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Funding Support from the Northwest Energy Efficiency Alliance


1) New 41-MW-Capacity Oregon Wind Farm Represents a First for PacifiCorp, Energy Trust
2) Third Major Wind Farm Proposed for Central Washington
3) Prototype Failures Hurt Washington Companyís Effort to Create Innovative Wind Turbines
4) Proposed Seattle Initiative Would Raise City Light Residential Rates 1 Percent to Fund Small-Scale Renewables Production
5) Northwest Projects Explore Smart Energy Network
6) Portland Building Professionals Address Green Building Issues
7) PacifiCorp, PGE Residential, Small Business Customers Can Opt for Time-of-Use Rates in 2004


New 41-MW-Capacity Oregon Wind Farm Represents a
First for PacifiCorp, Energy Trust

A new wind farm with several distinctions is rising in northeastern Oregon.

The 41-megawatt-capacity Combine Hills Turbine Ranch 1 will deliver the first Oregon wind-generated electrons directly to PacifiCorp customers, under a 20-year power purchase agreement.

It also marks the first big renewable energy project funded by the Energy Trust of Oregon, which will pay $3.8 million to cover the above-market costs of Combine Hills electricity. The public-purposes funding agency, which issued a request for wind proposals about a year ago, will own the projectís green tags and pass them to PacifiCorp for its Oregon customers.

Wind Long
Vansycle Ridge Wind Farm, shown here, will soon have
another neighbor in Combine Hills Turbine Ranch 1.
(Photo by Mark Ohrenschall)

Combine Hills marks a "unique partnership of public and private interests," ETO renewable energy director Peter West said in a news release.

Scheduled for completion by yearís end--just in time to secure the 1.8 cents per kilowatt-hour federal wind energy production tax credit--Combine Hills will join neighboring Stateline Wind Energy Center and Vansycle Ridge Wind Farm in what is becoming a "wind and wheat belt" of northeastern Oregon and southeastern Washington.

Developer Eurus Combine Hills received Umatilla County land-use approval in November 2002 for 104 MW of wind capacity, but there are no definitive plans for the remaining 63 MW, according to a company official.

Three-Way Project

Combine Hills is a three-way venture involving PacifiCorp, the Energy Trust and Eurus Combine Hills, a subsdiary of Eurus Energy America.

"Organizations like us typically stay on the sidelines for the PPA [power purchase agreement] part," the Trustís West told Con.WEB. "Either they go out and they subsidize the project before the utilities have chosen it, or after, and that creates its own set of issues. It occurred to us: Why not go in arm and arm with the utilities? So we did, and I think thatís one of the unique things" with this wind farm.

Tom Farnham, project administration manager for Eurus Energy America, said the Trust created this opportunity for Combine Hills. "It wouldnít happen without them," he said.

ETO issued a request for wind proposals in July 2002, seeking energy and environmental attributes from new or expanded Oregon projects, in the range of 25 MW to 100 MW capacity, selling power to PacifiCorp and/or Portland General Electric. The Trust set a commercial operation deadline of Dec. 31, 2003, coincident with the currently scheduled expiration of the federal production tax credit. The ETO allocated up to $8.3 million to pay for above-market costs of this wind-powered electricity, a significant step toward meeting the agencyís near-term goal of 35 average megawatts of renewables generation by late 2004.

This solicitation yielded seven responsive bids totalling 604.5 MW of capacity, at an average 20-year levelized cost in the range of 3 cents/KWh to 4 cents/KWh at the busbar, West reported last fall.

Two finalists--Combine Hills and a proposed addition to Northwestern Wind Powerís 24-MW-capacity Klondike wind project in Sherman County--were announced in October. ETO board members approved the major contract terms with Combine Hills in December.

The proposed Klondike addition encountered some financing difficulties, West said. With the Eurus project, "We could get more bang for the buck, more megawatts, the least amount of subsidy. In the end we ran out of time with Northwestern ... We had to make a call. We wanted to beat the production tax credit [deadline]."

Among the issues in concluding the 20-year power purchase agreement were transmission and credit arrangements, he said. "This is also a unique project in that effectively the power is ... a network resource," linked to nearby PacifiCorp transmission lines to serve the investor-owned utilityís customers in its Pacific Power and Utah Power territories.

The Combine Hills deal also took shape in the midst of challenging financial conditions for the energy industry, West noted.

PacifiCorp already obtains electricity from more than 70 MW of wind capacity in Wyoming. "This is the first large-scale long-term wind from an Oregon source," said utility spokesman Deston Nokes. "It really came about because of the Energy Trust."

ETOís $3.8 million contribution--a lump sum payable to Eurus upon the projectís completion and commissioning--represents the difference between Combine Hills costs and PacifiCorpís avoided cost for resources with similar characteristics, West said. That final amount was reduced from an originally planned $4.1 million.

The Trust allocated $8.3 million for wind ventures for PacifiCorp and PGE, whose customers shell out public-purposes funding admininstered by ETO. Since Combine Hills ultimately didnít work for PGE, West said the Trust will earmark half that total wind allocation for renewables under PGEís recent request for power supply proposals. "Itís more than unfortunate that we couldnít figure out, through this one, to also have a project for PGE. Really what happened in the end was time, time to work out the issues on this deadline, trying to beat the PTC ['s expiration]."

ETO will own the green tags from Combine Hills, but will give these environmental attributes to PacifiCorp as they are created by wind-generated electrons, according to West.

Combine Hills "is showing that the intent of [Senate Bill] 1149 [Oregonís electric industry restructuring and public-purposes funding law] in this respect is working out," said Nokes. "Part of the intent was to bring more renewables development to Oregon, and this is showing this is happening."

He said this wind power purchase is separate from PacifiCorpís intent to add 1,400 MW of new wind capacity to its system over the next decade, as envisioned under its latest integrated resource plan.

Combine Hills Turbine Ranch 1

The 41-MW-capacity project will occupy ridge lines and hilltops on the north end of and below Vansycle Ridge, according to the Umatilla County Planning Commissionís findings and conclusions for a conditional-use permit. It will lie about six miles west of Milton-Freewater and about three miles east of FPL Energyís 299.6-MW Stateline and 24.9-MW Vansycle Ridge wind farms.

Combine Hills earned unanimous planning commission conditional-use approval in mid-November. It generated very little controversy and gained broad support from neighboring farmers and landowners, according to county Resource Services and Development director Dennis Olson.

The 13,375-acre privately owned site leased to Eurus is predominantly used for dryland wheat farming and livestock grazing, surrounded by "sparsely settled agricultural lands," according to the commission document. About 18 acres will be permanently disturbed for this wind farm, which is permitted for up to 104 MW capacity--1 MW short of the threshold for jurisdiction by the stateís Energy Faciliting Siting Council, Olson noted.

The project is anticipated to have little or no discernible impact with scenic values, noise, wetlands, wildlife habitat and cultural resources, according to the planning commission. Bird and bat monitoring studies will be conducted. Olson said a couple of citizens expressed concern about the spread of weed controlling spray; this was addressed in the conditional-use approval.

Eurus plans to erect 1-MW Mitsubishi turbines. Other infrastructure includes underground electrical cables connecting individual turbines, some overhead collector lines and a new substation. The developer estimated a need for 60 to 100 construction workers.

As of July 11, "Everything is basically going right along" with the Combine Hills construction process, Farnham told Con.WEB. "Itíll be done by the end of the year." Eurus also is working on arrangements for the other 63 MW of permitted capacity, he said.--Mark Ohrenschall

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Wind Rush

Third Major Wind Farm Proposed
for Central Washington

A third major wind farm is proposed for central Washingtonís Kittitas County, raising the countyís announced potential wind capacity to more than 525 megawatts.

Zilkha Renewable Energy on July 1 unveiled plans for a 165-MW-capacity wind project about 13 miles east of Ellensburg, the county seat. The Texas-based firm also is developing the proposed (and controversial) 181.5-MW-capacity Kittitas Valley Wind Power Project some 12 miles northwest of Ellensburg, close to yet another prospective local wind farm, a 180-MW-capacity venture planned by enXco.

Wind Farm Site
The proposed Wild Horse Wind Power Project
would be located in the distant vicinity shown here.
(Photo by Mark Ohrenschall)

Zilkhaís newest proposal, the Wild Horse Wind Power Project, reflects "strong utility interest being expressed right now in wind power," project development manager Chris Taylor told Con.WEB. He specifically mentioned Puget Sound Energy, Avista Utilities and PacifiCorp as examples. "Thereís a lot of demand out there, more than just our Kittitas Valley project can meet."

Taylor said Zilkha will seek approval for Wild Horse from the Washington Energy Facility Site Evaluation Council, as the company has for its other project in the wind-raked county stretching from the Cascade Mountains to the Columbia River. EFSEC, as part of its review of Zilkhaís Kittitas Valley project, recently directed the firm to pursue compliance with Kittitas County wind farm regulations. EnXcoís project, known as Desert Claim, is exclusively within the countyís permitting process.

A leading opponent of Zilkhaís proposed Kittitas Valley project, Geoff Saunders of Residents Opposed to Kittitas Turbines, called the remote Wild Horse site "far more appropriate" for wind development. He urged the company to withdraw its Kittitas Valley proposal and seek county approval for Wild Horse. Taylor said Zilkha will proceed with both ventures.

Wild Horse Wind Power Project

Wild Horse Wind Power Project would be located on 5,000 acres sloping down from Whiskey Dick Mountain, about 10 miles northeast of Kittitas. The site is part of the 25,000-acre Parke Creek Ranch, which primarily hosts livestock grazing, according to Zilkha officials.

The location is well-known among wind developers, Taylor said. Al Davies of Caurus Power negotiated property rights with the single landowner in 2001, and subsequently approached several wind developers. "Ultimately, we decided to work together on this," he said.

Zilkhaís announcement stems from this new site access as well as expanding utility attention to wind, as shown by least-cost plans from utilities including Puget, Avista and PacifiCorp, he said. Zilkha expects to bid Kittitas County wind power in response to utility solicitations. Public-power utilities are another potential market.

"We think thereís more than enough demand out there for both of these projects," he said. "We feel well-positioned. We think these are two of the best wind power sites in the Northwest, in terms of [wind] resource and transmission."

The Wild Horse and Kittitas Valley sites have "comparable" winds blowing across them on an annual basis, he said, although Wild Horse is slightly higher in elevation and receives more winter storm-driven winds. "Our two sites tap the wind as it sweeps through the county," said Taylor in a news release. "We catch it literally coming and going."

Two sets of Bonneville Power Administration high-voltage transmission lines run nearby, as do smaller Puget wires.

Although the project is announced at 165-MW capacity from about 100 turbines, Taylor described those numbers as "approximate" and subject to change based on power market prices and wind technology advances, among other factors.

He called the 5,000-acre location "very remote," with no structures for several miles. Initial investigations have revealed no major permitting issues regarding birds and other animals, plants or cultural resources, he said.

Zilkha wants to apply for project approval to EFSEC instead of Kittitas County for the "exact same reasons" the company went to the Council with its Kittitas Valley project, he said. "Itís a rigorous process to get all the issues out on the table and address them. Second of all, it is the appeal track issue. If there were an appeal, and we donít expect one, it would be expedited Ö Weíre wanting to be able to move forward on a timely fashion." Zilkha, which has already requested of EFSEC a potential site study for Wild Horse, expects to complete the wind farm by year-end 2005 at a projected cost exceeding $175 million.

Location Issues

This location is "far more appropriate" than northwest of Ellensburg, as "there are no scenic issues, no environmental issues (to our knowledge), and it would not impact landowners or tourism," Saunders told Con.WEB in an e-mail.

"The wise strategy for Zilkha would now be to withdraw its request with EFSEC for the [Kittitas Valley] project and to apply to the county for a permit for the Whiskey Dick Mountain project," he wrote.

Taylor affirmed Zilkhaís intentions to develop both proposed wind farms. Wild Horseís only real effect on Kittitas Valley will be to expand cumulative impacts explored in environmental impact statements, he said.

Wind Projects Reviews

Zilkhaís 181.5-MW-capacity Kittitas Valley project remains under review by EFSEC, but a recent twist has sent it to the county.

EFSEC in early May determined the proposal didnít comply with Kittitas County regulations for wind farms, and it directed Zilkha "to make the necessary application for change in, or permission under, the Kittitas County land use plans or zoning ordinances, and make all reasonable efforts to resolve the noncompliance," according to the May 7 order.

This conforms to EFSEC rules for proposed energy projects that are found not to meet local standards, said EFSEC manager Allen Fiksdal. He noted Zilkha acknowledged its non-compliance with the countyís new siting rules for wind farms, adopted in December.

Accordingly, Zilkha has applied to Kittitas County for a development agreement, development permit, a rezoning and a comprehensive plan amendment, all conditioned on EFSEC approval.

EFSEC, meanwhile, has extended to Sept. 1 Zilkhaís deadline for reporting on its efforts to resolve zoning and land-use issues with the county. The company can ask EFSEC to supersede local regulations, Fiksdal said.

EFSEC plans to finish a draft environmental impact statement by late August or early September, Fiksdal said. "Thereís some significant issues that need to be addressed," including prospective impacts on views, birds and animal migration. These and other topics were raised at a March 12 meeting in Ellensburg (see Con.WEB, March 27, 2003, for a column on Kittitas County wind farms).

Kittitas County will likely schedule a public hearing on the Zilkha application after the draft EIS is finished, county planner Clay White told Con.WEB. He said he anticipates the board of commissioners will make a decision by January, but it could be later. The enXco project is tracking a similar timetable through the countyís process, White said.

The EIS drafting could take longer to incorporate cumulative impacts from Zilkhaís second proposed project, according to Fiksdal. EFSEC plans to render a decision on the Kittitas Valley project by February, he said, after which Gov. Gary Locke will have 60 days to approve or deny the application, or send it back to the council for reconsideration.--Mark Ohrenschall

More Information:

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Accidents Happened

Prototype Failures Hurt Washington Companyís
Effort to Create Innovative Wind Turbines

A Washington companyís long effort to create an innovative wind turbine to generate low-cost electricity is foundering.

The Wind Turbine Co. has sustained two accidents on a prototype turbine in the past year or so, the most recent a rotor shaft break in early June. Meanwhile, the Bellevue-based firm also has failed to attract sufficient capital for a $15 million cost-sharing contract with the U.S. Department of Energy, which could spell the pactís end in the near future, a National Renewable Energy Laboratory official told Con.WEB.

Company and NREL officials believe the two breakdowns do not reflect on the technical viability of The Wind Turbine Co.ís novel turbine design--a lightweight, flexible, two-bladed, downwind-facing machine with proprietary rotor hub technology that could potentially generate power in the unsubsidized range of 3 cents per kilowatt-hour. The rotor shaft fracture and an earlier electronic device failure that caused a blade to strike a tower "arenít indicative of problems in the technology," said NREL's David Simms. "Itís more just unfortunate circumstances."

He compared the mishaps to flat tires on a new-design car. But he acknowledged they have made it harder to attract investment dollars.

WTC president Larry Miles sees a larger problem for his company. "The private market for investing in wind technology in this country has been ... abysmal," he said. "People have no interest, or have had to date little interest in wind technology."

Simms suggested the wind industryís expansive growth has actually hurt The Wind Turbine Co., as developers opt for conventional and cost-effective three-bladed upwind turbines, in ever-larger sizes, to meet growing demand (U.S. installed capacity has grown an average of nearly 25 percent the past five years).

The Wind Turbine Co. is assisting DOEís investigation of the rotor shaft failure while "exploring a number of options" for its future, Miles said, including selling part of the company and licensing the technology. Several entities have shown interest since the recent accident. "We still have considerable faith in the technology and the question really is how, since we are not long on financial resources ... what the government will end up doing."

Wind Turbine Accidents

WTC started operating a 500-kilowatt-capacity prototype turbine in Southern Californiaís Antelope Valley in early 2002, on Los Angeles Department of Water and Power property, according to Windpower Monthly.

In early June, Miles said, the rotor shaft to which the two blades are connected broke off the turbine tower and fell to the ground. The blades stayed on the shaft, and the tower and nacelle remained standing. "It would be analogous to a wheel coming off of your car," said Miles. This mishap near one of two branches of the Los Angeles Aqueduct caused no injuries or other damage, he added--except to his company.

DOE has "basically put things on hold" pending an investigation into why the accident happened, Miles said.

This follows another accident about a year earlier, with the same machine. Miles said an electronic device in the pitch system failed and led to a persistent "runaway condition" in which a blade "drove itself back upwind and into the tower, and took a chunk off of the tip of the blade."

He said itís possible--but still unknown--that this earlier incident contributed to the rotor shaft break.

"Other than that, I guess the joke goes: ĎHow was the play, Mrs. Lincoln?í" he said, adding, "The machine had performed pretty well, Iíd say. We had no reason to believe there was anything really wrong with our concept." A 250-KW-capacity prototype is still running fine after several years in Colorado. Simms said. This initial machine "had more significant factors of safety built into it," given the uncertainties of WTCís new technology, with its 40-percent lighter weight and greater structural flexibility than conventional turbines.

Miles said his company operates on a "shoestring budget" that "caused some compromises necessarily to be made," including limited review and testing of components in the prototype. "Unfortunately, these are the kinds of outcomes that one can expect when you have to make compromises."

Insufficient scrutiny of control software contributed to the first accident, Simms said. Now, "It looks like maybe there was a flaw or a problem in the fabrication of the shaft on the turbine, which is why the shaft broke. It doesnít indicate this load-mitigating technology is not working. It very well indeed looks like it was working."

Nevertheless, the $15 million contract awarded by DOE to The Wind Turbine Co. in 1997 (see Con.WEB, July 25, 1997) may be nearing an end. "The outcome of the failure analysis ... will help us decide what direction to move in," Simms said. "We donít have money to continue beyond a few months ... unless The Wind Turbine Co. is able to find somebody who is willing to cost share to meet their [30-percent] cost-share obligations." Otherwise, "Weíll be closing out the contract, probably within a few months." This would have happened regardless of the accidents, he noted.

Miles said the project has rung up about $14 million in total expenses, including $12 million from DOE. The state of California pitched in nearly $1 million in 1998.

WTC has laid off two employees, and 10 remain, Miles said. "Weíre getting actually a fair amount of interest from parties that we had been talking with before, in terms of investment." Among the possibilities, he said, are selling part of the company to raise money and licensing the technology.

Since the accident, a private investor has shown interest in investing in the company, Miles said, and two large manufacturers have inquired about buying the firm. He declined to share names. The Wind Turbine Co. has in the past approached General Electric, Caterpillar and United Technologies about manufacturing the turbine, he said.

Wind Technology Marketplace

Simms and Miles offered varied perspectives on the wind technology marketplace, and The Wind Turbine Coís role in it.

Miles said Europe far outpaces the United States in wind technology development. Indeed, nine of the top 10 wind turbine suppliers in 2002 were based in Denmark, Germany or Spain, according to Windpower Monthly, citing information from BTM Consult. The only top-10 U.S. entrant, GE Wind Energy, ranked fifth with a 9.1-percent total market share.

"Itís kind of amazing from my perspective there is only one U.S. company that sees an opportunity in this business," Miles said. "It does beg the question: Why isnít it happening in the United States?" He also compared the state of wind technology to 1960s-era automobiles: "There isnít a Japanese car out there, or a front-wheel-drive vehicle."

Miles thinks the U.S. wind industry is more focused on public policy than technology, with its strong emphasis, for example, on renewing the federal wind energy production tax credit.

Still, Simms believes the emergence of a unit of business giant General Electric (2002 revenues: $131 billion) has made an impact on European wind companies. "When a big entity like that gets into the business, other people start to take notice and itís really mushroomed. Traditional European suppliers, seeing GE on their coattails, [are] innovating, developing product lines. They tend to be much slower and more systematic in their advances."

He believes The Wind Turbine Co. faces "a huge burden to overcome" in the marketplace. "The industry is booming now and conventional turbines are cost-effective," making a difficult sell for new concepts, even those with promising lower-cost technologies.

Although two-bladed downwind turbines have been explored before, WTCís project is inherently dicier than other turbine ideas funded by DOE, according to Simms. "Thereís a lot of potential there, but because they are kind of leapfrogging potential technology, we knew there was quite a bit of risk." He also noted the WTC prototypes are proof-of-concept models, and mechanical problems are part of the learning process.

With the 70-percent/30-percent cost-share contract, "Itís really our objective to give them this opportunity and try to help them out and try to demonstrate that this technology can really work," Simms said. "Thatís why itís so unfortunate they werenít able to keep up these cost-shares and these failures occurred. We still donít really know the answer to the question: Is the technology feasible? Is it worth pursuing?" He thinks a knowledgeable wind entity willing to assume some risk could bring WTCís concept to commercialization.

"I think the future has probably never been brighter for wind energy and prospectively never brighter for ourselves," Miles said. "Unfortunately, these kinds of [accidents] happen. Weíve basically got to convince people that it was not an inherent design flaw as much as it was an understandable event that presumably can be remedied and wonít repeat itself in the next machine."--Mark Ohrenschall (Steve Ernst contributed to this story)

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1 Percent for Renewables?

Proposed Seattle Initiative Would Raise City Light Residential
Rates 1 Percent to Fund Small-Scale Renewables Production

A proposed Seattle initiative measure would increase Seattle City Light residential rates 1 percent to pay for local solar- and wind-generated electricity.

Initiative 81 would initially deliver about $1.5 million annually into a fund paying up to $1.50 per kilowatt-hour to owners of small solar and wind installations in the Emerald City. It would cost the average Seattle resident about $5 a year over the proposed 10-year program life, according to proponents.

"Initiative 81 will produce thousands of [renewables] systems throughout Seattle, and will provide vital funding to make it cost effective for residential customers to install renewable energy systems," according to the proposalís Web site. "This program greatly increases Seattleís commitment to new jobs, distributed energy, and sustainability."

At City Light, meanwhile, "We donít really have a position on [Initiative 81] at this point,Ē spokesman Dan Williams told Con.WEB. "Itís fairly new, and weíre thinking about it internally."

Wind Farm Site
Solar photovoltaic systems, such as this one on a Seattle home, would presumably
become a more common sight in the Emerald City if Initiative 81 is approved.
(Photo courtesy of Puget Sound Solar)

An estimated 3,000 registered Seattle voters had signed Initiative 81 petitions as of early July, said Puget Sound Solarís Jeremy Smithson, who is involved with the proposal. Sign-up boards placed around town and signature-gathering at big summer events are planned to boost the numbers, he told Con.WEB in an e-mail.

The campaign needs at least 17,229 valid signatures turned in by Aug. 20, according to city clerk Judith Pippin. After a signature validation process the initiative would be submitted to Seattle City Council, which would have 45 days to enact it or submit it to voters in an election.

Initiative 81 is patterned after a solar-electric program developed in Germany, according to Smithson.

The proposal also bears some resemblance to Chelan County PUDís Sustainable Natural Alternative Power (SNAP) program, which pays local renewable energy producers up to $1.50 per KWh from local funding. In Chelanís case the money comes from voluntary customer green power payments and not a mandatory utility rate increase as envisioned in Seattle.

Initiative 81

Initiative 81 was filed with the city of Seattle in late March, Smithson said, after the expiration of proposed Washington legislation that would have established a statewide solar power production incentive from the state utility tax and an incentive for solar-electric manufacturing in eastern Washington.

I-81 is virtually identical to a venture originated in the German city of Aachen in 1992, he said. "It is a proven program; 30 or so other German cities adopted the Aachen model and then it became a national program. The result: Germany is No. 2 in the world for grid-connected solar power ... While we cannot necessarily repeat the German success here in the U.S. Seattle could prove to be a leader in renewable energy by adopting such a program and showing the rest of the country how it is done."

The Seattle proposal would impose a 1-percent rate increase for SCL residential customers (exempting low-income households) and earmark the accumulated dollars for local solar and wind producers with systems sized up to 5 kilowatts. An estimated $1.5 million would accrue in this fund each year, based on the current number of SCL residential customers paying $5 apiece.

City Light would administer the fund. It would pay individual renewables producers that feed power into the utilityís distribution system "the total money deposited in the Fund for the applicable year divided by the total electricity produced by all the Generators during that year," up to $1.50/KWh, according to the initiative. Any remaining dollars would carry over to the next year.

"As more systems come on line, the payments will be spread across a wider and wider number of participants," said the I-81 Web site. "The program rewards the risk takers who invest early more than later participants. Later investors will enjoy the benefits of lower-priced systems. The systems will keep producing power for 20 to 30 years after the program is over."

A 1-KW solar-electric system in Seattle would generate about 1,000 KWh annually, the Web site said. On this basis a producer could get $1,500 a year from the fund--a payback of less than six years on a "carefully shopped" system with "easy installation" that could cost as little as $8,000.

On the ratepayer side, the average SCL annual residential bill amounts to about $500--a 1 percent increase would equal about $5.

"The premise of the initiative is elegant," said Smithson. "After Seattle City Light has raised our rates by more than 60 percent because of poor decision-making, a 1-percent increase dedicated to solar energy seems just." Distributed solar would complement SCLís hydro base, he said--"most of the solar generation will occur when the reservoirs are low, and when there is plenty of water, the sun takes a vacation."

Among the benefits, according to the initiative Web site, are making renewable energy cost-effective in Seattle, providing clean and reliable power, giving residents more control over their energy future, reducing reliance on fossil fuels and hydro (in summer), promoting economic development and diversifying power sources.

City Light already offers a green power program that collects voluntary customer dollars, of which 40 percent are invested in local solar-electric demonstration projects at schools and other public facilities. Initiative 81 would create a "much larger revenue stream" to fund renewables, the Web site said.

Getting to A Vote

Although petition signatures were well short of the required total number as of early July--roughly 3,000 out of 17,229--organizers hope to pick up the pace through summer. Thirty sign-up boards were being placed in "key areas" in early July, Smithson said. Signature-gathering efforts also were planned at major local events such as Bite of Seattle, Seafair, Bumbershoot, Hempfest and outdoor concerts, the Web site reported.

If the campaign achieves the signature goal and the Council quickly opts for an election, a potential vote could be held in November, Pippin told Con.WEB. I-81 also could be placed on the primary election or general election ballot in 2004, she said.--Mark Ohrenschall

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Smart Energy Network

Northwest Projects Explore Information/Communications Technology
Links with Energy Infrastructure for More Efficient Grid Operation

If you were never proficient at economics, at least your refrigerator could be in the future.

A new report by Patrick Mazza of Climate Solutions outlines how automated appliances and distributed generators could team up to compete with peaking power plants and help combat price spikes.

Research and pilot projects, including several in the Northwest, are either in progress or soon to be launched, pairing information and communications technology with energy infrastructure for more efficient grid operation--economically and environmentally.

Mazza's report, "The Smart Energy Network: Electricity's Third Great Revolution," offers an overview of where the early buds of this capability are cropping up, and how the Northwest could be an ideal test bed.

Theoretically, if all resources were fitted with intelligent control devices and an Internet connection, price signals could be exchanged transparently throughout the grid. Each resource would then decide independently whether to begin generating kilowatts or curtailing load, based on calculations of economic benefits, grid optimization and owner preferences. At full deployment, a central operator would not only be obsolete, but practically incapable of optimizing the vast network of distributed resources, necessitating distributed intelligence and distributed control.

Intelligent Control Capability

Intelligent control capability has already been developed by the U.S. Department of Energy's Pacific Northwest National Laboratory, which has developed a form of smart computer chips that can make decisions based on measurements of grid signals. Modifying these to make decisions based on price signals is merely a question of altering them slightly for a different application, according to Steve Widergren, a scientist in PNNL's Energy Technology Development group. If all refrigerators in a region knew when skipping a defrost cycle could make their owners some money without melting food, utilities could skip building some new power plants.

And save some money themselves. The current national investment backlog on grid infrastructure upgrades could result in critical, localized shortages by the end of the decade; the cost of keeping up with demand growth projected by the Energy Information Administration could reach $450 billion through 2020, according to a PNNL economic forecast.

In contrast, the PNNL scenario for rapid adoption of smart energy technology produces an estimated $78 billion in benefits: $10 billion from lower interest rates on infrastructure upgrades with lower risk than transmission line projects; $10 billion in energy efficiency savings through advanced controls and sensors; $5 billion in fewer outages; $3 billion in lower plant operation costs from higher operating efficiencies; and $50 billion in foregone investments in 100 gigawatts of new centralized capacity.

But even PNNL scientists admit the rapid adoption scenario is unlikely; electrical engineering is a cautious field. After having developed the smart control devices, PNNL scientists are now working on modeling and simulating the cooperation of electrical networks and markets running simultaneously, to give engineers the tools to become familiar with the new concept and its potential and pitfalls. In the lab, projects are focusing on both distribution and transmission systems, and how system behavior changes with the introduction of demand response technology at different locations.

Northwest Forays into Smart Grid

Northwest stakeholders are beginning to make forays into the smart grid field.

The region is ideally suited to make headway because of the unique cluster of advanced technology companies, Mazza said. Spokane, WA-based smart meter and software maker Itron has shown consistently strong business growth throughout the down economy. Another Spokane company, fuel cell maker Avista Labs, is already finding niche markets for its hydrogen fuel cells. Celerity Energy of Beaverton, OR and Portland General Electric have been working separately on pilot projects for remote dispatch of distributed generators as networked peaking plants.

The first field connections in pilot projects with Bonneville Power Administration's Energy Web program will begin this year, with 60 Northwest energy resources in the pipeline for demonstration opportunities, BPA energy efficiency vice president Mike Weedall told participants at the Hydrogen Production and Northwest Transportation conference in Seattle June 16.

The first project, the Olympic Peninsula Reinforcement, is expected to start coming online in September. This pilot will connect some 10 or 12 distributed generation units and some industrial customer load-shedding capabilities on Washington's Olympic Peninsula, and aggregate the power using remote control, monitoring and communications technology. A joint effort by Celerity Energy, the Energy Web program and BPA's Non-Construction Alternatives to Transmission initiative, the pilot will help test whether Energy Web-type tools and thinking can avoid building new transmission lines to the peninsula, and whether that has economic value. BPA international sustainable energy expert Terry Oliver said that "by being able to aggregate and link these kinds of resources together, you could purposefully change the load-duration curve in ways that could benefit the transmission system as well as the energy system."

The Energy Web projects are seeking to learn the value--either financial or engineering--of aggregating demand management and distributed generation, and coordinating their deployment. In another potential project under discussion with BPA and the city of Milton-Freewater, OR, water heaters, space heaters and air conditioners could be used to fill in the gaps when Energy Northwest's Nine Canyon Wind Project generates less energy than forecast.

The cityís municipal electric utility currently operates a load-reduction program to remotely cycle those appliances off to save energy. "[C]ould you have Milton-Freewater turn load off when the wind doesn't blow for Nine Canyon ... and could that sort of coordinated operation of demand-management resources and an intermittent renewable resource add value to either resource?" Oliver said. The biggest challenge is to install sensors and gather the right data to see if any benefit was created. "It's one thing to turn off load," he said. "It's another to know if it had any impact."

For the Olympic Peninsula project, part of the value will be in reducing skepticism and getting the Northwest utility industry more familiar with how a network of distributed resources works, Celerity Energy senior vice president Dennis Quinn told Con.WEB. Celerity manages two commercial projects in New Mexico and Colorado very similar to the Energy Web pilot, but "one entity's pilot program is another entityís commercial program."

In March, Celerity began providing 3.5 megawatts of power to Public Service of Colorado from standby dual diesel and natural gas-fueled generators owned by customers including a data center and a regional generator dealer. Using a Web-based program, PSCo can directly dispatch the generators. Using a similar network in Albuquerque, NM, Celerity provides seven MW of dispatchable peaking power to Public Service Company of New Mexico. These power networks can also provide local voltage and grid support

Since 2001, PGE has networked 10 MW of customer emergency standby diesel generators ranging from 750 kW to 2 MW that can be remotely dispatched by the utility during times of high peak prices. Over the next year or two PGE is trying to scale the project up to 100 MW. The capital costs of the system are only about one-third those of a peaking power plant, but wholesale prices need to be as high as $75 per megawatt-hour for dispatch to be economical. PGE has dispatched the system only once, last winter.

Celerity Energy's projects also have had a relatively high dispatch price--around $100/MWh, depending on the prices of diesel fuel and natural gas. But Quinn and Oliver both told Con.WEB the multiple potential benefits including grid support, peaking power, transmission deferral and having backup power during outages might make it worth it. Oliver said, "It's not, 'Will this resource work in competition with the hydro system?' It won't and it can't. But can it compete in certain market situations? Can it compete for other uses that are not quite obvious in a marketplace now?"

A big obstacle to expanding such a system to new distributed generation technologies, and to allowing those technologies to interface with each other without central control, is that many emerging DG systems don't have standard Ethernet communications capabilities, according to PGE distributed resources manager Mark Osborn. Once these communications pathways are open, expanding networks of generators will be much more practical, he said. However, many of these manufacturers are becoming aware of the advantages and are beginning to move toward an open standard, according to Quinn.--Ben Gilbert

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Talking Green

Portland Building Professionals
Address Green Building Issues

Why build to green standards?

Opportunity, ethics, client motivations and a dose of serendipity, according to Portland building professionals speaking at a recent green building panel discussion.

The panelists--a developer, an architect, a building designer/developer, a representative of a commercial contractor/construction management firm and a green building/sustainability consultant--also addressed strengths and shortcomings of the Leadership in Energy and Environmental Design (LEED) standards from the U.S. Green Building Council. Differing perspectives on cost played into the discussion as well.

Success indicators, the role of subcontractors and ecological footprints also were part of the May 23 dialogue at Jean Vollum Natural Capital Center. The event concluded a city of Portland series titled ĎReThink: Innovation in Ecological Design and Construction.í

Why Build Green?

Moderating the panel discussion, keynote speaker Ray Cole of the University of British Columbia--whose earlier talk touched on the importance of human dimensions in green building--asked the five panelists why they decided to build to the LEED standard and whether their projects achieved goals and met expectations.

Wind Farm Site
Lewis & Clark College Residence Halls
(Photo courtesy of DPR Construction)

Jonah Cohen of Thomas Hacker Architects said his firm had encouraged public- and private-sector clients to pursue LEED, and when it bought a 1913 structure for its own practice, "We had an opportunity to practice what we preach" and learn "what itís like to be in the ownerís shoes." He called it "really interesting to wear two hats and make the tough decisions to spend a little bit more money, understand the minutiae of going through the program ... I learned a lot; we all learned a lot."

Rob Fallow of DPR Construction said contractors usually donít choose whether a project seeks LEED, unless they participate early in the process, as his firm did with a Lewis and Clark College campus housing project. "We had a very forward-thinking owner and a great architect [SERA Architects] ... We were very interested in learning about it and pushing the envelope." After the first school yearís occupancy, Fallow said, an additional 75 to 100 students want to live in this complex. "Itís definitely successful in our eyes."

LEED/sustainability consultant Scott Lewis of Brightworks outlined two of his LEED projects: a small winery whose owner was "motivated by value" to build green, and a public-sector facility in southern California "motivated by institutional mandate." Different building owners have different reasons for following LEED, he said. "What Iíve observed is the information that informs those decisions varies considerably from different project types."

Wind Farm Site
The Brewery Blocks
(Copyrighted photo courtesy of Bruce Forster: www.viewfindersnw.com)

For Gerding/Edlen Development, building green "was an ethical decision," said senior project manager Dennis Wilde. "We just felt it was important as part of the culture of our company and who we were. We wanted to provide buildings and built environments that were a positive legacy and contribution to the future of the community. Building buildings that are more sustainable certainly seemed consistent with that." Gerding/Edlen is applying LEED to its five-block Brewery Blocks development in downtown Portland. "Was it worth it? We would say, resoundingly, absolutely." He noted the development is leasing "phenomenally well" in a slow market. "Thatís not exclusively because our buildings are LEED rated, but it contributes to the environmental tone and the ambience of that project thatís made it successful."

Kevin Cavenaugh was the building designer/developer for two local projects: Ode to Roseís and Box & One. "We ran through the [LEED] checklist for both projects, just for kicks," said Cavenaugh. Box & One achieved LEED certified and Ode to Roseís fell one point short of LEED silver, so he added an electric car charger. "Iím not necessarily smarter than anyone else. I just got lucky," he said.

Cost Issues

Does it cost more to build green?

"We donít see significant cost premiums," said Wilde. "Iíll argue with anybody that you can produce LEED silver for exactly the same first cost as a normal out-of-the-box typical building. The only premium weíre seeing is the design effort, primarily. Iím willing to pay a little extra up front for the integrated design approach." Wilde declared himself a longtime believer in this collaborative strategy. "No buildings built today are sustainable, but you canít even get close unless you have a really integrated approach involving the entire design team and owners all committed to a set of objectives."

Cavenaugh said his 5,100-square-foot Ode to Roseís project cost $72 per square foot and the 7,200-square-foot Box & One came in at $92 per square foot. "Itís fun to debunk the myth that building green, going LEED, is more expensive than not," he said.

Cohen, however, said he discovered "5 to 8 percent in identifiable costs we could point to, in professional time, above standard in the overall cost of the project. Itís a pretty significant amount." For his own officeís renovation, he told Con.WEB later in an e-mail, green building costs included commissioning, energy modeling, materials recycling, new HVAC and lighting systems above code minimums, bike racks, premiums for certified wood, additional roof insulation and consultant fees. "As the architects for the project, we also put an enormous amount of time into tracking and discussing LEED-related items for which we didnít get paid," he added.

Financial incentives from governments and utilities can help, Cohen said.

Lewis noted commercial developers can reduce green building costs with Oregonís Business Energy Tax Credit, which offers a 35-percent tax credit over five years for eligible sustainable building costs; this can amount to $140,000 for a 200,000-square-foot building that achieves LEED silver.

Cost considerations for green building tend to vary, according to Lewis. Institutional developers look ahead 50 years and beyond. Speculative developers, meanwhile, focus on the near term, but are open to ideas--improved indoor air quality or better daylighting, for example--that "might provide differentiation in the market ... Often that will motivate them." He also noted evolving cost circumstances, such as lower prices for LEED-conforming paints.


LEED standards themselves were a frequent discussion topic.

"I think itís important from our standpoint not to see LEED as an end in itself," said Wilde. "Itís simply a tool for measuring performance. There needs to be a bigger overarching set of objectives to define your purpose." Gerding/Edlen uses the Natural Step for that function.

LEED requirements, notably documentation, can be burdensome, according to panel participants.

"Everybody wants to do the right thing," said Cohen, but, "The reality of the documentation is totally overwhelming to some sub[contractor]s. If you donít warn them at the beginning whatís expected, youíll end up with a situation where you ask for a lot of free work, or they get resentful, putting in a lot more time than expected." His experience with LEED paperwork was "frankly pretty frustrating," even with consulting help. "Itís a trial-and-error process," said Cohen. "I suspect the paperwork part will ultimately catch up with the LEED process."

Cavenaugh said his LEED paperwork cost $22,000, offset with a $15,000 Business Energy Tax Credit. "Thatís seven grand for a plaque. Iíd rather spend $7,000 on a better HVAC system that produces ... better air quality in the building."

Fallow and Wilde, though, believe LEED documentation is manageable. "I donít think the paperwork should scare people away anymore, especially in Portland," said Fallow.

Wilde warned against the notion, expressed by Cohen, that building owners may increasingly choose to forego official LEED certification while still applying the standards. "That easily could fall into greenwashing," Wilde said. "You could easily lie to yourself. Thereís a strong argument for saying, ĎDo the work. Make the subs go through the process ... get them engaged early on.í Most of the subs take real pride in what they do. Theyíll see their efforts make a better project at the end of the day."

Even with its shortcomings, LEED represents considerable progress, according to Lewis. The fact that several hundred buildings are LEED registered (more than 840 as of late June, according to the USGBC) "is really encouraging to me. If we ever get to green building, sustainable buildings, there will be a lot of steps along the way. These, to me, seem like real steps."

LEED is "a great start. Millions of people are embracing it," he said. "You donít have to wait for George Bush to change his energy policy. We can go make changes ourself."

The panelists also explored the idea of ecological footprints, as a means to measure sustainability. For example, Wilde said, a building site could have a "rainfall account" or a "solar account" to live within. But solar power isnít yet very efficient, he noted. "Weíve got a long way to go finding energy sources that work on a distributed basis. I think weíre seeing progress toward that."

The ultimate goal is "zero footprint," according to Lewis.

But a mandatory approach could be problematic in a capitalist society, Cohen suggested. "Progress has been made, I think, on a certain level--educate people from within, do the right thing, do it on a mass scale, in a way that harnesses the energy from capitalism ... The better chance to solve the problem is not to rely on a utopian idea that almost becomes socialism."

Competition is healthy in green building, too, Lewis said. "The more people pushing, the more itís going to transform the market."--Mark Ohrenschall

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Customer Choice

PacifiCorp, PGE Residential, Small Business
Customers Can Opt for Time-of-Use Rates in 2004

Residential and small business customers of PacifiCorp and Portland General Electric will again have a choice to pay time-of-use rates in 2004.

The Oregon Public Utility Commission on July 1 approved an advisory committee recommendation to allow the utilities to include TOU rates among the market-based rate options offered to smaller customers, as required under Oregon's restructuring law. About 3,600 customers of the two utilities were on TOU rates as of June--well below 1 percent of those eligible.

The commission also directed the investor-owned utilities to assess the potential for demand-response programs and file reports by yearís end. The utilities are expected to have some demand-response ventures running by next spring, to help reduce peak demand.

Time-of-Use Rates

The OPUC approved the Portfolio Advisory Committee's recommendation to retain time-of-use rates in the market-based rate portfolio the IOUs must offer to customers under Oregon's electric industry restructuring. These options are for residential and small commercial customers lacking direct market access, according to OPUC staffer Janet Fairchild, a PAC member.

The 12-member panel--composed of representatives of utilities, local governments, residential consumers and small non-residential groups, public/regional interest groups, and staff of the OPUC and Oregon Office of Energy--crafted the original market-rate options and suggested changes to the 2004 TOU rates, which the OPUC also approved.

These changes include requiring PacifiCorp to implement a TOU rate structure that is revenue-neutral with its cost-of-service rate and that provides more opportunity for the average customer to save money than the utility's current offering.

The utility's TOU customers paid an average of about 10 cents more per month than they would have under the cost-of-service rate, the PAC reported. And because the utility has an inclining block structure for its COS rate, customers who used more energy ended up saving money under the TOU option, regardless of whether they shifted any load, while smaller usage customers didn't save at all, even if they shifted as much as 50 percent of their usage to off-peak hours.

The new tariff will set an on-peak surcharge and an off-peak credit, instead of setting three different rates for power use during different times of the day--on-peak, mid-peak and off-peak.

PGE, meanwhile, is to reduce its monthly meter charge for residential single-phase customers to $1 per month from the current $2 per month.

Both utilities are to target any TOU marketing to high-usage customers, who have the most to gain from switching to TOU rates, and to continue the customer guarantee for the first 12 months of participation in the TOU option. This guarantee ensures customers switching to TOU rates will pay at most 10 percent more than they would have paid under cost-of-service rates. "This allows customers the opportunity to try the TOU option for one year, to determine if they can actually shift enough load to save money, without incurring too much additional cost," the Portfolio Advisory Committee said in its report to the OPUC.

The commission also directed the utilities to submit estimates of current and projected costs and benefits from the TOU programs by March 30, 2004, such as electric system cost savings gained from shifted loads. By that same date, the utilities must let the PAC know whether there are any potential energy rate changes for 2005 to increase system benefits and participant savings.

The advisory committee also recommended PacifiCorp drop its seasonal flux option after 2003. PacifiCorp found seasonal flux program participants saved money, but the savings were negligible. Also, commercial customers were discovered to have used more energy than they had during two out of three of the prior year's highest-priced months, even with weather-normalized data.

While the commission approved the renewable options for 2004 at its March 31 meeting, one issue associated with those options arose at the July 1 meeting: the customer transfer fee. Under PGE's current contract with Green Mountain Energy, which supplies some of its renewable options, Green Mountain is to receive a per-customer transfer fee if, at the end of the current contract term, PGE selects a different supplier. The only way to avoid such a payment is to require all customers on the renewable options to opt out at the end of the contract term and then sign up again with the new supplier. "Portfolio Advisory Committee members were unhappy with that," said Fairchild. "It implies the customers are the marketers' and not the utility's."

At the same time, the commissioners were hesitant to delve into that level of detail on the contracts, which ought to be left to the utilities, Fairchild said. The PAC decided to recommend no such per-customer transfer payments be required in future contracts, but to leave the door open to such payments if it turns out their prohibition has unforeseen effects on the utilities' ability to negotiate new renewables options contracts.

Demand Response Programs

The OPUC on July 1 also agreed to give the two utilities until spring 2004 to develop demand- response programs.

At the commission's June 3 public meeting, OPUC staff presented commissioners with recommendations to require the utilities to file pilot demand-response programs by Sept. 30, made in conjunction with a staff report on demand response programs. Officials of both PacifiCorp and PGE thought that was too soon a deadline, and commissioners decided they also needed more time to consider the issue.

In the interim, representatives of the two utilities and OPUC staff came up with revised recommendations, which the OPUC approved. The utilities still have to assess demand-response potential and barriers by Dec. 31, as commission staff initially recommended. But instead of filing new programs beforehand--by Sept. 30--the utilities now have until spring 2004 to develop proposals.

PGE will file tariffs for new voluntary programs or pilots by March 31, 2004, with a proposed effective date of May 1, 2004. PacifiCorp will make quarterly reports to the OPUC, beginning in April 2004, on its progress in developing new demand-response pilots or programs, based on results of the company's December 2003 assessment.

The two utilities appear to be on different timelines, but OPUC staffer Lisa Schwartz said that's not exactly the case. PGE conducted a pilot demand-response program last winter, and the utility will need additional capacity by 2005. PacifiCorp, on the other hand, recently issued a new load forecast that indicates slower load growth than earlier forecast, she said. The utility also wanted to finish its demand-response assessment first, then figure out timing and program offerings. PacifiCorp already has a energy exchange demand buy-back program, which it developed and used during the 2000-2001 energy crisis and could launch on short notice if needed, said Bill Griffith, PacifiCorpís director of pricing and regulatory options.

In addition, the utility prefers dealing with this issue in its integrated resource plan, said PacifiCorp spokeswoman Becky Witt. Addressing program development within the plan allows the utility to "better assess and rank their cost-effectiveness with other potential resources," she said.

The OPUC also has directed the utilities to evaluate demand-response programs on a par with other options in their integrated resource plans. It will also add the question of how to accomplish this to the issues list for its investigation of least-cost-planning requirements.--Jude Noland

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