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Ethiopian Wind Farm Adds Five Percent of Country's Total Electricity Capacity

The 120-megawatt, 84-turbine Ashegoda Wind Farm in Ethiopia opened this week in an arid region about 765 kilometers from the capital, Addis Ababa. The farm was completed in three phases and has actually been generating power for some time now, but was formally inaugurated by the prime minister on Saturday.

Those 120 MW actually represent about 5 percent of Ethiopia's entire installed electricity generating capacity based on the Energy Information Administration's latest data (and a more recent interview with the head of Ethiopia's state-run utility). Scaling up Africa's energy supplies is considered an enormous priority for helping to draw many millions of people out of poverty, and doing so with renewable energy is a no-brainer. Ethiopia alone has an estimated wind power potential of more than 1000 gigawatts (roughly the installed electricity capacity of the United States, from all energy sources). And while only a few projects are in the works in that country, an African Development Bank study from earlier this year reported that about 10.5 gigawatts of wind power currently in the pipeline across the continent.

The big controversy with electricity expansion in Africa relates to another renewable resource: hydroelectric power. Ethiopia already gets 90 percent of its existing electricity from dams, a source obviously fraught with environmental concerns of its own. And the country is moving ahead on a truly massive project, the Grand Ethiopian Renaissance Dam, which, at nearly 6000 MW, will triple the country's total capacity. Egypt has concerns that the dam, which will create a massive reservoir on the Blue Nile, will affect the downstream flow of the Nile to an extent that will affect both its own power supply and cause other water-related issues.

And then there's the ever-present threat of the Grand Inga Dam, a hydroelectric behemoth still under consideration on the Congo River. If built to its full capacity, it would be nearly double the size of the biggest hydroelectric project on the planet, China's Three Gorges Dam, at around 40 000 MW. The latest news on that project has construction for pieces of it beginning in 2015.

The quick-hit potential of such massive electricity development is hard to resist in a continent where 500 million people lack access to power. But it is exciting as well that wind power projects like the one in Ethiopia are starting to take hold, along with the ever-present potential of Saharan solar power. And the money for these projects is starting to flow as well, highlighted by U.S. President Barack Obama's announcement earlier this year of a US $7 billion grant for the Power Africa project; much of that cash will go toward renewable energy projects.

Photo: Kumerra Gemechu/Reuters

California's First-in-Nation Energy Storage Mandate

California has adopted the United States' first energy storage mandate, requiring the state's three major power companies to have electricity storage capacity that can output 1325 megawatts in place by the end of 2020, and 200 MW by the end of next year. The new rule issued by the California Public Utilities Commission (CPUC) will be key to implementation of the state's ambitious renewable portfolio rules, which calls for 33 percent of delivered electricity to come from renewable sources by 2020 and virtually guarantees that California, along with Germany, will remain in the world vanguard of those aggressively building out wind and solar.

[Editor's note: For an explanation of why the mandate is expressed in units of power instead of energy follow this link.]

By common expert consent, wind and solar can only reach their full potential if storage is provided for, as otherwise little-used generating capacity must be held in reserve for the times the wind does not blow and the sun does not shine. California's landmark rule was written by Commissioner Carla Peterman, newly appointed to the CPUC late last year by Governor Jerry Brown.

"This is transformative," Chet Lyons, an energy storage consultant based in Boston, told the San Jose Mercury News, the state's most tech-savvy newspaper. "It's going to have a huge impact on the development of the storage industry, and other state regulators are looking at this as a precedent."

Though the new rule was adopted by the five CPUC commissioners unanimously, two expressed concerns about the strorage mandate's being achieved at reasonable cost to consumers, especially as large pumped storage (hydraulic) facilities do not qualify. There are a wide range of technologies that do qualify, including batteries and flywheels, but costs are generally high. Pike Research has concluded that the United States as a whole could have as much as 14 GW from storage by 2022, but only if storage costs come down to the vicinity of to about $700-$750 per kilowatt-hour.

This post was modified on 7 November for clarification.

Photo: PG&E

China to Invest in Britain's Nuclear Sector

Stranger things have happened in the world of electricity restructuring and deregulation. Five years ago, when the Philippines privatized its national transmission organization, the winning consortium included the State Grid Corporation of China, an organ of the PRC’s communist state. Around that same time, some residents of Brooklyn, N.Y., (this writer among them) were dismayed to discover that they were now buying their natural gas not from a trusted local company but from the operator of a faraway country’s electrical transmission system. The company in question, National Grid of the U.K., was created after Margaret Thatcher’s Britain “unbundled” electricity and sold much of the world on the idea of competition in electric power.

But late last week, Britain’s Chancellor of the Exchequer—the country’s finance minister—announced during a visit to a nuclear power plant in China that the tables have turned. Apparently, Chinese companies will now be welcome to take stakes in nuclear power projects in Britain and eventually even take majority ownership. And according to the New York Times, French power utility Electricité de France (EDF) confirmed today it has has gotten the go-ahead from the U.K. government to build the proposed Hinkley Point C plant in Somerset, UK [illustration, above]. The facility, which will be the first new nuclear power plant to come on line in the country in almost 30 years, is expected to cost £16 billion (about US $26 billion). EDF's partners in the venture include China’s General Nuclear Power Corporation and the China National Nuclear Corporation. The two Chinese entities will together hold a stake totaling between 30 and 40 percent of the project, says the New York Times.

The Financial Times previously reported that the agreement might be the impetus for British companies such as Rolls Royce and International Nuclear Services to invest and participate in Chinese nuclear power projects.

In contrast to some continental European countries like Germany, Austria, and Italy, the British government wishes to stick with nuclear energy and pave the way for a second generation of atomic power plant construction. Its philosophy and approach is essentially similar to that of the current U.S. government’s. But whereas the Obama administration has provided big loan guarantees for two new nuclear projects in the U.S. Southeast, the British government eschews direct subsidies and instead will set a price floor for electricity generated by nuclear power plants.

In all, the official British plan calls for construction of 12 new nuclear power plants by 2030, to replace or supplant the 15 facilities currently operated in the UK by EDF. Britain’s so-called “strike price” for nuclear electricity is expected to be set at £92.5 per megawatthour (roughly 15 U.S. cents per kilowatthour), which is reportedly about double the current average wholesale price in the UK. The strike price approach appears to be a way of protecting the British government and public against cost overruns and delays like those that have plagued EDF’s initial second-generation reactor project at Flamanville, France. If the government were subsidizing Hinkley directly and things started going wrong, it would be tempted to throw good money after bad; the strike price basically tells the industry it can expect so-and-so much return from the project but no more—if something goes badly, that’s the builders’ problem, not ratepayers’.

Illustration: EDF Energy

X-Rays Shed Light on How Li-Ion Batteries Fail

Standard lithium-ion batteries, like the ones in everything from your cell phone to your plug-in electric vehicle, have electrodes that contain intercalation compounds. They are capable of charging and discharging without substantial change in volume or structure, but are limited with regard to energy density. Recently, much work has been done on battery materials with significantly higher energy densities, but these materials typically degrade extremely quickly. Now, for the first time, researchers have found a way to see clearly what is really happening inside the electrodes that leads to that short lifespan, potentially opening a way to engineer our way around the problem. They published a study Thursday in the journal Science.

Using the tomographic x-ray microscopy beam (TOMCAT) at the Swiss Light Source, researchers showed that a tin-oxide electrode expands during charging thanks to an influx of lithium ions. That influx-induced increase in volume turns out to cause irreversible damage by forming cracks within the electrode particles. Martin Ebner, one of the study authors and a PhD student at ETH Zurich, said in a press release that the crack formation is not random; the cracks form at spots where defects already exist. During discharge, the tomography imaging showed that the volume does decrease, but the cracks prevent the electrode from returning to its initial state. The image above shows the tin oxide particles undergoing such structural deformation during charge and discharge.

Specifically, the electrode they measured started life at 50 micrometers, and expanded more than 100 percent to 120 µm during charging; it then shrank back to only 80 µm. The average particle volume fraction, meanwhile, decreased back to a level below where it started, which the authors write implies the polymer binding the particles and the conductive matrix are distorted after just the one charge. "This distortion of the conductive matrix, together with particle fracture, is known to electrically disconnect particles from the rest of the electrode leading to capacity loss," they write.

Importantly, this technique could be repeated using other materials, potentially leading the way to better batteries in general. "Visualizing batteries in operation was essentially impossible until recent advances in x-ray tomography," said senior author Vanessa Wood, also of ETH Zurich. The researchers conclude that "the type of quantitative three-dimensional, and time-resolved images of particle lithiation introduced in this work will provide the experimental data necessary to comprehend the complex electrochemical and mechanical interactions in silicon and related materials."

Photo: Martin Ebner/ETH Zurich

Higher Electricity Costs Raise Alarm Across Europe

British government predictions of sharply increased electricity prices in the next decades are getting renewed attention these days, as the country's opposition leader Ed MIlliband promised to freeze rates if elected prime minister. A March report from the Department of Energy and Climate Change found that with current policies subsidizing green power, electricity costs will rise 33 percent by 2020 and 41 percent by 2030.

In Germany, according to reports issued this month by IHS Inc. in Denver, Colo., green energy developers received $19 billion in subsidies last year, six times the comparable figure for the UK. Germany has pushed low-carbon and renewable energy technology harder than any other European country, with impressive results: Last year it produced 22 percent of its energy from "green" sources, five times as much as twenty years before. But the costs of those green advances have proven to be unsustainably high, from a political point of view.

In Germany's feed-in tariff system, developers of green technologies are guaranteed specific rates of return well into the future, with the costs of those subsidies distributed among all ratepayers, nationwide. Those subsidies are putting a heavy burden on the country's less well-off ratepayers and threatening economic growth, at least as industry sees it. Figuring out how to redistribute those burdens without sacrificing the green policies themselves is a major element in negotiations to form a new government in Germany, which are expected to be protracted.

On Oct. 10, the chief executives of ten energy companies accounting for half of Europe's electricity production called for an end to subsidies for wind and solar power. They also called on Europe to develop a system to reward companies that maintain standby reserves, to compensate for power shortfalls when the wind doesn't blow or the sun doesn't shine. Industry leaders complain that the growing shares of wind and solar have undercut their revenues from baseload coal and nuclear while requiring them to maintain surplus capacity.

The companies are not going to see an end to green subsidies, but some kind of reform is plainly needed. Across Europe, the cost of electricity to homeowners has increased 17 percent in the last four years, and to industry, 21 percent. How to minimize those costs without giving up the objectives of reducing dependence on fossil fuels and cutting greenhouse gas emissions? it's rather like squaring the circle.

In England, the government's "contracts with difference"s program, which is roughly similar to Germany's feed-in tariff system, is not expected to take a hit. Instead, ironically, opposition critics are taking aim at programs encouraging better energy efficiency, according to the Financial Times.

 

 

Huge New Solar Thermal Plant Can Keep Running for Six Hours After Sun Goes Down

The Ivanpah plant in the Mojave may have recently snatched away the title of "world's largest," but Abengoa Solar's Solana plant in the desert near Gila Bend, Arizona, still has its share of superlatives. At 280 megawatts, Solana is one of the largest plant using parabolic mirrors in the world, and it is undoubtedly the largest to use substantial thermal storage to keep the juice flowing for hours after the sun goes down. Intermittency is still among the most common complaints about industrial-scale renewable energy, so proving that this storage tech can work is a huge step for the solar industry.

Abengoa announced on Wednesday that the Solana plant "passed commercial operation tests." The first of these involved running the plant's generator at full power while also ramping up the thermal storage system. Next, after letting the solar part of the plant stop once the sun was down, operators fired up the generator and produced electricity for six full hours using only the thermal storage system. Intermittency, you matter not here.

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Tesla's Lithium-Ion Battery Catches Fire

Tesla seems to make news at every turn. Most of this year's headlines about Tesla's Model S have been high praise, but this week, one Model S was in the spotlight for another reason: catching fire.

On Tuesday, a Tesla driver in Washington State drove over some metal debris on the highway, according to a report in The New York Times. The driver turned off the freeway and then the car caught fire. Elizabeth Jarvis-Shean, a spokesperson from Tesla, confirmed that one of the 16 modules that make up the Model S battery pack caught fire after direct impact with a large metal object. Earlier this year, the U.S. National Highway Traffic Safety Administration gave the Tesla Model S a 5-star safety rating (its highest) in all categories.

The video below captures the fire, in which a man in a passing car exclaims, "oh, that's a Tesla dude!" (Warning: video contains coarse language.)

“No one was injured, and the sole occupant had sufficient time to exit the vehicle safely and call the authorities,” Jarvis-Shean said in a statement on Wednesday. “Subsequently, a fire caused by the substantial damage sustained during the collision was contained to the front of the vehicle thanks to the design and construction of the vehicle and battery pack.”

After the fire was extinguished by the fire department, it reignited and was “difficult to extinguish,” a fire department official told The New York Times.

Lithium-ion batteries, the primary choice for electric vehicles, are known for their potential to catch fire, although the incidences are rare. Last year, a Chevy Volt caught fire a few days after being crash tested. The problems are not limited to cars. Earlier this year, Boeing’s 787 Dreamliner was grounded after fires in the plane’s lithium-ion battery.

Although fires involving lithium-ion batteries receive the bulk of the headlines, there are far more fires involving gas stations and conventional combustion engines each year. Between 2004 and 2008, the U.S. National Fire Protection Association reported an average of about 5000 fires per year in and around gas stations. From 2006 to 2010, there were roughly 152 000 automobile fires annually, on average.

Even if fires in electric vehicles are relatively rare, it is still a black mark on an emerging industry. Tesla was named the Motor Trend 2013 Car of the Year, but its stock price was trading at about $173 on Thursday after opening at $190.15 on Wednesday.

Tesla said it is investigating the fire.

 

Photo: AJ Gill/YouTube

What Is the Actual Status of Carbon Capture Technology?

The U.S. Environmental Protection Agency's (EPA's) long-expected rules for carbon emissions from new coal-fired power plants have thrown into sharp relief the question of whether carbon capture and sequestration or storage (CC&S) can be described as "demonstrated" and ready for commercialization. This is because the new regulations declare, in effect, that no new coal plant can be built without CC&S.

The EPA is reported to have alluded to four CC&S plants and projects in connection with its coal regs—in California, Mississippi, Texas, and Saskatchewan, Canada—though I cannot find that statement in the press release, technical backgrounders or detailed report on regulatory impacts issued with the new coal regs on 20 Sept. But surely the most substantial and furthest along of the U.S. projects is the IGCC plant that Southern Company is building in Kemper, Mississippi [photo].

Integrated gasification combined-cycle technology involves coal gasification and then the separation of carbon dioxide from other flue gases, including those containing nitrogen. Can Kemper be considered a demonstration of a technology ready for commercialization? By no stretch of the imagination. The plant is being built with a $270 million contribution from the U.S. Department of Energy. And Southern Company has issued a statement saying the Kemper technology "cannot be consistently replicated on a national scale."

DOE originally hoped to see IGCC tested and demonstrated at a plant to be built near Tampa, Florida, but the local utility lost interest. The Energy Department thereupon helped get the demonstration transferred to Mississippi. The government subsequently changed horses mid-race. FutureGen, which was to have sponsored the major U.S. demonstration of IGCC, collapsed toward the end of George W. Bush's presidency. The Obama administration decided early on to resuscitate the project, but switched to an alternative technology known as oxycombustion or oxyfiring. (In oxyfiring, nitrogen is removed from air pre-combustion, which simplifies separation of carbon dioxide post-combustion.) The change suggested that IGCC was suffering some loss of confidence at Obama's DOE as well.

Outside North America, the important work being done on CC&S is also pre-commercial. Norway and its national oil company, Statoil, having declared in the past that depleted North Sea oil fields contain enough storage capacity to sequester all the carbon dioxide emitted from European power plants, have a major R&D facility at Mongstad. On 23 Sept., however, the government and Statoil, while reaffirming their commitment to research there, pulled the plug on upgrading Mongstad to commercial-scale.

Sweden's national utility Vattenfall has been testing oxycombustion technology at a power plant it owns in eastern Germany, at Schwarze Pumpe. As described in an MIT summary, "Vattenfall announced in November 2009 that it was achieving nearly 100 percent CO2 capture at Schwarze Pumpe. As of the beginning of June 2010, Schwarze Pumpe has now been in operation over 6500 hours during the last one and a half years… Vattenfall is continuously rebuilding and developing this unit." Vattenfall plans to continue operations for ten years.

All that is well and good, but of course it does not add up to having a demonstrated technology ready for commercial deployment.  Five years ago, Spectrum declared Schwarze Pumpe a "winner," not because it necessarily would lead to a usable technology, but because Vattenfall at least was trying seriously to find one.

Photo: XTUV0010/Wikipedia

 

 

 

DOE Maps Path to Huge Cost Savings for Solar

The price of a solar photovoltaic module has dropped dramatically over the last few years. But to get solar installations down toward ideal price points, the cost of making the panels isn't the only thing that needs to come down: so-called "soft costs" represent half or more of most solar installations. These costs include permitting, labor, inspection, interconnection (if you're going grid-connected, at least), and others, and the U.S. Department of Energy's National Renewable Energy Laboratory (NREL) thinks we can cut those down to size as well.

In a new report, NREL maps out a way to bring soft costs down from $3.32/watt in 2010 for a 5-kilowatt residential system to $0.65/watt in 2020. For small commercial systems below 250 kW, the report suggests a drop from $2.64/watt in 2010 to $0.44/watt in 2020. These soft cost reductions would allow the U.S. to reach the Department of Energy's SunShot Initiative goals of $1.50/watt and $1.25/watt for residential and commercial installations, respectively.

But first, the bad news: if the current trajectory of soft costs continues, those SunShot goals will not be met. Achieving the extra cost reductions necessary to get there won't be trivial, especially for residential installations—in fact, an additional $0.46/watt is needed beyond the current trajectory, a sizable amount when we're gunning for $0.65/watt in total. Financing and customer acquisition costs are most likely to get there without much help, while permitting and interconnection need some help. That help could take the form of streamlined inspection processes and a standardized permitting fee that is substantially lower than what currently exists. The average permitting fee now, though it varies widely across jurisdictions, is $430; NREL suggests bringing that to $250 across the board.

Commercial systems, meanwhile, need only $0.11/watt beyond current trajectory in order to achieve the SunShot goals. Labor costs may come down easier than with residential systems; the report suggests that universal adoption of integrated racking, where modules arrive at a site already assembled and ready for installation, is one method for dropping costs in the right direction.

In general, soft costs are increasingly recognized as perhaps the primary barrier to bringing solar prices down into the truly competitive range. And that seems to go for manufacturing of solar panels as well as for installations: A recent paper in Energy and Environmental Science compared costs of solar manufacturing in China and the U.S., and found soft costs including labor and supply chain are the biggest differences. If the U.S. wants to keep up with the world's biggest solar manufacturer, working on those costs unrelated to materials is a good place to start. And they better hurry: the cost of building a PV module at major companies in China is going to drop all the way to $0.36/watt by 2017, according to one recent report. With module prices continuing that sort of decline, focusing on the soft side of solar is getting more and more important.

Photo: Tim Boyle/Bloomberg/Getty Images

Is Energy Efficiency the Most Popular In-Home Automation?

A new study from the Consumer Electronics Association found that energy efficiency technologies are the most popular amongst home automation options in American houses.

Programmable and/or smart thermostats beat out home security and entertainment automation for the top honor, with 47 percent of households saying they had at least one.

The findings, which come from an online survey of about 1000 people, would seem to be a win for energy efficiency. But most of the homes had programmable thermostats, which are often used incorrectly, if at all.

One study from Lawrence Berkley National Laboratory [PDF] found that 89 percent of survey respondents rarely or never used the thermostat to set a weekday or weekend program. Seventy percent were not set at all.

Programmable thermostats have been around for more than 30 years, but a new generation of smart thermostats that connect with smartphones and the Internet make programming far easier. Not only is the interface easier to use but some have algorithms that can learn your household thermal characteristics and daily patterns to help fine-tune settings.

The energy savings for software-based, digital thermostats range from about 15 to 30 percent. But such smart thermostats are still in the minority, with only 12 percent of CEA respondents saying they had one, and even then it was often in conjunction with older thermostats in the home. When old-school programmable thermostats are taken out of consideration, automated home security becomes the most popular technology choice. 

The survey found that saving money was a key motivator when it comes to energy efficiency products, but most people don’t save anything with their programmable thermostats, and the smart thermostat market has been emerging slowly in the past few years despite the potential savings. Energy efficiency has historically been a hard sell, even if it makes sense financially over the long run.

The first generation of two-way digital smart thermostats was often sold through utility channels and the cost was too high. But with the proliferation of smartphones and lower costs, smart thermostats have started to catch on.

The recent popularity has also come from smart-thermostats makers partnering with other players, particularly home security companies and service providers, both of which want to provide end-to-end home automation services for a monthly fee.

Even Nest Labs, which has a smart thermostat that works on a proprietary system, has partnered with some utilities and just launched an application programming interface (API) for developers that want to create smart home apps that run on top of the thermostat. It is also reportedly developing a smoke detector as its second connected home product.

It’s hard to say if a smart smoke detector is the next wave in home automation, and the CEA survey gave mixed signals in terms of what segment will grow the fastest. The study found safety and security are the building blocks of home automation packages, with climate, lighting and appliance controls viewed as “very desirable” but not critical. But the survey also found smart and programmable thermostats were the items that people expressed the highest purchase intent for within the next two years.

Even though connected home offerings are growing, and everyone from your cable provider to your local big box store is selling them, CEA found most consumers still don’t think they have a need for the products. But for products that can provide convenience, peace of mind and a cool factor—just as a smartphone does—the sky could be the limit.

 

Photo: Randi Klett

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