1) BPA Initiates Third-Party Loan Program for Residential Energy-Saving Measures
2) Alliance Board Approves Five Market Transformation Projects
3) Two Developers Propose Central Washington Wind Projects Totaling 362 MW Capacity
4) Northwest's First Geothermal Power Plant Bubbling toward Development in Southern Idaho
5) Washington Plant Produces Solar-Grade Silicon for Growing PV Industry
6) Klondike Wind Project Sold to PPM Energy
7) NorthWestern Energy Issues Another Wind Power RFP
8) Green Power Available to Most Washingtonians, But Initial Sign-ups Slow, Report Shows
9) News Bytes: Washington Energy Code Change, Oregon's Biggest Grid-Tied PV System Installed, and More
Bonneville Power Administration is initiating a loan program for residential energy-efficient equipment.
This new venture offers third-party financing to residential customers for a wide range of household energy-saving measures, such as heating/cooling systems, windows, duct-sealing and insulation. Utilities, local contractors and lender First Mutual Bank all have roles in this regionally available program.
BPA officials view the loan initiative as a way to expand residential energy efficiency opportunities at minimal cost to the financially strapped power marketing agency, which recently cut $13 million from its planned conservation spending. "The beauty of the loan program is that we're using the bank's money," said BPA's Mike Rose, and "tapping into a system" of existing residential equipment contractors.
"The key to this will be that the utilities will be encouraging energy efficiency through a base of contractors in their service area," said Scott Harlan, residential lending senior vice president for Bellevue, WA-based First Mutual.
His bank will offer unsecured loans of up to $20,000 and 12-year terms--at fixed interest rates starting at about 9 percent--for most residential efficiency measures eligible for BPA's conservation/renewables wholesale rate discount as endorsed by the Regional Technical Forum.
Mike Weedall's Brainchild
The residential loan program is the brainchild of BPA energy efficiency vice president Mike Weedall, who oversaw a similar venture in his previous work at Sacramento Municipal Utility District (see below for more on SMUD's program).
Weedall described the SMUD loan initiative as "tremendously successful ... We'd offer a loan or a rebate and invariably people would take the loan; it was that much of a better deal. The contractors loved it," he told Con.WEB, as it helped them sell high-efficiency equipment, such as air conditioning for Sacramento's toasty summer climate. "I've got to think we can have the same opportunities up here for things like high-efficiency heating equipment."
Weedall took charge of BPA's energy efficiency unit in late 2001, shortly after Bonneville administrator Steve Wright called for stabilized Northwest conservation funding (see Con.WEB, Sept. 28, 2001). "Part of Mike's challenge was how do we find ways to keep conservation alive that aren't necessarily subject to volatile market prices and the funding/lack of funding cycles that we go through," said Rose. The residential loan program is "one of a group of tools Mike's testing right now to help find ways to actually get us off the roller coaster."
This initiative also fits with several other guiding principles for BPA's energy efficiency activities, including cost-effectiveness, new approaches, collaboration and leveraging.
Bonneville can't loan money, Rose noted. And even if it could, "We're far better off relying on the banks to do what they do."
The agency sought utility opinions on the loan venture's design, Rose said, and solicited proposals from vendor-based lenders around the country, ultimately selecting First Mutual.
First Mutual began contractor-based home improvement lending in 1997, Harlan said, and now offers this service in 32 states. It makes hundreds of such loans per month, for items including energy-efficient windows and heating/cooling systems. "The contractors' participation in the program is a critical part of making it work, and ... we already had a contractor referral program," he said. "We saw a good opportunity there to have our program work in conjunction with BPA's."
Under the Bonneville initiative First Mutual will provide unsecured loans of up to $20,000, for terms as long as 12 years. Interest rates begin at 8.99 percent, as of late January, Harlan said, and can be higher depending on the borrower's credit rating, loan amount and other factors.
Most RTF-endorsed residential energy-saving measures are eligible for loans, although Rose said the program is intended for items that "typically become a part of the house," such as windows, heat pumps and insulation. Dwellings, ranging from single-family to four-plexes, can be heated by electricity or natural gas.
The loan program is available for all Northwest utilities, including investor-owned utilities. Equipment contractors anywhere can work separately with First Mutual, Harlan acknowledged, but the BPA venture offers the promise of utility referrals from customers. "A lot of conservation measures, a lot of improvements should come about because of that whole marketing relationship between the utility and the contractor," he said.
Participating utilities agree to local promotion and coordination with First Mutual. Utilities can feature certain measures, collaborate with local contractors and complement other energy-saving programs, including BPA's conservation/renewables rate discount. Other potential sweeteners include rebates and tax credits.
BPA is looking into marketing and advertising options that "leverage a little bit of [BPA] money" into considerable exposure, said Rose. Bonneville also may occasionally step in to provide program services, if needed.
The agency hasn't established program targets. "At this point, our immediate goals are really getting the program established well enough, getting it functionally operating and getting it out and available," said Rose.
Although no utilities have officially signed up for this new venture as of late January, a number have expressed interest, Rose said.
"We're very interested for some of our higher-cost measures, those that are not cost-effective for us to do that customers really like," said assistant energy services manager Dalene Moore of Tacoma Power. "We're thinking for window-only jobs it might be appropriate for our weatherization contractors to use third-party financing." Heat pump installations are another possibility for Tacoma, which already offers zero-interest weatherization loans. Local contractors could decide whether they wanted to participate with First Mutual, she said. The interest rate is "pretty low" for an unsecured loan.
The loan program idea appeals to energy services manager Jim Dolan of Pacific County PUD, who called it "another option" to help customers. But Pacific is deferring a decision on participation as it reviews its overall energy-saving portfolio. "My budget was cut in half for the 2003 calendar year," he said. "Now we're looking at dropping some programs that would've looked perfect for the loans."
Idaho Power is "definitely interested" in BPA's loan program, as it examines financing options for residential energy efficiency, said program specialist Annie Tucher. "I really think the BPA is on the right track with trying to bring a program to fruition that program managers like me can check a few boxes, customize for our customers and move on out the door. I think it's a really great idea, a great resource." Customers could potentially choose from among several loan-eligible measures, and thus create larger energy-saving projects, she said.
SMUD's Loan Experience
Sacramento Municipal Utility District, where Weedall formerly worked as energy services manager, began offering customer loans in the mid-1980s, said energy efficiency programs supervisor Dave Galbraith. Lending "really ramped up" starting around 1990, he told Con.WEB. SMUD has since provided some $400 million in financing, almost entirely for residential energy efficiency. From 1992 through 2001 loan-financed measures have created annual savings of 25 megawatts to 30 MW, and cut summer peak loads by 10 MW to 14 MW.
SMUD lends the money from its general revenues, a novel approach for utility loan programs, according to Galbraith. The northern California public-power utility works through participating contractors, who are authorized to make financing available directly to customers, which he called "a huge marketing advantage over anyone else." Contractors very much like the program features, he said.
The most popular measures are HVAC systems, particularly air conditioning, and windows, which now account for more than half of total loan volume, Galbraith said. HVAC loans average about $5,600 and window loans average slightly more than $7,000. Maximum term is 10 years for most measures. (See SMUD's Residential Equipment Efficiency Improvement Program for more details.)
Interest rates are set to cover administrative costs and projected losses, he said. Rates have varied over the years, from 3 percent to nearly 10 percent. So have delinquency rates, now about 2 percent but in the mid-1990s about 12 percent to 13 percent. "We started paying very close attention to qualifying borrowers" and became "aggressive on the collection side," Galbraith said (SMUD loans are collateralized).
"There's no recipe out there for success, necessarily," he said. "Try it in the marketplace and see how it goes, then make your modifications as you go."--Mark Ohrenschall
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Five market transformation projects totalling nearly $6.8 million have gained funding approval from the Northwest Energy Efficiency Alliance board of directors.
Three of the ventures fall under the Alliance's umbrella Commercial Buildings Initiative, BetterBricks. These will focus on expanding energy efficiencies in the specific markets of new kindergarten through 12th grade schools, hospital facilities and regional grocery chains, with $2.8 million in collective Alliance funding.
|(Courtesy of Northwest Energy Efficiency Alliance)|
The Alliance board--meeting in Bellevue, WA Jan. 23-24--also endorsed a new $2.9 million initiative to improve the efficiency of utility distribution systems by lowering voltages. An existing pilot venture, promoting operations and maintenance services for small commercial HVAC systems, received an additional $1 million for a second phase.
Alliance board members also adopted a $3.6 million operations budget for 2003, amounting to about 14 percent of an overall $25 million in anticipated spending this year for the regional market transformation collaborative. About 86 percent of the $25 million is earmarked for ongoing and new Alliance ventures, with the rest tabbed for operations, marketing, evaluations and research and development. This would be the Alliance's biggest spending year, largely because of increased project activities.
Altogether the Alliance has allocated about $142 million out of $164 million available to the collaborative from 1997 through 2004.
Look for more complete coverage--including an internal assessment of the state of the Alliance--in Con.WEB's February issue.--Mark Ohrenschall
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Two wind energy projects totaling nearly 362 megawatts of potential capacity have been formally proposed for central Washington's Kittitas County.
But the developers are taking very different routes in seeking government approval for their prospective wind farms, one of which has already generated local opposition.
Zilkha Renewable Energy in mid-January filed a site certification application with the Washington State Energy Facility Site Evaluation Council for an approximately 181.5-MW-capacity wind project between Ellensburg and Cle Elum. This marks the first time a wind developer has sought EFSEC endorsement, as allowed under revised state law. EFSEC recommendations are forwarded to Gov. Gary Locke, who has the final say.
The Texas-based company scratched plans to seek Kittitas County permission for the project after county commissioners changed the process for reviewing wind farms. But some Kittitas County officials and citizens believe the EFSEC path will diminish local influence on consideration of this wind farm proposal, which has been locally controversial.
Meanwhile, California-based enXco in late January applied to Kittitas County for approval of a proposed 180-MW-capacity wind project north of Ellensburg, near the proposed Zilkha site.
If approved and built to full capacity, these projects together would exceed the current 300-MW capacity of Stateline Wind Energy Center in southeastern Washington. These also would be the closest large-scale wind farms to metropolitan western Washington.
Neither of these projects is likely to start spinning out electrons before 2004, at the earliest.
Zilkha's Proposed Wind Project
Zilkha publicly announced plans for a Kittitas County wind project in April, anticipating maximum capacity of 250 MW from turbines installed on ridges some 12 miles northwest of Ellensburg.
|Zilkha Renewable Energy's proposed wind farm site. (Courtesy of Zilkha Renewable Energy)|
Zilkha touted the site's strong winds, ready access to transmission lines, power markets and roads, lack of significant environmental issues, and substantial economic development benefits for Kittitas County, in property tax revenues, lease payments to landowners and construction jobs. "We believe this has the potential to be one of the premier wind sites in the Northwest," Zilkha project manager Chris Taylor told Con.WEB (see Con.WEB, May 31, 2002).
But some local opposition to Zilkha's proposal quickly emerged, and the wind farm plan has become the topic of extensive and impassioned local debate.
"Unlike virtually every other wind farm in the United States, which are typically located in remote areas, Zilkha wants to build on the doorstep of a residential community (this area is not farmland), only 7 miles from a city of 10,000 people, on the highest ridges of an area prized for its great scenic beauty," wrote Geoff Saunders, spokesman for Residents Opposed to Kittitas Turbines, in a recent e-mail to Con.WEB. "This county depends to a large degree on tourism, and there is no doubt that a large industrial project in a formerly scenic area will damage tourist revenues. This area is also environmentally fragile and home to a wide range of birds, animals and fish, whose habitat will be disturbed or worse." Local landowners who don't lease to Zilkha face "all of the problems of living next to a huge industrial project but no compensation."
Zilkha Seeks State Approval
|EnXco's proposed wind farm site. (Courtesy of enXco)|
Zilkha initially planned to seek approval from Kittitas County, which at the time allowed wind farms to be reviewed as conditional uses in Agriculture-20 and Forest & Range zones, which cover the entire proposed site. But after months of deliberation and a temporary moratorium on wind farm development applications, the county commissioners in December changed the process for considering wind proposals.
Commissioners now have the final word, not the Board of Adjustment. The new wind process requires a development agreement with standards, a site-specific comprehensive plan amendment and a zoning change to a wind resource overlay district, according to county planner Clay White. Environmental review also is included. Each wind farm application will be reviewed by the county Planning Commission, which will make a recommendation to the three commissioners.
Zilkha officials believe the county's new rules are unreasonably burdensome and open the door for delays and multiple appeals, Taylor said. "With the new ordinance the county passed Ö we went from a [conditional use permit]-type process, which most other wind farms have been permitted under, to a more complicated process," Taylor said. "We don't want to wait five years" to build the project.
These alterations prompted Zilkha to take advantage of a revised state law and pursue state approval of the proposed Kittitas Valley Wind Power Project.
A bill passed by the state Legislature in 2001 allows developers of alternative energy resources of any size to apply to EFSEC for state review of their projects. At the end of its review--which includes public meetings, independent experts, environmental impact statements and formal hearings--EFSEC will forward a recommendation to the governor, who makes the final decision, according to a council news release.
Zilkha is looking forward to state review of its wind farm proposal, said Taylor. "We think EFSEC has some advantages" over Kittitas County, Taylor said. "They've reviewed a lot of projects. This is simple for them."
EFSEC managers, accustomed to reviewing applications for gas-fired combustion turbine proposals, are anxious to review their first wind project application. "We're excited to look at it," said Allen Fiksdal, an EFSEC manager. "The differences between combustion turbine projects and wind are big; for example, there are no air emissions or water issues to deal with."
EFSEC plans a public information meeting in Ellensburg in early March. Fiksdal said EFSEC could submit a recommendation to Gov. Locke by year's end.
Some Kittitas County officials and residents, however, are leery of the EFSEC process and its minimal local representation. EFSEC has an appointed chair, five state agency representatives and potentially four others, along with some local government representation from the affected area, the news release said.
"It's a business decision and that's [Zilkha's] right," said Kittitas commissioner Perry Huston, quoted in the The Daily Record newspaper. "But in my opinion it puts local citizens in a far lesser position to have local control over the project. Zilkha is looking for the easiest way to do it." Although he acknowledged some local input to EFSEC, "We, the county, would have a much better process and a more thorough and fair one. And the decision would rest on county elected officials." Commissioner Bruce Coe called Zilkha's plans "the litigative path of least resistance," as quoted in the newspaper.
Saunders thinks Zilkha is "completely bypass[ing]" the county, and has "demonstrated what little regard the company has for the wishes of residents and local officials." He labeled it "a deeply cynical move."
EnXco has prospected for wind development sites in Kittitas County for some time. On Jan. 29, it announced plans for a 180-MW project, dubbed Desert Claim, about eight miles north of Ellensburg.
An enXco news release lauded the site's "sufficient commercial wind resource" (measured over two years), easy access to transmission, large power markets and existing roads, "no apparent environmental constraints," and continuing availability for agricultural and rural residential use. The proposed location lies on the northern portion of the Kittitas Valley, where it starts to rise into mountains, project manager David Steeb told Con.WEB. He said his company has agreements with eight private landowners for the entire proposed site, encompassing 5,237 acres.
Although enXco is seeking county approval to erect 120 turbines and associated infrastructure, "The market will determine whether we build it in phases," he said. EnXco has touched base with Northwest publicly owned and investor-owned utilities, as well as Bonneville Power Administration. "Our discussions with utilities cover a wide range, from initial contact to very detailed discussions," he said, but nothing is ready for public announcement.
The company "intends not only to develop and construct the wind farm, but to also operate it for the life of the project," the news release said.
Steeb said EnXco's development timeline depends on the county process. White said county review could take months before the commissioners make a decision, perhaps longer if an environmental impact statement is needed. He declined to speculate on potential controversy over enXco's proposal, other than to note some people don't like huge turbines rising more than 100 yards high.
"I can't comment on how people view our competitor's proposal," said Steeb. "We believe we've reflected a good site and a site that supports a good wind project."
Saunders said he hadn't yet examined enXco's application, although he praised the company for "trying to do this the right way," through a local process. But he expressed concern Kittitas County would become an "eyesore" and "an industrial wasteland" if the wind farm proposals are approved.--Mark Ohrenschall and Cassandra Sweet.
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A proposed geothermal power plant is bubbling in southern Idaho, as potentially the Northwest's first large-scale project to create electricity from underground hot water.
The Raft River geothermal venture, in Cassia County near the Idaho-Nevada-Utah border, would likely start in the range of 10 megawatts to 15 MW capacity, although it eventually could generate as much as 90 MW. Developer U.S. Geothermal looks to start construction in 2004 and begin power production late that year or early 2005.
Boise-based U.S. Geothermal has several advantages in its favor--a relatively hot resource, an apparently non-controversial site that hosted a successful federal demonstration project about two decades ago, and a ready-made initial market at a reasonable price under a federal law requiring utilities to buy power from alternative energy resources. U.S. Geothermal also has an arrangement for $1 million in initial equity financing for project development.
Idaho already hosts many geothermal applications, although none produce electricity. Other Northwest geothermal power plans have surfaced over the years, particularly in Oregon, but none have reached fruition.
Raft River Geothermal
In the late 1970s and early 1980s the U.S. Department of Energy conducted a geothermal demonstration project at Raft River, drilling five production wells, two injection wells and seven monitoring wells, according to the Idaho Department of Water Resources. This plant successfully generated 7 MW in 1981-82.
But oil prices dropped and federal funding disappeared, U.S. Geothermal chief executive Doug Glaspey told Con.WEB. The power plant itself was sold and moved to Nevada; the capped wells have lain dormant. Vulcan Power has owned the Raft River project for the past 10 years, Glaspey said, and U.S. Geothermal has an agreement to acquire the venture from Vulcan.
"What it lacked more than anything was a market for the power at a price that was economic," Glaspey said.
But in a series of rulings last year, the Idaho Public Utilities Commission adopted more generous rules for so-called qualifying facilities under the federal Public Utility Regulatory Policies Act (PURPA). The IPUC ultimately allowed 20-year contracts for projects up to 10 MW. It also required utilities to pay levelized prices (for non-fueled projects with 2005 on-line dates) of about 5.1 cents per kilowatt-hour.
These regulatory changes stemmed from the energy crisis and subsequent calls to expand PURPA resources to lessen Idaho's exposure to wholesale power markets, said IPUC policy strategist Bill Eastlake. Meanwhile, utilities were examining their future resource needs. "It just looked like a good time to take a new look at our existing PURPA rules," he told Con.WEB. "They were very unfavorable, frankly," with low prices and a five-year contract limit that posed a huge financing barrier.
"The 10 megawatts we're looking at to begin with is specifically designed for the 10 MW PURPA size," Glaspey said. "What allows us to look at 10 megawatts is all the sunk capital spent, the wells already in. If we were starting a new project ... we couldn't do a 10-megawatt project unless there were much hotter temperatures." Existing Raft River project assets have been valued at $11 million, he said--"$11 million in the ground there we don't have to spend, assuming the wells are in producible shape."
U.S. Geothermal plans to test the wells this spring; a U.S. Department of Energy grant will pay 80 percent of the estimated $265,000 cost. "We know they pour hot water, have good head pressure and the water is very clean," Glaspey said. "Our expectation and the consultant's expectation is that it shouldn't be a problem."
The presence of existing wells "makes a very, very, very large difference" in geothermal development, agreed Kevin Rafferty of the Geo-Heat Center at the Oregon Institute of Technology in Klamath Falls. "They obviously were able to ... hit the ground running there, which is really not possible at any other [Northwest geothermal power] site I'm aware of."
U.S. Geothermal in December announced a complex arrangement expected to generate $1 million in equity financing, raised through First Associates Investments of Canada. This money is earmarked toward the Vulcan purchase, well testing and geothermal reservoir estimates, initiation of an engineering study for a 10 MW plant, and working capital, according to a news release.
|(Courtesy of Renewable Energy Atlas of the West)|
This infusion comes despite financial woes afflicting the larger energy industry. "I think there's a belief that renewable energy is a good field to be in," said Glaspey. "Typically there's a premium paid for the product, and going forward there will be a more economic market for renewable energy realizing that the Northwest has pretty much used up its excess hydro capacity."
Director Rodger Gray of First Associates pronounced himself "very optimistic on our ability to raise the funds." Raft River features a substantial geothermal resource and nearby transmission. It benefits from the growing movement toward green power. And geothermal is a highly reliable and environmentally clean power source, he said, with no fuel concerns, unlike gas-fired generation. The business risk with geothermal is recovering the initial capital investment, from a power buyer willing to pay a premium price.
Meanwhile, Glaspey's company will be taken over by a publicly traded firm, U.S. Cobalt, and the merged entity will assume the U.S. Geothermal name, according to Glaspey. "We had decided to move out of the mining business" with U.S. Cobalt. "We needed another business to keep our stockholders happy."
Raft River projects costs are anticipated at $23 million for 10 MW of capacity, he said. "Most of that, assuming we get a power-purchase agreement, can be bank-financed."
The levelized PURPA price of 5.1 cents/KWh "is no economic bonanza," Glaspey said, although it should cover operation/maintenance and capital costs, and some profits. "It's probably marginal for a 10-megawatt-sized plant. We hope that will get us started and allow us to build the site larger."
Other Project Details
Located about 15 miles from Malta, the Raft River project lies entirely on private land. "We're purchasing the properties the wells are on and we have leases for a much larger property position ... close to six square miles" altogether, Glaspey said. "We're pretty much out in the sagebrush, with agricultural fields around us."
Siting issues can be a bugaboo for some renewable energy and fossil-fueled plants, but not, apparently, for Raft River. "Right now we are not having a siting problem with this project," said Warren Weihing of the Idaho Department of Water Resources Energy Division. The proposed locale isn't especially scenic or populous, and some geothermal infrastructure, such as wells, already occupies the site. Emissions would be very minimal, he said.
"It's pretty well accepted right now," said Mechelle McFarland of the Mini-Cassia Development Commission, who has not heard any opposition to the geothermal plant proposal. Her commission "is completely in favor of it," seeing the potential for some high-paying jobs and local tax revenues.
Glaspey said he anticipates building a binary-cycle air-cooled facility, in which heat from geothermal water vaporizes another fluid, and steam from this secondary fluid spins turbines.
The plant's initial capacity is planned in the range of 10 MW to 15 MW, which could be just the beginning. A technical report from GeothermEx found potential for 14 MW to 17 MW from the five current steam wells, and a "known reservoir" capable of generating up to 90 MW, according to a news release.
U.S. Geothermal is "examining options" beyond the initial phase, Glaspey said, although additional capacity above 10 MW would not automatically qualify for standard PURPA sales. U.S. Geothermal is focusing on possible power-purchase arrangements with Idaho Power and PacifiCorp, and talking with BPA about potential renewables sales and transmission, and Bonneville Environmental Foundation for green tags, he said.
A nearby high-voltage transmission line is owned by Raft River Electric Cooperative, with capacity leased to BPA, Glaspey said.
Idaho Geothermal Perspectives
The Gem State already takes considerable advantage of subterranean hot water, although not for generating electrons. "Idaho has a tremendous amount of geothermal development, all of which is direct use," said Rafferty, citing applications ranging from homes to district heating in downtown Boise to greenhouses to an alligator growing farm.
These geothermal sources have lower temperatures than needed for electricity generation. Raft River reservoir temperatures range from 275 degrees to 300 degrees, according to IDWR. "Most geothermal power plants are using resources in excess of 300 degrees," said Rafferty.
Although Raft River would be the first commercial-scale geothermal project within the Northwest, Portland-based PacifiCorp owns a 27.5-MW-capacity plant in Utah and BPA has contracted to buy power from the proposed 49-MW Fourmile Hill project in far northern California.
Ironically, none of these sites are in Oregon, which claims the Northwest's most abundant geothermal power resource potential, according to the Renewable Energy Atlas of the West. "There's been a number of false starts," said Rafferty, listing ventures in the Newberry Crater area south of Bend, the Alvord Desert in southeastern Oregon and the Winema National Forest in south-central Oregon. "Generally speaking, there's been tremendous environmental opposition to geothermal development," he said. "I would put that up toward the top in terms of reasons why we don't have anything going on in Oregon." --Mark Ohrenschall
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Until late last year, hand-me-downs from the semiconductor industry were the sole source of crystalline silicon for manufacturing solar photovoltaic cells.
Now the PV industry has a dedicated source of crystalline all its own--a Moses Lake, WA facility, opened in November, that plans to turn out 2,000 metric tons of solar-grade crystalline silicon every year.
This annual production will be enough to support fabrication of approximately 130 peak megawatts of PV cells, equivalent to about one-third of global production in 2001.
The plant's opening signals that the solar industry is growing beyond the point it can rely on discarded silicon from the semiconductor industry. "The industry has matured to the point where it needs a reliable source of feedstock," said Tor Hartmann, president of Solar Grade Silicon LLC, operator of the Moses Lake plant. "The electronics market is not a high-growth industry. There are limits on the amount of cast-off material the solar industry can acquire," Hartmann said.
"At a 25 percent annual growth, the PV industry's demand for silicon will double every three years or so. In three years, you double and three years later you double again. Then it gets to the point where PV is a significant part of the silicon commodity market," said Tom Surek, PV researcher at the National Renewable Energy Laboratory.
Making Silicon in Moses Lake
The Moses Lake plant, which employs 160 workers, manufactures "chunk" polycrystalline solar-grade silicon that is the feedstock for producing silicon wafers used to fabricate crystalline PV cells. Production began in November.
Solar Grade Silicon LLC is a 50-50 joint venture between Advanced Silicon Materials LLC (ASiMI), a subsidiary of Japan's Komatsu Ltd., and Silicon Technologies AS, a subsidiary of Norway's Renewable Energy Corporation AS. The plant opened in 1984 to manufacture silicon for the semiconductor market, but closed in February 2002 as a result of poor market conditions, Hartmann said.
The silicon-for-solar facility uses a two-step manufacturing process, Hartmann said. Metallurgical-grade silicon is converted into silane gas through a series of chemical reactions. The gas is then used to produce polycrystalline silicon through a conventional chemical technique.
"We'd like to grow with the market, and if the business opportunities are there, we'll grow also," Hartmann said. He declined to disclose the price Solar Grade Silicon LLC charges for its product.
A process improvement project involving the Northwest Energy Efficiency Alliance had some bearing on the Moses Lake plant's reopening.
The Alliance is working with ASiMI on polycrystalline silicon production improvements that have achieved energy savings of 25 percent. ASiMI developed production process improvements for "dendritic" silicon manufacturing, a method of producing crystalline silicon, enabling the company to grow 25 percent more crystals in a given unit of time, said Michael Ponder, the Alliance's coordinator for the project.
The Alliance worked with ASiMI to implement the improvements at its Moses Lake plant, Ponder said. The improvements also were instituted at ASiMI's Butte, MT plant, which produces semiconductor-grade silicon. The joint venture, Solar Grade Silicon, has licensed ASiMI's production technologies.
The $2 million alliance project began in May 2001 and is scheduled to wind up at the end of this year, Ponder said.
With crystalline silicon accounting for more than 80 percent of the PV market, the PV industry depends on the semiconductor silicon market for feedstock.
That creates several problems, according to industry experts. Semiconductor-grade silicon is purer than needed for PV manufacturing and the cost is $50 per kilogram, far higher than PV producers' $20 target price, according to NREL's silicon materials research program.
As a result, the PV industry takes off-spec castoffs from semiconductor-grade production. But as PV demand grows, the industry's need for castoffs is likely to exceed supply in the next decade, NREL and other observers forecast.
A reliable supply of solar-grade silicon at prices below $20 per kilogram will be necessary to support projected growth in PV production, according to the Photovoltaic Industry Roadmap, produced by PV industry representatives in 2001.
NREL is collaborating with Crystal Systems, Inc. on technologies to drive the price of solar-grade silicon below $20 per kilogram, said Martha Symko-Davies, a researcher in NREL's photovoltaic manufacturing technology program.
The most important piece in reducing PV cost, however, is improving module efficiency, Surek said. "Efficiency is the cost driver, rather than dollars per kilogram of silicon," he said.
Crystalline silicon wafers account for 40 percent to 50 percent of the cost of PV modules, which in turn represent half the cost of total installed solar systems, according to consulting firm Solarbuzz, Inc.. For solar to achieve deep penetration into the electricity market, Solarbuzz believes total installed solar system costs must fall from $8 per peak watt to $10 per peak watt today to $3 per peak watt
Today, the typical silicon-based commercial PV module has efficiency ratings of 10 percent to 14 percent, representing the amount of sunlight converted to flowing electrons, Surek said.
NREL's high-performance photovoltaic project is researching polycrystalline thin-film cells, using alternative materials such as copper indium diselenide, with efficiency ratings of 20 percent and concentrators with efficiencies up to 40 percent, Symko-Davies said.
However, reaching those targets could take a decade, give or take five years, Symko-Davies added.
Growing Silicon Demand
In the meantime, PV demand for silicon is growing. Worldwide in 2000, the PV industry used an estimated 4,000 metric tons of crystalline silicon to manufacture 235 peak megawatts of PV modules, according to an article in the November-December 2002 edition of Renewable Energy World written by Hubert Aulich of PV Crystalox Solar, a German wafer manufacturer, and Friedrick Wilhelm-Schulze from PV Silicon, a PV Crystalox Solar subsidiary. Half the material was off-spec semiconductor-grade scrap, the remainder a higher quality "non-prime" silicon.
Non-prime costs 15 to 60 percent more than scrap and its availability depends on low demand from the semiconductor industry, according to an article in the June 16, 2002 edition of PV Power, a newsletter published by the International Energy Agency.
Aulich and Wilhelm-Schulze estimated that if global PV demand grows 25 percent annually, PV manufacturers will need 18,000 metric tons of silicon per year by 2010. At 15 percent growth, the 2010 demand will reach 8,000 metric tons, twice the amount consumed in 2000. Only 4,000 tons of off-spec silicon will be available by 2010, they projected.
To match supply and demand, the PV industry can reduce silicon demand by improving the efficiency of wafer fabrication; purchase semiconductor-grade silicon, which would drive up the price of PV modules; or find a reliable supply of solar-grade silicon.
Aulich and Wilhelm-Schulze believe that greater wafer production efficiency and the growth of solar-grade silicon manufacturing capacity are the best bets for meeting silicon demand.
That's where the Moses Lake plant fits into the picture.
Meanwhile, other manufacturers are studying the solar-grade silicon market. Wacker Chemie, a German firm, is researching production of a granular solar-grade silicon, with a target price of $25 per kilogram.--Jim DiPeso
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The 24-megawatt-capacity Klondike Wind Power Plant in north-central Oregon has been sold to PPM Energy from Northwestern Wind Power for $16.8 million.
This deal will help sustain operations at Golden Northwest Aluminum, which is owned by Brett Wilcox, also owner of Northwestern Wind Power. It also represents the first purchase of an operating wind project by PPM Energy (formerly PacifiCorp Power Marketing).
Klondike-generated energy will continue flowing to Bonneville Power Administration.
"We're extremely, extremely pleased with this purchase," said PPM spokeswoman Jan Johnson. "I think BPA's happy and I think Brett's happy."
Wilcox said proceeds from the sale would be used to help preserve jobs at GNA's Goldendale, WA smelter. "We need to sell this first phase of Klondike so we can keep smelter operations and employment," he told Con.WEB.
The 24-MW Klondike venture started commercial operations in December 2001 about eight miles east of Wasco in Sherman County.
"Klondike is a wonderful renewable resource originally developed to help Golden Northwest Aluminum obtain a diversified power supply," Wilcox said in a Jan. 14 news release announcing the deal. "Our successful sale of this wind project helps ensure continued operations at Golden Northwest and our ability to develop our other wind power and gas-fired generating resources."
The Sherman County assessor put the real market and assessed value of the 16 turbines at $19.1 million. BPA receives all of Klondike's output under a 20-year contract with an average price of 3.5 cents per kilowatt-hour. Bonneville also buys green tags associated with Klondike. The contract will be assigned to PPM, with some amendments.
"It allows us to expand our sizable wind portfolio," said Johnson. PPM already markets all the energy from FPL Energy's Stateline Wind Energy Center, which was recently expanded to 300 MW capacity. BPA buys output from 90 MW of Stateline capacity at a price "consistent" with that of Klondike, she said. PPM also has plans for about 200 additional megawatts of wind capacity under development in California and Minnesota.
Beyond Klondike's existing capacity, Northwestern has plans for a 75-MW expansion, using the same substation, general manager Allen Barkley told Con.WEB. "The problem is just finding a market for the wind energy," he said. Northwestern hasn't yet resubmitted a conditional-use application to Sherman County for the expansion, whose timeline "really depends on the market." PPM Energy has first rights on any equity sales of the expansion phase, he said.--Ben Tansey and Mark Ohrenschall
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NorthWestern Energy is renewing its search for wind power.
Montana's largest utility issued a request for wind energy proposals Dec. 30, seeking an unspecified amount of power. Bids are due Feb. 14, and NorthWestern (formerly Montana Power) plans to notify winners and negotiate contracts in March. Any purchased wind power would help serve the utility's default supply customers.
This is NorthWestern's second wind RFP in less than two years. A 2001 solicitation led the utility to select 150 megawatts in planned capacity from Montana Wind Harness, but the choice became mired in controversy and questioned by state regulators. NorthWestern eventually canceled the power-purchase agreement.
In addition to taking a broader look at wind power market offerings, the new solicitation reflects concerns expressed by the Montana Public Service Commission about the previous RFP, said utility spokeswoman Claudia Rapkoch. "It's just a little bit more transparent with very clearly stated goals, very clearly stated aspirations, a very clearly written RFP with a contract attached to it. And not a great deal of emphasis on individual negotiations."
Meanwhile, in another development, the Montana PSC ruled in December that a proposed 50-MW-capacity wind farm near Butte is a qualifying facility under the federal Public Utility Regulatory Policies Act, and thus eligible for a mandatory power-purchase contract. But the PSC established a price of 1 cent per kilowatt-hour, based on short-term avoided cost, which an official of developer Whitehall Wind said was far too low to build the project.
Seeking Wind Power
NorthWestern's previous RFP listed a goal of up to 150 MW of installed wind capacity, but the investor-owned utility's latest solicitation lacks a specific megawatt number.
"It is anticipated that the Utility will determine the appropriate quantity of wind energy to purchase based on an independent integration study, economic impact on the default supply and the specific bids received through this RFP process," said the Dec. 30 solicitation.
NorthWestern announced in November it would analyze wind energy--notably cost and system integration issues--as a potential addition to its resource portfolio for customers remaining with the utility under the state's electric industry restructuring. Spokeswoman Claudia Rapkoch called the wind RFP and study "a dual effort," with each informing the other (see Con.WEB, Nov. 26, 2002).
In its new solicitation NorthWestern sets a minimum bid size of 10 MW, and welcomes proposals in 25-MW increments. Proposed terms of 10 and 20 years are required in the bids, although other lengths of time are allowable if they provide "clearly defined benefits" to the utility. NorthWestern wants electrons as well as environmental attributes. The RFP did not specify on-line deadlines, although price proposal tables start in 2004.
Proposed wind projects need not feed power directly to NorthWestern's system. Bidders are "encouraged, but not required" to offer extra integration and transmission services, such as hourly and seasonal forecast guarantees, fully integrated energy deliveries and transmission offerings.
NorthWestern will evaluate each project on the basis of its energy price and value, the bidder's ability to deliver power as proposed, the project's overall environmental impacts (especially on birds) and the developer's creditworthiness. The utility said it expects to sign one or more power purchase agreements if deemed "economically and reliably feasible." NorthWestern reserved the option to choose the non-lowest-cost bid "if another proposal is deemed to have other attributes that warrant a higher overall ranking. Thus the evaluation will contain qualitative and quantitative ratings," the utility said in its RFP. "The quantitative rating will be evaluated by comparing the net price and volume within the portfolio compared to other resources options." NorthWestern expressly noted its right to reject all proposed bids.
The utility anticipates between 12 and 24 bids, Rapkoch said. "We're extremely happy with the level of interest."
Shortly before NorthWestern issued its wind solicitation, the Montana PSC on Dec. 18 decided on a 3-2 vote that a spurned bidder from the first wind solicitation could sell power to the utility under PURPA. But the commission set the purchase price for Whitehall Wind's proposed 50-MW venture at NorthWestern's short-term avoided cost, currently 1 cent/KWh.
The PSC order acknowledged that long-term PURPA contracts--as sought by Whitehall Wind--are desirable. But it also referenced occasions for "significant balancing of competing interests and cautious approaches to approving price and terms" for QF sales to utilities. Commissioners cited NorthWestern's status as a restructured utility and a temporary default supplier, which "could raise legitimate questions regarding long-term contracts."
The order cited NorthWestern concerns about wind's intermittence, and Whitehall's contentions that the "anti-QF" utility ignores the larger benefits of Montana wind development.
(Now former) PSC commissioner Bob Anderson said he wanted to change the short-term avoided cost rate from 1 cent/KWh to 3.2 cents/KWh, based on "sufficient information in the record," but PSC staff and other commissioners didn't think there was "a sufficient evidentiary record to support it." Whitehall's "best hope is through an RFP issued by NorthWestern," Anderson said.
Whitehall Wind officials were displeased with the PSC decision. "We were hoping [the commissioners] would follow their own rules and set a rate that was reasonable and provide for the ability to do some sort of wind development," said Whitehall development director Chris Moore. He said the 1 cent/KWh rate was "incredibly low," incorrect, "not a true cost rate" and would not allow the company to build its wind facility.
Whitehall was still mulling its options, Moore told Con.WEB in mid-January. The company plans to submit a bid to NorthWestern's wind RFP, similar to the proposed QF facility, he said. "We still think it's a very good project."
NorthWestern, meanwhile, liked the PSC's call. "We think it was appropriate under the circumstances," said Rapkoch. The utility generally disapproves of PURPA, which allows QFs to obtain power-sale contracts without competitive bidding. "We recognize that the federal law still exists, but we still question whether or not a QF facility is appropriate in this market," she said.
The QF decision has not affected the wind solicitation, she said in late January.
Whitehall Wind is affiliated with Minnesota-based Northern Alternative Energy, which lost out to Montana Wind Harness in NorthWestern's 2001 wind solicitation. But NAE and at least one other bidder claimed the utility didn't choose the lowest-price proposal and questioned Montana Wind Harness' qualifications (see Con.WEB, Dec. 20, 2001).
In June 2002, the PSC decided NorthWestern had not sufficiently explained how it chose Montana Wind Harness, and thus could not declare the selection reasonable. The utility soon thereafter canceled the power-purchase contract (see Con.WEB, Aug. 29, 2002).
NAE president John Jaunich said he approached NorthWestern officials with the 50-MW project after the PSC's June ruling, but didn't get anywhere. He said his company took the QF route because it was anxious to build its project before the current federal wind energy production tax credit expires at the end of 2003.
The PSC's December order mentioned NorthWestern's refusal to negotiate with Whitehall, for potential reasons ranging "from bumbling ineptness to lack of resources to accomplish things in a timely manner." But, the commission concluded, "Whether NWE has exercised poor judgment regarding QFs or WHW does not affect the price NWE should pay for energy generated by WHW."--Mark Ohrenschall and Cassandra Sweet
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Retail green power is now available to customers of larger Washington utilities, as mandated by a 2001 state law, although initial sign-ups are quite modest.
Customer participation averages about one-half of 1 percent among the 16 utilities required to offer retail green power, according to a December report to the Washington State Legislature. Green power as a percentage of total utility kilowatt-hour sales and revenues averages well below one-tenth of 1 percent.
The report--prepared by the state Department of Community, Trade and Economic Development and the Washington Utilities and Transportation Commission--anticipates growth in green power numbers over time. Only four of the 16 utilities offered green power before Washington law required it for larger utilities starting in January 2002, the report noted. It called the green power mandate a "catalyst" to renewables investments, particularly by investor-owned utilities.
"In general it looks good," said green power programs director Natalie McIntire of Renewable Northwest Project. "The programs are working well and improving," after a start marked by "some disappointment" with utility marketing efforts. "I think they're catching on to the whole process. You can't just offer a product. You have to market it and educate people." The participation rates show "room for improvement," she acknowledged, calling green power a "very immature" market.
Washington Gov. Gary Locke in 2001 signed legislation that required utilities with more than 25,000 customers to offer green power to their retail customers (see Con.WEB, June 28, 2001). The designated state date was Jan. 1, 2002.
All 16 qualifying utilities offer green power, although two were still setting up programs as of an October 2002 CTED/WUTC survey of utility green power sales, program budgets and participation, along with "qualitative data" from utility officials. Information from Renewable Northwest Project's most recent regional green power survey also was incorporated.
|(Courtesy of Chelan County PUD)|
The average customer participation rate--a widely used metric for green power programs--was 0.55 percent among all 16 utilities. Chelan County PUD (1.9 percent) and Benton County PUD (1.1 percent) came in with the highest rates. (This survey did not officially include Orcas Power & Light Cooperative, a smaller Washington utility with a long-running green power program that has about 4.4 percent participation.)
Puget Sound Energy, the state's largest utility, has the most green power customers--about 3,500 as of November, and more than 5,200 as of early January, the utility reported. Seattle City Light had a slight lead over Puget in green power revenues as of September: $92,000 to PSE's $88,012, the report said. Seattle subsequently reported year-end revenues of $138,000. Snohomish County PUD ranked first in green power as a percentage of sales, at 0.057 percent, followed closely in this category by Tacoma Power and Avista Utilities.
Collectively, the 16 utilities sold 12.4 million kilowatt-hours (1.4 aMW) of green power from January through September--an average of 0.03 percent of total retail electric sales. Some 90 percent of the green power was derived from wind energy.
Total green power revenue came to $372,723 for the first nine months of 2002. Average green power revenues amounted to 0.015 percent.
Most programs offer green power blocks to customers, and generally derive green power from direct power purchases, green tags or Bonneville Power Administration's Environmentally Preferred Portfolio. Benton, Chelan, Seattle and Tacoma Power solicit contributions, while Clallam County PUD offers a 6.9 cents/KWh flat rate for a resource mix with landfill-gas energy--the only Washington green power program without a higher price to participating customers than conventional electricity.
What Do The Numbers Mean?
The overall Washington green power numbers are proportionally quite small. Yet these are mainly new programs selling a relatively unknown and amorphous product, in one of the nation's most troubled state economies.
"It's a market that is very immature [with] customers who are not very knowledgeable," said RNP's McIntire. "It takes a while to get enough people signed up and aware and understanding." Nationally, she said, 2.5 percent to 3 percent is considered a "very respectable" participation rate for green power programs; she believes Washington utilities should target that range over the next few years.
The state report quotes a National Renewable Energy Laboratory report that the total national green power market was about 1 percent as of October 2001. NREL also cautioned that new markets take considerable time to mature, citing the experience of long-distance telephone service, bottled water and recycling.
CTED and WTUC believe Washington's numbers will grow, but they suggest an ultimately limited market for optional green power ventures. As evidence they point to Eugene Water & Electric Board's Windpower program and its 3.25-percent participation rate. "Given the environmental nature of the Eugene community, the program's rate stability feature, the number of years this program has been available, and the program's high visibility, EWEB's program may represent the upper end of the penetration rates of voluntary, customer-driven green power procurement programs in the Northwest."
Challenges, Highlights, Recommendations
Washington utility officials described several challenges in their green power ventures, the report said.
Marketing and recruitment of customer participants is one major challenge. Utility rate increases have made premium-priced green power a tough sell in many areas, according to the report. One utility official wondered how to go "beyond demographics of 1-3% of the customer base. How do you market to ... the non-true blue environmentalist? If we want renewables to be successful we need to transform the market."
McIntire agreed that marketing is "always a challenge" for green power, especially for smaller utilities with fewer resources. But she also said help is available through her organization, Bonneville Environmental Foundation and other potential partners.
Another marketing barrier identified in the report is the "complex and somewhat abstract nature of electricity ... Utility representatives said it was difficult to explain to people where their money was going to and what they were getting for it. This was especially true with utilities that offered green tags."
Several utility officials reported they felt "significantly limited" in their marketing by the legislation's mandate that, "All costs and benefits of this voluntary program shall accrue to program participants." McIntire said this provision is subject to interpretation. "The [green power] benefit does go to all the customers," even non-participants.
On the plus side, Washington utility representatives shared tales of favorable public and media response for their programs, "enthusiastic accounts of the success of forming alliances within the utility's community," support from local governments and recognition of commercial customers.
Suggested improvements largely focused on expanding participation, the report said. Among the ideas offered were better marketing (such as more relevant messages), locally produced green power (as in Chelan County) and expanded commercial customer outreach.
Asked for recommendations to policymakers, some utility representatives suggested renewables be incorporated into the overall resource mix rather than through a voluntary green power program; increased incentives for customers and suppliers of green power (e.g., tax breaks); keeping programs simple; changing the cost-benefit section to enable marketing and/or administrative costs to come from a utility's general fund; and more government-funded research on green power costs and benefits.
The report concluded: "This program has been a catalyst for renewable resource investment, especially by the investor-owned utilities. As a result, newer, non-hydropower renewable resources are becoming more available to customers in Washington." Specific resource investments were not available, although the report said all 16 larger utilities spent money on renewables for their green power program and/or their overall resource mix.
Non-hydro renewables accounted for about 1.3 percent of total utility retail sales in Washington in 2001, predominantly from biomass, the report said. Wind power's share is expected to grow in 2002.--Mark Ohrenschall
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A recent change to the Washington State Energy Code allows more window area for new residential multifamily high rises in Washington--and, presumably, higher energy consumption.
This code revision, however, reflects a marketplace reality, according to the state's Building Code Council, which unanimously approved the modification in November, effective Jan. 1.
"The council finds that greater glazing area is related to the economic viability of apartment buildings," reads the BCC ruling. "The council finds the rule proposed in 2001 may be an economic burden on the building and design industries, which could result in an increase in the cost of housing for multi-family residential buildings including hotels, apartments and condominiums." Although not permanently effective until the end of Washington's 2003 legislative session, this emergency rule "is necessary to avoid delay in the construction of high-rise multi-family residential buildings, and to avoid adversely affecting the state's building industry, building owners, and building tenants by possibly imposing an economic penalty," the BCC concluded.
More stringent residential building envelope standards were part of 2001 changes to the state energy code, motivated by the energy crisis and a desire to save energy (see Con.WEB, Dec. 20, 2001).
These new envelope requirements, however, made virtually no distinction among residential building types and fuel sources, according to the BCC. They set a baseline of 0.40 U-values for vertical glazing and 15 percent glazing area as a percentage of total square footage. "There was an unlimited glazing path as part of that deal, but it applied only to single-family," said BCC managing director Tim Nogler. Some developers "felt this was unworkable for a high-rise residential construction."
An analysis found that using more-efficient windows was cost-effective, Nogler told Con.WEB, "but the council's decision was at least in part based on the market and the need in this type of building to have a greater glazing area."
High-rise developers can now follow a prescriptive path allowing unlimited glazing and a 0.35 U-value for vertical glazing and another path allowing 25 percent glazing area, both presuming other criteria are met, said BCC staffer Krista Braaksma. High-rise developers like to say, "If you're not getting a yard, you're getting a good view," she reported.
A technical advisory group to the council "looked for an approach that would both create a structural change in the code language that distinguishes the two types of structures [single-family and multifamily] as well as the reasonable balance point for energy efficiency and style of construction that reflects the market demand for multifamily units," said BCC chair Stan Price.
The city of Seattle opposed the change. Mayor Greg Nickels wrote to the BCC that many high rises will be built in the state's largest city, which can't adopt its own residential energy code. "We believe it would be a disservice to the citizens of Seattle to require that the City of Seattle purchase more power for the next 30-50-100 years to serve less-efficient highrise residential buildings. This is not good public policy as this money will flow out of the City, out of the State, and out of the region." No figures were available on the kilowatt-hour impact of the code change, although Nogler said "it could be a significant amount more energy" over a building's lifetime.
Renewable Energy/Green Power
|The 25-kilowatts-capacity solar PV system on the Pacific Cooperative building.
(Courtesy of Advanced Energy Systems)
The California Energy Commission, however, reported that overall peak demand rose slightly from 2001 to 2002, though it remained below 2000 levels.--Mark Ohrenschall [Lulu Weinzimer of California Energy Markets contributed to this report].
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