Posts Tagged ‘original reporting’
Senate bill aims to appraise value of home efficiency
For appraisers, it may not matter how green your house is. (Photo by Sean Marshall via Creative Commons)
Say you were getting ready to put your home on the market and wanted to make a quick investment to boost the selling price.
Would you be better off buying a granite countertop for your kitchen, or an ultra-efficient furnace that would lower heating bills by hundreds of dollars every year?
The answer in almost every case is going to be the granite countertop.
The reason is that appraisers rarely consider energy use when determining a home’s value. Two homes that are identical except for energy efficiency are likely to be appraised for the same amount.
That makes it difficult for home builders and sellers to recoup the cost of efficiency improvements, even when they would clearly benefit buyers.
A coalition of builders, business groups and efficiency advocates is now lobbying to change federal underwriting guidelines so that energy use becomes a factor.
A bipartisan bill called the Sensible Accounting to Value Energy (SAVE) Act was introduced in the U.S. Senate Banking, Housing and Urban Affairs committee in October.
The legislation would require lenders to consider energy costs as well as the mortgage when determining whether a borrower can afford the monthly payments.
For homes with below-average energy costs, appraisers would be instructed to add the net present value of those savings to the appraised value of the home. Savings would be estimated using a U.S. Department of Energy formula, or calculated in an optional, “qualified, independent” energy audit.
The rules would apply to any loans issued, insured, purchased or securitized by the federal government — about 90 percent of all new loans.
Appraisers are allowed to incorporate energy efficiency into home values, but in practice it rarely happens, says Cliff Majersik, executive director of the Institute for Market Transformation, one of the SAVE Act’s main supporters.
Home appraisers need to churn through a lot of work quickly to make a living, and calculating efficiency is something that normally gets skipped over. Plus, appraisers aren’t trained energy auditors.
When a seller seeks a higher price because of efficiency, the lender’s appraisal often won’t cover that premium, leaving it up to the buyer to come up with the difference in cash.
“That’s a real problem” for buyers, who often can’t afford the extra down payment, says Majersik. And for builders and sellers, it creates a disincentive.
“They don’t want to invest in energy efficiency in their homes because they’re worried when they go to sell it they won’t recoup that investment,” he says.
The SAVE Act aims to eliminate that problem. Builders and sellers could be assured that the value of efficiency would be reflected in appraisals, and buyers will be more easily able to qualify for loans.
Jim Petersen, research and development director for Michigan-based Pulte Homes, the nation’s largest home builder by sales, says the SAVE Act could help resolve some of the opposition among builders to energy code updates.
“As the energy codes increase, new homes are on an unlevel playing field with existing homes,” says Petersen. “We have to put in better furnaces, better windows, better insulations, etc., etc., but the current mortgage process gives no value for all of those items.”
Energy code updates have added costs for builders, but it’s a tough sell for builders to convince buyers or their lenders that the added efficiency justifies the higher price, which is why the SAVE Act is needed, says Petersen.
The law would also allow existing home owners to pay for energy projects through refinancing, making it a potential alternative to property assessed clean energy, or PACE, financing in some cases, says Majersik.
The Institute for Market Transformation and the American Council for an Energy Efficient Economy (ACEEE) estimate the act would create 83,000 jobs and $1.1 billion in energy bill savings by 2020.
Other supporters of the legislation include the U.S. Chamber of Commerce, the Leading Builders of America, the Appraisal Institute, and the U.S. Green Building Council.
Are we flushing a heat source down the drain?
(Photo by Evan Long via Creative Commons)
A northern Minnesota start-up company wants to recover a waste heat source that’s currently flushed down the drain.
Hidden Fuels of Brainerd, Minnesota, is trying to develop a municipal sewer heat recovery system, which would heat buildings using warmth from the city’s sewers — minus the stench.
Jeff Aga, one of the company’s principals, said it would work similar to geothermal, but that sewers have an advantage of warmer starting temperatures than ground wells.
“We did some tests throughout their system and found where there’s good heat that can be captured,” Aga said.
The company placed temperature sensors throughout the city’s sewer system as part of a 16-month, federal stimulus-funded feasibility study that was completed in January. They found temperatures ranged from 38 to 78 degrees, but were mostly between 45 and 60 degrees. The warmest temperatures were found near a commercial laundry facility.
Aga said they’ve identified the police department as a good potential customer for the system, which might also be able to heat the local high school and a nearby apartment high rise.
“The fact that no one else has really thought about tapping into that until we did this study, I thought, was kind of fascinating,” says Scott Sjolund, technology supervisor at Brainerd Public Utilities, which sponsored the study after the city was approached by Hidden Fuels.
The company believes the system would be the first of its kind in the United States, though Vancouver built something like it as part of its 2010 Olympics village. The New York Times reported that the Vancouver project was the first district energy system in North America to draw heat from untreated wastewater, and that three others existed in Oslo and Tokyo.
The fact that so few systems exist is probably a sign of their challenging economics, said John Whitehouse, vice president of business development for Recycled Energy Development, an Illinois company that designs, builds, owns and operates cogeneration and waste heat recovery projects around the country.
“Unless you have really high energy prices, it’s going to be a hard sell,” Whitehouse said of the concept in general.
Low natural gas prices mean the payback time is likely to be long, he said. That’s especially true for projects that will involve retrofitting buildings rather than incorporating systems into new construction.
And while there is heat in sewers that’s technically recoverable, “there’s just not that much there,” Whitehouse said. His company normally looks for opportunities where the temperature is at least 180 degrees.
Hidden Fuels has presented the results of its feasibility study at public meetings in Brainerd. Next, it hopes to find funding to build a system at the police station.
Smoothing out the bumps of compressed-air storage
The University of Minnesota has licensed a new technology that could be used to smooth out many of the peaks and valleys in wind and solar power generation.
The invention, by mechanical engineering professor Perry Li, is a method for setting up a compressed-air energy storage system that releases energy at a constant rate.
Compressed-air energy storage typically involves using excess electricity to pump air into an underground cavern. When electricity is in higher demand, the airflow can be reversed, spinning a set of turbines with a stream of air as the container depressurizes.
One drawback is that the intensity of the energy released constantly declines. It’s like filling balloons with a helium tank. As the tank empties, it gradually takes longer to fill each balloon.
There’s inefficiency and variability in that type of system — two qualities that are undesirable when it comes to managing an electricity grid.
Li came up with a configuration for an above-ground storage system, using a set of tanks and vessels, in which the pressure inside stays nearly constant, which means the energy output stays consistent, too.
“It’s really about the configuration — how you put it together,” says Li. “The idea is to allow the system to operate at more constant pressure, rather than at varying pressure. That’s the key to the invention.”
Li imagines the systems could be installed on individual wind turbines, where they could regulate the electricity output to a rolling eight-hour average.
The project, which was funded by the National Science Foundation, started out as a search for storage solutions for hydraulic hybrid vehicles, which capture energy from braking and store it in a vessel containing pressurized fluid.
What they came up with, however, appeared to be better suited for larger energy storage systems instead of vehicles, so Li turned his attention to wind and solar applications.
The technology has been licensed to SustainX, a New Hampshire company that’s developing above-ground isothermal compressed-air energy storage systems.
For those who want to delve into the technical details, you can find the patent information here.
Wind’s ‘modular’ advantage over power plants
Photo by PGE via Creative Commons.
In the ongoing conversation about how renewable portfolio standards affect electricity prices, it’s important to keep in mind that building any new generation source, whether wind or fossil fuel, is going to create new costs for electricity customers.
Wind power investments can be spread more gradually, though, giving them a potential advantage over large, conventional power plants.
Last week I spoke with Dr. Harold Kung, a chemical and biological engineering professor at Northwestern University. He’s author of a paper titled “Impact of deployment of renewable portfolio standard on the electricity price in the State of Illinois and implications on policies,” published this spring in the journal Energy Policy.
“Any time you put a new capital investment in, it costs money, and you have to pass that cost onto your consumer,” Kung said.
Illinois created a renewable standard in 2008 that requires large utilities to generate 25 percent of electricity from renewable sources by 2025, with three-quarters of that coming from wind power.
The cost of building wind farms to meet the policy’s benchmarks in 2012 will lead to as little as a 2 percent premium on electricity bills, according to Kung’s paper. By 2025, wind farm construction could lead to anywhere between a 20 and 50 percent price increase.
Harold Kung, Northwestern University
Kung’s paper evaluates the different options policymakers have to buffer those impacts on Illinois consumers. His analysis favors investment tax credits, rather than production tax credits, as a more effective tool for lowering retail wind electricity prices.
What’s beyond the scope of Kung’s paper is how those wind costs compare to what utilities would have spent maintaining the status quo. I asked him why it’s been so tricky to pinpoint precisely how much these policies are contributing to electricity prices.
One reason is that answer depends on how fast the economy grows, Kung said. When the economy grows, electricity use usually goes up with it, forcing utilities to spend money on new power plants.
If utilities have to invest in new generation sources anyway, then the relative cost of wind power compared to fossil fuel sources becomes more negligible, or even non-existent in some cases.
Under normal economic growth, in which utilities might see electricity demand increase 1 or 2 percent per year, Kung said, wind has an often overlooked advantage in that you can build up capacity a few megawatts at a time.
“It’s very easy to slowly build it up, so that the capital investment is much less intensive than a big conventional power plant,” Kung said.
When a utility builds a large conventional power plant, they build it to meet a region’s long-term needs. It can take several years for demand to grow into the new plant’s size. As a result, there’s a “temporary excess capacity” during those year, Kung said.
And that’s an added cost to customers. It’s like a college student paying to live alone in a three-bedroom house because they expect to have a family someday.
“[I]n order to realize the benefit of the economy of scale, large-capacity power plants would be built that would result in temporary excess capacity,” Kung’s paper says. “On the other hand, wind electricity capacity is much more modular in nature, making it much easier to match capacity to need.”
A wind farm’s capital costs, from acquiring land to buying turbines and other equipment, accounts for vast majority of the cost of the power it produces. Policymakers who want to minimize the cost to consumers of complying with Illinois’ renewable standard should focus on capital costs, Kung’s paper concludes.
A 30 percent investment tax credit is more effective than a $0.022 per kilowatt hour production tax credit in lowering retail wind electricity prices, he concludes.
“The analysis shows that the capital cost dominates the electricity price, and changing the capital cost, either through technology changes, market pressure, or government incentive (in the form of [investment tax credit]) will have a large impact on electricity price.”
Some co-ops seek a pass on Minnesota planning rules
Dairyland Power's service area covers parts of Wisconsin, Minnesota, Iowa and Illinois.
A bill advancing through the Minnesota Legislature would exempt two rural electric cooperatives from having to report their plans for maintaining reliable, low-cost power to customers.
“It’s a just a very burdensome regulatory filing,” said State Rep. Rich Murray, a Republican who represents a southeastern Minnesota district served by Dairyland Power Cooperative members.
Murray said Dairyland officials approached him about their problems with Minnesota’s Integrated Resource Plans, long-range planning documents that utilities need to file every couple of years. The plans include the utilities’ forecasts for electricity demand, as well as an detailed explanation of how it plans to provide that power in a reliable, cost-effective way.
Basin Electric Power Cooperative would also be exempt if the legislation passes.
The bill doesn’t specifically name either cooperative. Instead it says generation and transmission co-ops whose distribution customers are at least 80 percent outside of Minnesota and whose retail electricity sales represent less than 5 percent of Minnesota’s annual total would no longer be required to file resource plans.
State Sen. Dan Sparks, a Democrat from Austin, Minn., is co-sponsoring parallel legislation.
The Minnesota Department of Commerce, which receives the reports, declined to make an official available for comment Wednesday afternoon, but a spokesman issued a statement saying the plans are an important tool:
“The Minnesota Department of Commerce has been working closely with Basin and Dairyland on an ongoing basis to address their concerns with Integrated Resource Plan (IRP) reports. We will continue those efforts, but have significant concerns about HF2747, which would exempt Basin and Dairyland from IRP reporting requirements,” the statement says.
“If approved, this exemption could impact electric reliability in our state and have a broad potential impact on all Minnesota ratepayers. IRP reports provide Minnesota regulators with key information needed to ensure that all utilities serving Minnesota have adequate generating resources to meet their customers’ needs.”
Murray said he would like the Commerce Department’s Energy Resources division to work with Dairyland to come up with a “more reasonable” reporting requirement. He disagrees that the state or ratepayers will be put at a disadvantage without the plan.
“The amount of electricity that the two coops here bring into the state of Minnesota is within the margin of error on these reports,” Murray said.
Dairyland serves two dozen electricity distributors in four states, with its largest customer base being in Wisconsin. Other states include Iowa and Illinois. Less than a fifth of its distribution is in Minnesota, but 85 percent of the time its planning department spends on regulatory reports is spent on Minnesota’s resource plan, according to Kenric Scheevel, Dairyland’s senior governmental relations representative.
The cooperative has been filing resource plans with Minnesota regulators since 1995, but Scheevel said they became more burdensome around 2005 when the state started requesting the raw data that went into its forecasts so that the department could attempt to replicate its results.
“We just don’t understand why Minnesota wants to go that route,” Scheevel said. Other states it does business in require the demand forecasts, but not all of the data that goes into making them. In Minnesota, “it appears there is so much emphasis being put on verifying the methodology.”
Compiling that information requires collecting and organizing data from all of its member cooperatives, he said.
A review of the public utilities commission docket for Dairyland’s most recent resource plan suggests a history of late, incomplete and messy reporting by the cooperative, as well as a hint of strained patience from regulatory staff.
A November 2011 briefing document describes how on September 8, 2011, one week after its deadline for filing an integrated resource plan, Dairyland submitted several separate documents that included nontechnical summaries and numerous spreadsheets.
Commerce Department reviewers noted that they were unable to locate the results of Dairyland’s supply and demand scenario modeling. They also flagged a number of “deficiencies” in the cooperative’s spreadsheets.
Also missing: page numbers. For the second time in a row. The Minnesota Public Utilities Commission issued an order during the co-op’s 2008 resource planning process asking it to refile that report with page numbers.
“Not having page numbers on portions of its filed documents makes it very difficult for commenters to refer the Commission to specific portions of the plan, and in addition makes it difficult for the Commission to refer to portions of the plan when issuing a decision on the plan,” the document states.
Murray’s bill passed a committee hearing Wednesday. Now it’ll be up to the full Legislature to decide whether to give the co-ops a pass.
Readers react to Minnesota 100% renewable report
What a 100-percent renewable electricity system in Minnesota might look like on a week in January.
Monday’s post, “Could Minnesota get by on 100 percent renewables?,” has generated quite a few comments. A report released this week by the Institute for Energy and Environmental Research (IEER) claims the state could meet all its electricity needs through wind and solar, provided they were matched with the right mix of energy storage and efficiency improvements. I decided to check back in with Arjun Makhijani, IEER’s president and senior engineer, and ask him to respond to some of your questions and comments.
PwrSavy commented “As I understand it, if you’re relying on typical [compressed air energy storage]; they couple with combustion turbines when supplying energy, so this is not a ’100% Renewable’ scenario… unless that is you’re burning some kind of biofuel.”
On this point, the reader is correct, says Makhijani. The scenario described in IEER’s report actually does rely on a small amount of natural gas for generating power from the compressed air energy storage. The amount of natural gas used in generating from compressed air storage is about one fifteenth the amount of gas used in a conventional natural gas combustion plant.
“The amount of natural gas is so small that I believe it could be replaced with biogas,” says Makhijani.
Another option that could become economical at some point is pairing compressed air storage with hydrogen powered generation.
Mary is alarmed about how expanding commercial wind farms in the state could affect bats and birds. “If we pepper this state with the turbines required to produce enough energy to provide for households alone, we will have an environmental disaster of biblical proportions down the road,” she writes.
Makhijani says improved turbine design has largely resolved the problem of bird collisions at newer facilities. He thinks the bat issue is a bigger problem and one that we need to pay attention to. He hopes that careful siting of wind farms might help reduce the impact.
“I think wind farms should be carefully sited, and I think we do have the luxury of doing that in Minnesota because the available resources are enormous,” he says.
About a third of the state’s land area is rated as having relatively high wind potential by the National Renewable Energy Laboratory. The state’s total wind generating potential, depending on turbine height, is 20 to 30 times the state’s current consumption, says Makhijani. Achieving the 12,000 to 15,000 megawatts of wind capacity called for in his report would require developing on about 5 percent of the state’s high-wind-potential land.
“It’s not huge. It’s not negligible,” Makhijani says.
Mouli Vaidyanathan comments that the data used in the report to estimate Minnesota’s solar potential is about 10 percent to 15 percent optimistic. “Such over estimates could harm our renewable energy industry in over promising and under delivery.”
While the report includes an Average Solar Radiation map for Minnesota, Makhijani says they didn’t calculate the state’s solar potential based on land area. Minnesota is unlikely to have large-scale PV or concentrated solar thermal, he says. Instead, the more likely application of solar is smaller, distributed installations on commercial rooftops, of which there are more than enough to provide the kind of solar capacity called for in the report.
“The solar generation in our scenario is not very big. It serves mostly to reduce the variability of the renewable resource rather than as a big source of supply,” Makhijani says. “Solar generation plays a role of moderating the storage requirement and the seasonal variability of your renewable resource. It improves the economy of the system.” That’s because solar generation tends to peak with demand on hot summer days when air conditioners are running.
Rolf Westgard doubts whether the state could ever build enough storage to moderate wind and solar’s variability. “There is no storage supply to compensate for the erratic nature of those sources. Imagine a warm muggy summer night when all AC’s run and there isn’t a ‘breath of air’.”
Makhijani admits building energy storage will be expensive and challenging. Under his report’s scenario, the state would need about a $9 billion investment in storage. Siting issues would undoubtedly arise, although he believes enough sites do exist. The state could shrink its storage requirements by further improving efficiency and expanding the use of demand dispatch, in which customers agree to have certain appliances or equipment powered off for short intervals when electricity demand is high, usually in exchange for a discount.
“The whole idea was to show that you can actually run a renewable system though all of the erratic supply and all of the variability in the existing demand with out doing anything to the existing demand,” says Makhijani. “You can get through all of these warm muggy nights.”
(Also, as noted previously, the IEER is a member of RE-AMP, which also funds Midwest Energy News.)
Could sweet sorghum dethrone corn as biofuel king?
>> Midwest Energy News
Could juice from this corn-like, African plant someday fuel our cars? (Photo by ILRI via Creative Commons)
February 9, 2012
By Dan Haugen
Most biofuels today are made by extracting sugar from plant material, then feeding it to bugs in a fermenter, which transform it into larger molecules similar to crude-oil hydrocarbons.
Dave Jessen is working to bypass all of that.
Jessen is chief technology officer at Chromatin, a Chicago biotech company that’s working to genetically engineer varieties of sweet sorghum that would convert sugar to biofuel before it even leaves the plant.
“You let the plant do all of that extra work,” says Jessen.
If successful, within a few years Chromatin will have a plant from which you’ll literally be able to wring biodiesel out of at harvest.
Chromatin’s concept has enough promise that the U.S. Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) recently awarded $5.7 million to Chromatin under its PETRO (Plants Engineered To Replace Oil) program. PETRO’s challenge to participants: come up with a crop that produces twice as much energy per acre as what’s currently possible with corn.
The sugar-rich, tropical grass — which looks like corn without the ears — would appear to have many advantages. It grows quickly, up to 14 feet tall, in time to plant and harvest twice a year in warmer regions. And it requires half the water and fertilizer it takes to grow corn. Scientists are also working on varieties that produce even more sugar, and ones that could be grown in colder climates.
Still, a century and a half after sweet sorghum was introduced to America from Africa, it remains a boutique crop in this country with little commercial-scale infrastructure. Competing with corn — or even finding a place alongside it — will require investment in new equipment and years of outreach and education to farmers, who won’t be easily convinced to switch from a known commodity.
Alternative to imports
In the 1860s, the U.S. Department of Agriculture was interested in sweet sorghum as a way to reduce reliance on imported sugar cane and slave-owning sugar plantations, according to the National Sweet Sorghum Producers & Processors Association. At the time, the Midwest was the biggest producer of sweet sorghum, which was sometimes called the “Northern Sugar Plant.”
Ultimately the plant proved unsuitable for making dry sugar, and instead it was used to make syrup (and probably moonshine, too, says Jessen). By the 1890s, the crop had mostly migrated to the Southeast, where it’s better suited for the climate.
Sorghum syrup, sometimes called sorghum molasses, still turns up at farmers markets from Iowa to Indiana (where you can attend the annual Crawford County Sorghum Festival in October). Sorghum syrup production peaked around 24 million gallons in the 1880s and then plummeted as glucose syrups took over the market.
Today it’s a tiny industry, accounting nationally for somewhere between 10,000 and 30,000 acres of cropland.
A stand of sweet sorghum being tested for biofuel production in Mozambique. (Photo by Swathi Sridharan via Creative Commons)
An ‘ideal crop’
Countries such as India and Brazil are already ramping up sweet sorghum production to supplement sugar cane as an ethanol ingredient. That isn’t happening yet in the United States, which is more attached to corn, but the federal energy and agriculture departments are funding research and a handful of companies have small projects in the planning stage.
“It’s an ideal crop for almost everything,” says Ismail Dweikat, a sorghum genetics researcher at the University of Nebraska-Lincoln who is working to create a cold-tolerant variety to expand the crop’s range. “It’s very cheap to grow. It’s very cheap to make ethanol out of. It’s environmentally friendly. It does not require as much nitrogen or irrigation. It’s an ideal crop.”
In places that receive at least 15 to 20 inches of rain per year, sweet sorghum can be grown without any irrigation at all, says Dweikat. It requires half the fertilizer that corn crops take, and the process of making ethanol from it is far less energy intensive. Instead of grinding and cooking kernels, you simply juice the stalks, add baking yeast, and wait 48 hours.
An improvement such as the sugar-oil conversion Chromatin is working on could be the game-changer the crop needs to find a place in U.S. energy production.
Convincing farmers
Improving on nature’s design may prove to be the easy part, though. Next comes convincing U.S. farmers to grow it.
Our agricultural infrastructure, from the subsidies to transportation, is set up for producing lots and lots of corn. Getting farmers to try sweet sorghum instead is going to take time, education, and probably incentives, too.
Dweikat says government and universities will likely have to take the lead in advancing early projects. He thinks existing ethanol plants could be adapted to also process sweet sorghum for less than $5 million per facility.
The production facilities would need to be located close to the sweet sorghum farms. The juice needs to be collected and processed within hours of harvest or it goes bad. That also means it’s a commodity that can’t be stored like corn, so farmers would lose control over when they sell.
Current sweet sorghum varieties can’t be planted until soil temperatures are above 65 degrees. The variety that Dweikat is working on would be able to sustain 50 degree soil temperatures, but even then Midwest farmers might not be able to fit two cycles into each growing season, something that’s possible in the South.
Policy changes are needed, too, according to Chris Cogburn, strategic business director for the National Sorghum Producers. The U.S. Environmental Protection Agency doesn’t yet recognize sweet sorghum ethanol in its renewable fuel standards, something the association is lobbying to change. Until that happens, and more productive hybrid varieties are available, most companies are holding off on significant investments, says Cogburn.
How much potential?
Dweikat thinks those investments might be less than five years off. Chromatin’s PETRO grant is for a three-year study, after which the DOE plans to pursue field testing of the most promising energy crops. Others crops being studied through the PETRO program include grasses, tobacco, camelina, and pine trees.
“What we tried to do was to put together an interesting portfolio of approaches that could theoretically hit the cost and yield targets,” says Jonathan Burbaum, PETRO’s program director.
At the end of the project, PETRO won’t be endorsing any single crop, and that’s because all agriculture is regional and the best option will depend on where you plan to grow it. (Sweet sorghum, for example, may have advantages in drier climates or marginal crop land.)
“It’ll have a niche, and it’ll fit well,” says Cogburn. “Could you produce 500 million gallons from sweet sorghum? I think that could happen. It’s going to be a good-sized industry, but it’s not going to be corn ethanol.”
EDITOR’S NOTE: An earlier version of this story misstated the amount of time it takes to convert sorghum sugars to biofuels. It is 48 hours, not 4 to 8 hours.
Dan Haugen is an Energy Journalism Fellow at Midwest Energy News. Contact him at dan@danhaugen.com.
This work by Midwest Energy News is licensed under a Creative Commons Attribution-NoDerivs 3.0 United States License.
Iowa researcher looks to toughen up wind turbines
>> Midwest Energy News
December 7, 2011
By Dan Haugen
K.K. Choi has spent much of his research career studying how subtle design changes affect the durability of large military vehicles.
Now, the University of Iowa mechanical engineering professor is working with the wind industry to design a tougher turbine.
Improving wind turbine reliability has become a national priority in recent years. The U.S. Department of Energy highlighted reliability in its July 2008 report on increasing wind generation to 20 percent of the nation’s electricity supply by 2030.
If the nation is to reach that goal, it’s believed that the number of costly, unplanned repairs to wind turbines will need to be reduced, which will bring down the overall cost of wind power.
“To beat or to be competitive with fossil-fuel based energy sources, the biggest challenge in wind energy is reliability,” said Choi, whose research revolves around fatigue analysis using computer modeling technology.
Choi’s computer models have been applied to everything from the Ford Taurus to Stryker tanks. A tool he developed for the U.S. Army predicts how slight design changes would affect the cost, durability and reliability of vehicles and their components.
The modeling tool created by Choi is more advanced than others because it takes into account uncertainties such as tiny variations in the materials and manufacturing precision, as well as the conditions in which the vehicles are driven.
The process is called reliability-based design optimization. In the Army’s case, Choi identified a change to a Stryker tank part that made it ten times more durable and 20 percent lighter at the same time. The military is considering whether to incorporate the new part.
Tanks to turbines
The leap from tanks to turbines isn’t as big as it might seem.
The military and wind industry both need reliable equipment that’s going to hold up under extreme conditions, whether it’s a desert battle zone or the blustery lower atmosphere. It’s also important that it’s not heavier or more expensive than it needs to be.
“While the components may look different, obviously, and serve different purposes, inherently they have the same technical challenges,” said University of Iowa Provost Barry Butler.
Butler is head of the Iowa Alliance for Wind Innovation and Novel Development (IAWIND), a multi-university, public-private research partnership, and he’s also the one who first connected the dots between Choi’s work and the wind industry.
After attending a wind reliability conference a few years ago, Butler asked Choi about his vehicle reliability tools and concluded they were a “natural fit” for turbine research. Butler approached Clipper Windpower about partnering on a project, and soon they were on a plane to the manufacturer’s California headquarters.
“They spent an entire day with us and gave us time to present, and they presented what their challenges are, and that’s when I think everybody around the table started realizing there’s some connectivity here,” Butler said.
How thick? How precise?
K.K. Choi
What’s unique about the type of computer modeling Choi does is that it helps judge how precise the manufacturing process needs to be in order to achieve reliability gains.
“If you make 10,000 blades, none of them are identical,” said Choi. Same goes for cars. They’re not exactly snowflakes, but even two vehicles of the same year, make and model will have slight differences — fractions of millimeters here and there.
It’s a way for car makers to keep their costs down. They can get a better price on sheet metal, for example, if it just has to be roughly one millimeter thick instead of precisely one millimeter.
A tool like Choi’s can help automakers calculate the ideal thickness of a piece, but also how much leeway is acceptable before it starts to noticeably affect the reliability results.
Choi is working on translating the tool to work with turbines. IAWIND awarded him a three-year, $300,000 research grant, which is being matched by Clipper Windpower. The goal is to create a design that doesn’t cost more but requires substantially less maintenance.
“What happens is in lots of cases is we over-design, which means that our products cost more than they should, which increases the cost of energy,” said Clipper engineering manager Rob Budny. “In some cases we under-design, which means that the product is not reliable and that you have large warranty costs.”
Clipper is asking Choi to design a new rotor hub and suggest changes to its blades that it can compare to its existing ones. And the new parts can’t cost more to manufacture.
“What I’m saying is: Guys, we can make it even cheaper, and yet improve reliability,” Choi said.
And that may lead to turbines that are as tough as tanks.
Dan Haugen is an Energy Journalism Fellow at Midwest Energy News. Contact him at dan@danhaugen.com.
Photo by Christiaan Conover via Creative Commons
This work by Midwest Energy News is licensed under a Creative Commons Attribution-NoDerivs 3.0 United States License.
New transmission line would ease Iowa wind bottleneck
>> Midwest Energy News
DC power lines, like this one in Oregon, are smaller and can run through narrower corridors, but also require expensive converters.
December 5, 2011
By Dan Haugen
Wind data is collected, turbine positions are mapped, and landowner agreements are signed. Even the financing is lined up.
And yet plans for the NorthStar Wind Farms in north central Iowa sit on the shelf six years after they were proposed because the area’s electricity grid can’t carry any additional power sources.
“Transmission has been the bottleneck,” said Jack Levi, co-chair of the project’s developer, National Wind. “If we had transmission tomorrow, we could start construction within six months.”
Wind developers like Levi finally see help on the horizon.
The proposed Rock Island Clean Line would be a 500-mile transmission expressway between northwestern Iowa and the Chicago area, where it could feed into a regional electricity grid that extends from Illinois to the Jersey Shore.
The Houston, Texas, company that’s seeking to build the project has already started submitting applications to state and federal regulators. It’s holding a series of landowner open house meetings this week as it works to narrow down its final route.
RE-AMP, which publishes Midwest Energy News, has provided funding to groups advocating for the line, but was not involved in the reporting of this story.
The corridor that’s being looked at passes within about 50 miles of the plot for the NorthStar Wind Farms, which would generate up to 200 megawatts, enough to power about 60,000 homes, if it could reach them.
“This is a tremendous opportunity,” Levi said of the transmission line project.
Advantages of HVDC
The Rock Island Clean Line would carry 3,500 megawatts of power from Iowa, Minnesota, Nebraska and South Dakota to eastern electricity markets via high-voltage, direct current (HVDC) transmission lines.
Direct-current lost out to alternating current as the world’s electricity standard more than a century ago, but there’s recently been renewed interest in the technology because of its potential advantages for moving power from remote sources over longer distances.
“The load losses are less, so the amount of energy you put in at one end is a lot closer to what you get out at the other end than if you used AC,” explained Hans Detweiler, Clean Line’s development director.
Direct-current transmission lines run on smaller, shorter towers that require a narrower right-of-way. Wherever they connect with the rest of the grid, though, expensive converters need to be installed to change the power back to AC.
Detweiler says over long enough distances, usually 350 miles or more, the advantages of HVDC outweigh the added costs.
The Iowa-Illinois project is one of four such lines the company is trying to build. Each one aims to transport renewable power from the country’s interior plains or deserts out to population centers where electricity is in greater demand.
“The existing grid just was not built with the notion in mind that you’d be moving serious amounts of power from, say, Omaha to Chicago,” Detweiler said.
The Rock Island Clean Line transmission project would deliver 3,500 megawatts of power from the wind-rich plains around northwestern Iowa to electricity markets in the east. (Graphic provided by Clean Line Energy Partners)
Transmission bottleneck
The lack of long-distance transmission is limiting wind development in some of the country’s most wind-rich regions.
In northwestern Iowa, multiple wind developments are on hold and some existing wind farms are having to routinely curtail their generation because of a lack of transmission capacity, said Harold Prior, director of the Iowa Wind Energy Association.
In O’Brien County, Iowa, where the Rock Island line is slated to begin, economic development director Kiana Johnson says Eurus Energy and Invenergy have repeatedly visited and expressed interest in developing wind farms. Neither has moved forward, though, citing transmission issues, she says. (Neither company returned a phone call Friday seeking confirmation.)
The problems are driving developers to build wind farms in parts of the state that are less windy but have more transmission capacity, Prior said. This can involve building turbines taller and placing them closer to where people live.
The Rock Island Clean Line’s 3,500-megawatt capacity would make room for Iowa to nearly double its wind generation from a year ago, says Prior. The developer estimates that its project will spur $7 billion in new wind farm investment.
“It would be a huge boost to the development of additional wind farms in northwest Iowa,” Prior said.
Levi, of National Wind, said even if the transmission line didn’t specifically carry electricity from the company’s NorthStar Wind Farms or similarly stalled Red Rock Wind Farm, it should help free up other capacity on the local grid.
Moving foward
Clean Line applied to the Federal Energy Regulatory Commission last month for authority to begin negotiating rates with potential customers. It also asked for permission to give preference on the line to renewable power.
“When you look at the national wind resource map,” Detweiler said, “the purple area in western Iowa is the furthest east of the truly superior Great Plains wind resources. That’s the area we’re working to access.”
For each segment of the route, the company has honed in on two or three corridors between three and 10 miles wide. It’s hosting landowner open house meetings Monday through Thursday of this week in nine Illinois cities.
Any transmission project on this scale is bound to find opponents, Detweiler said, but the company has been pleased with the public response so far. The wind industry has strong political support in both states, he noted.
The company plans to file its site permits with both states next year, and it expects those cases will take about 18 months. It will also need approval from the U.S. Army Corps of Engineers for crossing the Mississippi River.
If customer contracts and land acquisitions fall into line fairly quickly after that, Clean Line could be breaking ground by 2014 and beginning service as early as 2016.
“By long distance transmission standards, that’s like moving at light speed,” Detweiler said.
Dan Haugen is an Energy Journalism Fellow at Midwest Energy News. Contact him at dan@danhaugen.com.
Photo by theslowlane via Creative Commons
This work by Midwest Energy News is licensed under a Creative Commons Attribution-NoDerivs 3.0 United States License.
Even in Midwest, water for power plants a concern
>> Midwest Energy News
The Michigan City Generating Station on the shore of Lake Michigan in Indiana.
December 1, 2011
By Kari Lydersen
During a 2006 heat wave, the Prairie Island nuclear power plant in Minnesota had to cut its power generation by more than half because the water it draws from the Mississippi River for cooling was too hot. At least three other nuclear plants in Minnesota and Illinois also had to cut generation that summer – right at the moment electricity was badly needed to run air conditioners.
Similarly in Texas this summer, the record drought caused at least one power plant to curb power generation, and during the Southeast’s 2007 drought North Carolina customers saw blackouts because of water-related cutbacks by Duke Energy plants. In 2010, the Browns Ferry nuclear plant in Alabama reduced generation significantly for weeks because of record temperatures.
Such occurrences could become increasingly common with climate change and growing power demands, according to a report released Nov. 15 by the Union of Concerned Scientists (UCS). The report is the latest example of growing attention being paid to the “water-energy nexus” – the massive water demands of power generation, and potential difficulty meeting these demands in the face of population growth, climate change and regulatory revisions.
The UCS report describes a two-pronged threat: increasing ecological harm from power plants’ water use, and risks to the energy supply with warming temperatures and increasing drought.
Withdrawal vs. consumption
The report points out that power plants withdraw several times more fresh water than households and municipalities nationwide, and about as much water as irrigated agriculture – approximately 100 billion gallons per year. The vast majority is returned to water bodies after it is used, while about three to six billion gallons per year is consumed – lost through evaporation.
(via Union of Concerned Scientists)
Coal plants account for about two-thirds of withdrawals and consumption among power plants. When water is released back into rivers or lakes it is significantly warmer – sometimes over 90 degrees – which has serious ecological impacts, including fueling algae growth that depletes oxygen and can be toxic to organisms and humans.
When water bodies are warmer than normal, power plants can have to reduce or suspend their withdrawals to avoid violating the Clean Water Act, which labels high temperature as a pollutant. Meanwhile, increased drought and reduced winter snowpack are expected effects of climate change, meaning aquifers, rivers and lakes may not always have enough water for power plants’ cooling operations.
And while people typically think of the Midwest as having plenty of water, the UCS report includes models based on Intergovernmental Panel on Climate Change predictions indicating greatly increased drought in Midwestern states including Illinois, Kansas and Nebraska.
“There are watersheds even in the Midwest where we get in drought situations,” said UCS climate and energy program senior analyst John Rogers. “When you add into that changing circumstances, whether it’s demand changing because of population growth or supply because of climate change, the point of our analysis is you really want to be thinking about those changes before they actually happen.”
A priority for utilities
Revis James, a Generation R&D director for the Electric Power Research Institute (EPRI), which is funded by member utility companies, said widespread blackouts and power shortages are not a likely scenario because of future water shortages and warming. But he said utility companies do see water issues as a top priority and increasing challenge, since cool water is crucial to plants’ efficiency and because more stringent regulations in the future could force the adoption of new technology.
In a journal article published this summer (PDF), EPRI said they had surveyed 89 electric utilities nationwide and found two thirds reporting “great” or “very great” concern about meeting water needs in the future, particularly because of “stricter regulations and public attention to water scarcity.”
Power plants can exponentially reduce their water use by installing cooling towers known as closed cooling systems, which reuse the same water over and over again. These are expensive and take up a lot of space, but withdraw only two percent as much water as once-through systems.
Power plants can also use dry cooling systems that use air rather than water to condense steam. But these are also expensive, take more energy to operate and are less practical in warmer climates.
EPRI is partnering with utilities and power companies to develop and test more efficient cooling technologies, make experimental carbon capture at coal plants less water-intensive, and use “degraded” water rather than clean fresh water for power plants — agricultural runoff, stormwater, industrial and municipal wastewater and water byproducts of oil and gas extraction.
But James said these methods are bound to be more expensive.
“There’s no such thing as a free lunch,” he said. “There’s always trade-offs. It’s not clear yet whether water will become a more important driver (in choosing technologies) than other types of drivers like emissions and cost to consumers … If water becomes so precious that these tradeoffs are worth it … we haven’t been at that place yet but we may get there.”
Other water impacts
The UCS report doesn’t make recommendations but is intended to guide policymakers and power and utility companies in making “wise choices” about our existing power plants and future energy generation, said Rogers. The report notes that fossil fuel plants create a double whammy in the water-energy nexus since they use large amounts of water, and also are major drivers of climate change, which is expected to have serious impacts on fresh water quality and quantity.
Environmental groups point out that coal, natural gas and uranium also have serious “upstream” and “downstream” effects on water supplies on top of the direct effects of power generation dealt with in the UCS report. Strip mining of coal, in situ uranium mining and fracking for natural gas can all potentially pollute aquifers, rivers and lakes; and milling uranium and processing coal are water-intensive processes that result in contaminated wastewater.
Storing the waste products from coal and nuclear plants can also put water bodies at risk, as seen with the collapse of a coal ash impoundment into Lake Michigan from the Milwaukee-area Oak Creek power plant Oct. 31.
The Environmental Protection Agency is in the process of revising the section of the Clean Water Act — 316(b) — which regulates cooling water intake structures for major industries including power plants. Environmental groups say the proposed rule, released last summer for public comment, does little to protect ecosystems or push power plants to switch to closed cooling systems. The proposed rule essentially delegates to state regulators the power to decide what is the “best technology available” for individual plants, which critics say will mean a lax patchwork of standards.
In public comments filed in August, the Environmental Law and Policy Center and Natural Resources Defense Council argued that the proposed rule would seriously undermine the Obama administration’s Great Lakes Restoration Initiative and “continue to allow the Great Lakes to be used as a source for massive water withdrawals for once-through cooling of power plants and subsequent thermal pollution discharges.”
“There’s a grave concern in terms of lack of cooling towers and once-through cooling,” said ELPC attorney Faith Bugel. “Where fish species are already on the brink, this is adding another huge damage … I’m not going to argue that cooling towers are cheap, but if you look at the tenure for which a coal plant is going to operate, for plants at the beginning of their life span this makes sense. It is a cost you recoup given a sufficient amount of time.”
Power company and other industry interests also voiced much opposition to the proposed cooling structure rule, calling it too stringent. The EPA is in the process of making a final rule based on feedback from both sides. Apart from the 316(b) rule, industry representatives also think the government could ban open cooling systems or institute “zero liquid discharge” mandates in the future, forcing significant changes in cooling systems.
Environmental and clean energy advocates say such regulations are part of a carrot-and-stick approach needed to address power generation’s impacts on water and the risk of energy bottlenecks in a warming world. They call for more stringent rules regarding power plants’ cooling systems and water intake structures, and also more subsidies and incentives for wind power and distributed solar generation, especially in the Midwest where ample wind resources have not been tapped.
“This is about what can we do about existing power plants with things like 316(b), and also very much about the choices we’re making in terms of how we’ll meet energy demand in the future,” said Rogers. “It’s clear the Midwest is so well-positioned to do much more when it comes to taking advantage of renewable energy resources.”
Kari Lydersen is a Chicago-based freelancer and author whose work appears in The Chicago News Cooperative, The Washington Post, The New York Times and other outlets.
Photo by cncphotos via Creative Commons
This work by Midwest Energy News is licensed under a Creative Commons Attribution-NoDerivs 3.0 United States License.
