will require extraordinary political courage – both to cut the deal and to communicate its necessity to the public.

A mindset shift is required. Distrust and competition persist between regions and nations, manifest in a “no, you must show your cards first” attitude that has dogged the negotiations leading up to Copenhagen. This has to be overcome.

A deal that is not based on the best scientific evidence will be nothing better than a line in the sand as the tide comes in. But short-term considerations, including from special interest groups and electoral demands, are working against long-term solutions.

Success in reaching a deal will require leaders to think for future generations, and for citizens other than their own. It will require them to think about inclusive and comprehensive arrangements, not just a patched up compilation of national or regional interests.

A deal that stops at rhetoric and does not actually meet the needs of the poorest and most climate vulnerable countries simply will not work. The climate cannot be “fixed” in one continent and not another. Climate change does not respect national borders. We are all in the same boat; a hole at one end will sink us all.

For it to work, climate justice must be at the heart of the agreement. An unfair deal will come unstuck. Industrialised countries such as the United States must naturally take the lead in reducing emissions and supporting others to follow suit, but developing countries like India or China also have an increasing responsibility to do so as their economies continue to grow.

Tragically, it is the poorest and least responsible who are having to bear the brunt of the climate challenge as rising temperatures exacerbate poverty, hunger and vulnerability to disease for billions of people. They need both immediate help to strengthen their climate resilience as well as long-term support to enable them to adapt to changing weather patterns, reduce deforestation, and pursue low-emissions, clean energy growth strategies.

The deal must include a package of commitments in line with the science and the imperative of reducing global emissions by 50-85% relative to 2000 levels by 2050.

This requires a schedule for richer countries to move to 25-40% emission cuts by 2020 from 1990 baselines; clear measures for emerging economies to cut emissions intensity; and clarity about both immediate and longer term finance and technical support for developing countries, notably the poorest and most vulnerable among them.

Will we get there? The targets that have been proposed for emission reductions by many industrialised countries such as the EU, Japan and Norway are encouraging, as are those being made by the big emerging economies including Brazil, China, India, Indonesia, and South Korea.

Recent announcements by the US on emission targets represent a significant shift and provide a basis for scaling up commitments in the coming years. So does the recognition by emerging economies that they also have a role in supporting the most vulnerable countries.

Welcome too are the proposals for financial support to LDCs and small island states made at the Commonwealth summit in Trinidad, as well as proposals by the Netherlands, France, and the UK, among others.

But much greater specificity on finance is needed. Existing official development assistance (ODA) commitments to help the poorest countries meet the Millennium Development Goals need to be met. And significant additional finance that is separate from and additional to ODA needs to be mobilised to support them meet the incremental costs generated by climate change.

A deal that is not clear on the finance will be both unacceptable to developing countries, and unworkable. Finding the additional resources and communicating its necessity will not be easy, particularly in the current economic climate, but it must be done.

A successful deal could incentivise not only good stewardship of forests and more sustainable land use, but also massive investment into low-carbon growth and a healthier planet, including in sectors such as energy generation, construction and transportation.

And it could usher in an era of qualitatively new international co-operation based on common but differentiated responsibilities – not just for managing climate change, but for human development, social justice and global security.

Ultimately, at stake is whether our leaders can work to help us save ourselves from … well, from ourselves. The legacy of today’s politicians will be determined in the weeks to come.

• Kofi Annan was UN secretary-general from 1997 to 2006. He now chairs the Kofi Annan Foundation and the Africa Progress Panel and is president of the Global Humanitarian Forum

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DC Arc Faults and PV System Safety

As an industry, we have done a good job of providing adequate system protection and safety mechanisms. Widespread deployment of PV systems teaches us new lessons. We must learn from those lessons and continue to improve the safety of PV systems. Arc fault detection is a necessary next step.

Aspects of DC Arc Fault and Safety

Recent proposed changes to the National Electric Code underscore the gravity of DC arc fault risks. The changes (which have NOT yet been adopted as of this writing) will mandate detection of — and preventative measures for — series DC arc faults in systems where the DC voltage exceeds 80VDC. This is a step in the right direction as it addresses the prevention element of DC arc fault safety. There are two elements to the DC arc fault/safety issue:

Prevention – this aspect deals with the mechanism and factors necessary to create an arc, especially one that is capable of becoming the source of ignition of nearby combustible materials. It should be noted that DC arcs can reach temperatures of over 3000 degrees C. Arcs of this temperature can melt metal, which can fall as slag and ignite nearby combustible materials. Preventative measures are therefore necessary to minimize the risk of starting the fire in the first place.
Suppression – this involves all aspects related to extinguishing the fire after it has started. Fires are typically started by some means other than the PV system, but the presence of relatively high DC voltage and high DC current presents a significant risk to the firefighters.

Types of Arcs

Three types of arcs are of particular concern:

Series – A series arc occurs when a connection is pulled apart while the PV is producing current. Any intermittent connection in the DC circuit has the potential for producing a DC arc fault. These connections may include soldered joints within the module, compression type wire connections, or the actual connectors that are commonly used on the wire leads attached to PV modules.

Parallel – Parallel arcs occur when an insulation system suffers a breakdown. Two conductors of opposite polarity in the same DC circuit are often run in close proximity to each other. The insulation between the two wires can become ineffective due to animals chewing on them, UV breakdown, embrittlement, cracking, moisture ingress and freeze/thaw cycles.

To ground – This fault only requires the failure of one insulation system. While GFDI (Ground Fault Detector & Interrupter) provides some measure of protection against this fault, there have been cases of faults to ground that failed to trip the GFDI protection yet created an arc.

Challenges with Arcs

Detection of the arc is the first real challenge. It is paramount that the arcs are reliably detected without raising “false alarms.” Many different techniques can be employed, with most relying on voltage, current, radiated energy, or a combination of these.

Taking appropriate action once the arc has been detected is the second challenge. Furthermore, the correct action for series arcs is the opposite of the action necessary for parallel arcs. In fact, the corrective action for a series arc can actually exacerbate a parallel arc.

To extinguish a series DC arc, power production must be ceased and current flow in the DC circuit must be reduced to a very low level. It is preferable to reduce the DC current flow to zero in order to guarantee that the arc is extinguished. The PV inverter can accomplish this by ceasing exportation of power.

A parallel arc requires the opposite action. The two DC conductors must be shorted together to bring the array voltage to zero. Once the voltage is near zero, the arc extinguishes and the protective device must be capable of carrying the array short circuit current indefinitely.

System Design

Three aspects of system design contribute to the arc fault risk: high DC voltage, high DC current and large geographic distribution of DC wiring. To sustain an arc of significant temperature, the voltage across the arc gap must be in the range of 20 volts or more. DC short circuit current capabilities below 2 or 3 amps have a difficult time sustaining an arc of any real danger. Wide distribution of wiring systems increases the likelihood of physical damage and increases the degree of exposure to firefighters during the suppression phase of a fire.

A traditional string/central inverter PV system design is not beneficial in terms of addressing arc fault risk and firefighter safety. Strings are designed for the highest DC voltage to reduce I²R losses, and multiple strings are placed in parallel to increase the DC current. This design also results in a large geographic distribution of DC wiring systems. All three of these design factors increase the risk of arc faults and make it more difficult to suppress a fault once it occurs.

The impact of DC-DC converters, which operate at high DC bus voltages and connect to a traditional string/central inverter, resulting in the large geographic distribution of DC wiring, is uncertain. Certain types of arc faults could fool the control system into taking inappropriate control actions and theoritically worsen the problem. Some of these systems also rely on communication controls for safety functions. Without appropriate safety measures similar to those used in aerospace control systems, this is a questionable approach.

Microinverter and AC module designs work at much lower DC voltages, lower DC current, and limit the distribution of DC wiring to the vicinity of the module. These inverters are Utility-Interactive, which means that the removal of Utility AC power from the system, results in no AC voltage being distributed, and only low voltage DC under each PV module. This approach reduces arc fault risk and provides the greatest degree of safety for the firefighters.

In summary, as the concern for fire prevention and suppression rises in the PV industry, more attention is being paid to the threat of arc faults. Challenges with arc faults include understanding the type of arc fault and ensuring that the appropriate corrective action is taken. System design also has a significant effect on both prevention and suppression of fires, with increasing preference being given to AC-based systems that mitigate the risk of fire by avoiding distribution of high DC voltage and high DC current altogether.

— Henrik Stiesdal, CTO, Siemens

Proof of Concept

The first concept prototype was erected in July 2008 and a second in March of this year. The most important functional aspect of this “Proof of concept” test trial was exchanging the gearbox and generator of a conventionally geared 3.6-MW SWT-3.6-107 with a direct-drive generator. The concept turbine drive system also includes a rotating main shaft supported by two bearings, whereby the upwind rotor is located in front and the generator behind the tower.

Since the test set-up essentially includes only one main variable, a scientifically sound drive-system comparison can be conducted. Stiesdal said that these two machines have proved themselves faster than expected, including a high availability almost from day one and trouble-free operation of the generators with operating temperatures remaining favurably modest.

Stiesdal explained that the “main lessons learned underline the long process required from [the] ideas phase to a “Proof of concept” machine. Secondly, the optimization required cost calculation models that are not readily available.”

He said that the company “discovered that relevant and competent generator suppliers originate from ‘Design to Project’ practices, and not from parties focused at ‘Design to Manufacture.’ All of this took time to get aligned.

System Layout

The new highly compact 3-MW IEV WC IA turbine features a 101-metre rotor diameter and a cylindrically shaped nacelle. Visually the turbine is characterized by a large prominent cooling radiator unit located at the nacelle rear, while the characteristic long and tapering Siemens nose cone has been exchanged for a substantially shorter solution.

A key conceptual difference with the concept turbine is that the annular generator has moved to the front of the tower. This direct-drive system layout is also taken from (earlier) turbine models that were developed by direct drive pioneers like Enercon and Vensys of Germany and former Lagerwey/Zephyros of the Netherlands.

The main structural element of this 3-MW Siemens direct-drive system is a cast main carrier accommodating eight yaw motors, whereas the generator and rotor assembly as a unit are bolted to its inclined vertical mounting flange. Furthermore, a hollow stationary main pin with the main bearings is an integral part of the generator assembly and provides easy (service) access to the rotor hub internal workings. Both the rotor hub and rotor blades originate from the 2.3-MW SWT-2.3-101 turbine model.

Inverted Generator

For this turbine Siemens worked together with partners to develop a new fully enclosed liquid-cooled permanent magnet type generator. Siemens Large Drives based in Berlin, Germany, provided the generator for the prototype for the turbine prototype but in the future there will be additional suppliers.

The electric machine itself is, in power-engineering terms, known as an inverted radial-flux generator. A key difference with “conventional” radial-flux generators is that the generator-rotor with its magnets facing inside now turns around the stator part. As a consequence this 2-plus-meter-long generator-rotor is directly exposed to the outside environment, and represents a substantial section of total nacelle length.

Stiesdal explained that there were a number of specific reasons for choosing the inverted generator layout: “Annular generators are by definition big in size, which puts high demand on structural component stiffness, and that in turn is necessary for guaranteeing a constant air gap retention between generator-rotor and stator.”

He further explained: “adding sufficient structural strength to the stator of a conventional generator by definition results into a substantial outside diameter increase, which potentially contributes to more complex transport logistics. With an inverted generator by contrast, ample space is available for adding stator support structure towards the centre. Our comparative concept analysis clearly showed that inverted generators can be built more compact compared to conventional radial flux equivalents.”

Lightning Protection

The compact nacelle cover with integrated lightning protection is further fitted with an onboard crane for easier heavy component exchange, including yaw motors, hydraulic pitch parts, etc. Components as well as people (in case of an emergency) can be lowered to the ground through a hatch located in the nacelle cover’s rear section. Main power electronics, including power cabinets, a full converter and a medium-voltage transformer, are all located at three levels in the tower foot similar to the 2.3-MW turbine series arrangement.

When asked why Siemens had chosen a new 3-MW class direct-drive turbine, Stiesdal commented: “Some initial findings indicated that the costs per unit of torque (Nm) decrease when power rating goes up and that at a 3.6-MW rating [the] break-even point seems likely. Our expectations were therefore that a direct-drive concept mainly offers a commercially viable alternative for large offshore turbines. However, we now have sufficient indications that the concept might also be feasible for the high-end high-volume market, and do hope that this machine will prove competitive with our 2.3-MW volume turbine series.’

Early in 2010 Siemens will begin an assembly-line system for the 2.3-MW and 3.6-MW series, the major benefits of which are expected to be substantially reduced assembly time per turbine and optimized factory floor utilization.

Added Value

Another key issue Stiesdal explicitly addressed is what a direct-drive solution can offer in terms of added value to customers. He explained that all manufacturers “feel the heat” of press reports on gearbox failures, but also stressed that his company has successfully built geared wind turbines since 1980.

Stiesdal quoted the results of a 2008 survey on a substantial number of (former Bonus) turbines installed during the mid 1980’s in California. He said that even after more than 20 years, “96% of these installations were still running well.” He also said that the systems were so reliable that the company was able to reduce service time from twice per year to only once per year.

So while it is evident that geared turbines will remain a reliable, competitive alternative for many years to come, it’s important to note that a switch to direct-drive reduces the number of turbine components by 50%. This will make it easier to convince customers of the long-term income stability on their capital investment not to mention that 50% fewer parts to handle also turns into a real cost advantage during high-volume turbine manufacture.

Offshore Applications

Siemens currently has more 450 of the upgraded 3.6-MW SWT-3.6-120 turbines on backlog. In the future Siemens will offer the new 3-MW turbine model for offshore applications, but only after successfully completing a rigorous product testing and optimizing period followed by a careful series production ramp-up.

Stiesdal said that, “at this moment it is far to early to elaborate on 3-MW series production timing, as we first want to see how the turbine performs in the field. That is the way we always did it, and know based upon these experiences that there will always be issues with a new turbine model, smart design concepts included.”

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Designs for new UK nuclear reactors are unsafe

Terry Macalister

27th November, 2009

Major setback for nuclear energy plans as watchdog’s report finds flaws in US and French models

Britain’s main safety regulator threw the government’s energy plans into chaos tonight by damning the nuclear industry’s leading designs for new plants.

The Health and Safety Executive said it could not recommend plans for new reactors because of wide-ranging concerns about their safety.

The leading French and American reactors are central to plans for a nuclear renaissance aimed at keeping the lights on and helping to cut carbon emissions. The government needs to build a number of nuclear power stations in the next 10 years to replace old atomic and coal plants.

HSE approval

But the HSE has to approve the safety of the designs before they can be built.

‘We have identified a significant number of issues with the safety features of the design that would first have to be progressed. If these are not progressed satisfactorily then we would not issue a design acceptance confirmation,’ the agency concluded following a study of the latest French EPR and US AP1000 reactor designs.

Kevin Allars, director of new build at the HSE, admitted frustration that the design assessment process was already behind schedule owing to insufficient information from the companies promoting the reactors and a lack of enough trained staff in his own directorate.

The HSE’s public report expresses ‘significant concerns’ about the lack of separation between the safety protection and control systems on the EPR reactor design promoted by Areva and EDF of France.

Design faults

The safety body says another part of the reactor is ‘not entirely in alignment with international good practice’.

The report says it has raised a number of issues with EDF and Areva relating to the structural integrity of the EPR and it concludes: ‘It is too early to say whether they can be resolved solely with additional safety case changes or whether they may result in design modifications being necessary.’

The design put forward by Westinghouse, the American firm now owned by Toshiba of Japan, is also criticised, with the HSE saying the safety case on internal hazards has “significant shortfalls”.

It criticises the company for a “lack of detailed claims and arguments” to support various assertions, while questioning aspects of the civil and mechanical engineering plans as well as the structural integrity and “human factors”.

It also complains that the reactor design was submitted in feet and inches rather than metric figures.

Delay

Industry experts said the HSE was in a pivotal position to make or break the government’s wider plans because it could delay the planned reactors from coming on stream from 2017.

That is the time that ministers fear an “energy crunch” because most existing reactors will have been retired, many coal plants shut down and renewable power insufficiently advanced to take over.

John Large, a leading nuclear consultant, said: ‘The HSE as an independent agency will come under tremendous pressure to push through these designs. But if it stands up to [the] government and stops or delays these designs for two or three years until it is satisfied then developers could lose interest and we could fall behind in the queue of countries waiting to build nuclear.’

Allars said he had not received any pressure so far from the government. While he had beefed up his staff and hoped to quicken the speed of his work, he insisted it was not his problem to worry ultimately about delays.

Independence

‘I am independent of government, and independent of industry and I will do what I need to protect society from any dangers of nuclear power. I will only be in a position to agree a generic design assessment if I get the right information [in future] to do that,’ he said.

The HSE said it might allow so-called exclusions over some of its concerns under which it would allow construction to proceed on the understanding that the problems would be addressed later.

Jean McSorley, consultant to Greenpeace’s nuclear campaign, said it was highly likely reactor designs would not be ready for final sign-off at the end of the design process.

‘This could leave the utilities and construction companies with real problems finishing projects, and that’s very risky for them financially. Investment companies will also want to delay putting money into these projects until it is decided who takes responsibility for any potential cost overruns and delays,’ she said.

Areva shrugged off the concerns raised by the HSE.

‘It is important to emphasise that this is a normal part of what is a very transparent process and that it is entirely expected, as part of the design assessment process in the UK, for issues to be identified and resolved prior to licensing and construction,’ it said.

This article is reproduced courtesy of the Guardian Environment Network

27 November, 2009

Solar’s rapid evolution makes energy planners rethink the grid

The initiative, called RETI, is an attempt to build a statewide green grid in an environmentally sensitive way that will avoid the years-long legal battles that have short-circuited past transmission projects.

But the rapidly evolving solar photovoltaic market may moot the need for some of those expensive and contentious transmission lines, requiring transmission planners to rethink their long-term plans, according to Black & Veatch, the giant consulting and engineering firm that does economic analysis for RETI.

In short, solar panel prices have plummeted so much as to make viable the prospect of generating gigawatts of electricity from rooftops and photovoltaic farms built near cities.

“This has pretty significant implications in terms of transmission planning,” Ryan Pletka, Black & Veatch’s renewable energy project manager, told me last week. “What we thought would happen in a five-year time frame has happened in one year.”

That’s prompted Pletka to radically revise the potential for so-called distributed generation—solar systems that can plug into the existing grid without the construction of new transmission lines—to contribute to California’s need for 60,000 gigawatt hours of renewable electricity by 2020.

When Black & Veatch did its initial analysis last year, it predicted that photovoltaic solar could contribute 2,000 gigawatt hours, given the high cost of conventional solar modules and the fact that a next-generation technology, thin-film solar, had yet to make a big commercial breakthrough.

Pletka’s new number is a bit of a shocker: Distributed generation could potentially provide up to 40,000 gigawatt hours of electricity, or two-thirds of projected demand.

“Certainly some of the new transmission lines will be needed but not as many as before,” he says.

That analysis also calls into question the need for as many large-scale solar power plants. Currently there are about 35 Big Solar projects planned for California that would generate more than 12,000 megawatts of electricity.

A game-changer has been the rapid rise of thin-film solar. Thin-film solar modules are essentially printed on glass or other materials. Although such solar panels are less efficient at converting sunlight into electricity than traditional crystalline modules—which are made from silicon wafers—they can be produced more cheaply.

In the past year, utilities like Southern California Edison have signed deals with First Solar, the thin-film powerhouse, to buy electricity from four massive megawatt thin-film solar farms. And in September, China inked an agreement with the Tempe, Ariz., company to build a 2,000-megawatt power plant, the world’s largest.

The next day, Nanosolar, a Silicon Valley startup, announced it had secured $4.1 billion in orders for its thin-film modules, which it claims will be even more efficient and cost less to produce than those made by First Solar.

Meanwhile, California’s two biggest utilities, PG&E and Southern California Edison, this year each unveiled initiatives to collectively install 1,000 megawatts of distributed solar generation. SoCal Edison will put solar arrays on warehouse roofs throughout the Southland—First Solar snagged the first big contracts—while PG&E is focusing on ground-mounted solar systems near its existing substations.

So what’s behind this rooftop revolution in solar?

Partly it’s due to a glut in the solar panel market. The global economy collapsed last year just as solar module makers ramped up production. But it’s also a result of technological innovation and economies of scale that have made thin-film solar, for instance, competitive. Strides have also been made in cutting installation costs, which typically account for half the price of photovoltaic systems.

The solar market, of course, is heavily dependent on government incentives—in the United States and overseas—and thus vulnerable to disruption. But the trajectory remains one of falling prices and thus Black & Veatch’s projections pose a conundrum for transmission planners.

Given that transmission projects can take a decade to complete, power bureaucrats make their plans based on 10-year projections of energy costs according to Pletka. That wasn’t much of a problem when planning transmission for, say, a grid supplied by natural gas-fired power plants as the technology or the market was not likely to change radically.

Not so for solar, where technological advances and fast-changing market conditions are shaking long-held views that photovoltaic power, or PV, is not ready for prime time.

“I’ve worked in renewables since the ‘90s and I myself had written off solar PV for years and years and years,” Pletka says. “That’s a firmly rooted mindset among everyone who works from a traditional utility planning perspective.”

“We present this new information on photovoltaics to people and it’s still not sinking in,” he adds. “It would cause a major shift in how we plan.”

While fewer massive transmission projects would be needed if California generates gigawatts of electricity from rooftops, the distribution network will need to be upgraded and a smart grid created to manage tens of thousands of pint-sized solar power plants.

Cities, Pletka notes, could become generators of electricity rather than consumers of power.

“It brings up questions people haven’t had to talk about before,” says Pletka.

SolarReserve’s 24/7 solar plant

The company was in the news last week when it filed an application with California regulators to build a 150-megawatt solar power plant in the Sonoran Desert east of Palm Springs. The Rice Solar Energy Project will be able to store seven hours of the sun’s heat so it can be released when it’s cloudy or at night to create steam that drives an electricity-generating turbine. Future versions of the solar farm will be able to store up to 16 hours of solar energy. Other solar power companies are using energy storage but SolarReserve’s technology is a potential game-changer (more on that in a bit).

SolarReserve has kept a low-profile. Not surprising for a company founded by executives who previously needed government security clearances to get into their offices. (I only found out about the Rice project when I noticed SolarReserve had filed an application with the California Energy Commission.)

The company first caught my attention when a day after Lehman Brothers collapsed last September—setting off the global economic meltdown—the startup issued one of its rare press releases, announcing it had raised $140 million from a blue-chip roster of big players, including Citigroup and Credit Suisse.

A few weeks later I flew to Los Angeles to meet SolarReserve president Terry Murphy and his team, headquartered somewhat incongruously around the corner from Geffen Records, Lionsgate, and other outposts of the entertainment-industrial complex.

The SolarReserve execs were affable and eager to discuss their technology but close-mouthed about the dozens of deals they said were in the works for Big Solar power plants to be built in the desert Southwest and overseas. (One tantalizing hint they dropped was the interest of an unnamed utility in a massive complex of 10 SolarReserve power towers that would generate 1,000 megawatts.)

I’ve kept in touch with Murphy and even as the credit crunched worsened and the solar industry began to consolidate as startups ran out of money, he remained confident that SolarReserve would remain on track.

“We’re capable of riding this out,” Murphy told me a few months ago.

That’s because as investors run away from financing billion-dollar solar power plants using untried technology, SolarReserve’s ace in the hole is Rocketdyne and United Technologies.

The company that guaranteed Neil Armstrong made it to the moon will guarantee the performance of SolarReserve’s solar power plants. In these tough times, that’s what it takes to raise money on Wall Street or from well-capitalized utilities.

“SolarReserve has a very credit-worthy backer—United Technologies—which has said it will stand behind that technology and which gives them an edge,” said Tom Glascock, a global finance partner at the San Francisco law firm Orrick, at a recent seminar for green tech movers and shakers.

Rocketdyne’s molten salt technology was proven a decade ago at the 10-megawatt Solar Two demonstration project in the desert outside Barstow, Calif.

Solar Reserve’s planned Rice solar power plant will dwarf Solar Two. More than 17,000 heliostats—each mirror is 24 feet by 28 feet—will form a circle around a 538-foot-tall concrete tower. Atop the tower will sit a 100-foot receiver filled with 4.4 million gallons of liquefied salt.

When the sun rises each morning, the heliostats will focus their rays on the receiver, heating the salt to 1,050 degrees Fahrenheit. The hot salt will flow into a steam generation system that will drive a conventional turbine housed in a power block. After the sun sets, the salt will retain heat which can be used to generate electricity when demand spikes.

“The California utilities have peak demand from 1 p.m. until 8 p.m. so we are designed to run at 100 percent capacity during the full peak period into the evening,” Kevin Smith, SolarReserve’s chief executive, wrote in an e-mail message. “In addition, because of the storage capabilities, the facility is flexible enough to accommodate other requests from the utility after the sun goes down provided we understand the requests in advance.”

By being able to tap solar electricity on demand, utilities—at least those in the Southwest—could forgo spending billions of dollars on fossil fuel power plants that are fired up only a few times a year to prevent blackouts when everyone turns on their air conditioners on a hot day.

The Rice project is to be built on private land that is the site of a World War II-era Army airfield near the desert ghost town of Rice.

I happened to visit the site in late 2007 with an executive from Silicon Valley solar startup Ausra, which was shopping for land for solar power plants. Old artillery shell casings litter the desert scrub and you can still see the outlines of old runways. A massive concrete tarmac now serves as a parking spot for snowbirds’ RVs.

Ausra, an early player in the solar power plant business, has since dropped out, electing to focus on supplying solar thermal technology to developers rather than building its own projects.

With the Rice Solar Energy Project, SolarReserve is on the launch pad. Now it just needs to prove its salt.

Category: Energy Matters

Climate change puts us all in the same boat. One hole will sink us

DC Arc Faults and PV System Safety

An Exclusive Look at the New Siemens 3-MW Direct Drive Turbine

Designs for new UK nuclear reactors are unsafe

Designs for new UK nuclear reactors are unsafe

Major setback for nuclear energy plans as watchdog’s report finds flaws in US and French models

Solar’s rapid evolution makes energy planners rethink the grid

SolarReserve’s 24/7 solar plant