CWEB.084/December.20.2002
Energy efficiency and renewable energy spending cuts by Bonneville Power Administration will reverberate around the Northwest in years to come.
But the precise extent of their impact is yet unclear. BPA officials believe the agency can still achieve significant energy savings and renewable energy advances despite $21 million in reduced spending over the next four years.
Those trims account for about 6 percent of the $350 million in cost savings identified by BPA administrator Steve Wright in a Nov. 22 letter outlining Bonneville's responses to a projected $1.2 billion gap between expenses and revenues from fiscal year 2002 through FY 2006. No further rate increases are planned, for the moment.
BPA officials pledge to meet the agency's energy-saving target of 220 average megawatts from 2002 through 2006, with less money. Bonneville's 2002 results of 50.7 aMW of total installed savings--much of it gained at lower-than-historical-average costs to the agency--suggest BPA is tracking toward that goal.
Yet the spending cuts will actually lower BPA's Conservation Augmentation capital budget by more than one-third--the $13 million in projected conservation dollar savings comes from reduced interest and amortization costs from not borrowing $84 million. One regional energy analyst said BPA faces a challenge to meet its savings target with that greatly reduced level of capital spending.
BPA also will cut renewables spending $4 million through 2006, or $1 million annually. Of broader consequence, Bonneville envisions a diminished role in buying renewable energy. The agency plans to "focus more on facilitating purchases of renewable generation by others than on a BPA-only acquisition program," Wright wrote.
BPA also has stopped active consideration of four wind proposals remaining from its landmark 1,000 MW or more wind solicitation issued in February 2001.
Reaction to BPA's conservation/renewables actions ranges from fatalism to concern to glimmers of opportunities.
Financial Travails
Bonneville's financial travails lie behind the agency's conservation/renewables and other cuts.
Wright in his letter called the past two years "particularly challenging" for BPA. And the projected $1.2 billion deficit over the five-year rate period could widen with meager hydropower production or continuing low wholesale market prices.
BPA's single biggest financial problem, Wright told the Northwest Energy Coalition's Nov. 15 fall conference in Portland, is declining net revenues from surplus power sales. The agency planned 2002-2006 expenses around higher such revenues, based on the late 1990s pattern of high wholesale prices and abundant precipitation. But then came hydropower-reducing drought and plummeting market prices after the energy crisis.
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Bonneville has lost $800 million the past two years, despite a 46-percent wholesale rate increase, Wright said. "We can't keep losing this kind of money, 3, 4, 500 million dollars a year. It's unsustainable."
Through late summer and fall Bonneville solicited regional opinions through its Financial Choices process. BPA heard from many people about the significance of energy efficiency, renewable energy and fish and wildlife spending, Wright said. Agency officials also listened to tales of teacher layoffs, farm closures and increasing power shut-offs related to higher electricity costs. "It's having an impact on real people out there," he said. Northwest electric rates are no longer a major competitive advantage for regional industries, which Wright called "a huge shock for me."
BPA's response eschews further rate increases for now, although Wright pledged in his letter to monitor water and market conditions and "revisit" this option in early 2003.
The $350 million in spending reductions, deferrals and other actions target $107 million in Power Business Line internal operations, $72 million at the Columbia Generation Station, $56 million in freed-up Energy Northwest bond reserves, and the $21 million conservation/renewables cuts (including $4 million from Energy Web spending). Another $500 million may be forthcoming, Wright wrote.
'Socially Responsible' Pledge
The Nov. 22 letter acknowledged "impacts and tradeoffs" from the cost-cutting moves, but Wright pledged BPA to "respond in a socially responsible way.
"We will continue to work toward a sustainable energy efficiency future, and we intend to meet the Northwest Power Planning Council's target for conservation acquisition [220 aMW from BPA for 2002-2006]. Based on recent experience, we believe we can hit that target at costs significantly below the cost of historic conservation acquisitions if we stay on track with our conservation augmentation programs," he wrote.
"We will continue to exert leadership and promote development of cost-effective renewable energy resources but will focus more on facilitating purchases of renewable generation by others than on a BPA-only acquisition program," he wrote.
Some Reactions
BPA has little choice but to slash its budgets, said senior economist Kevin O'Meara of the Public Power Council. "This is not a happy time," he said. "Bonneville's finances are really in a bad state and the problem is the rate increases are doing enormous amounts of damage to the regional economy."
The PPC board, O'Meara said, generally believes that "Bonneville has to make these painful cuts so both Bonneville stays alive and the region's economy stays alive. Basically a lot of different sectors have to contribute. The sad thing is that any cuts in programmatic conservation expenditures are probably going to be swamped in effect by the price-induced conservation Bonneville's done" by increasing wholesale rates. "I'd prefer in the long run more programmatic conservation and less price-induced conservation."
At the Northwest Energy Coalition, "We're somewhat pleased that Steve didn't cut conservation and renewables too much. A few million dollars, given the crisis, that's not too bad," said senior policy associate Steve Weiss. "The cuts aren't wonderful … We would rather not have them," he added, but at least BPA's energy-saving target remains intact. Weiss expressed concern about the $500 million in potential further budget cuts, calling that "the other shoe."
Bonneville's conservation budget cuts were "bigger than I wanted and less than I expected," wrote executive director Stan Price of the Northwest Energy Efficiency Council in the December NEEC News. Rate increases are difficult, but efficient use of electricity is "the best method" to lessen their harm, according to Price. "Reducing consumption … is the only way for the Northwest to cling to some small part of its historical energy market advantage. Those who argue that energy efficiency is a regional expense that puts upward pressure on rates and declines utility revenues are not good students of recent history. If the current weather continues and power markets remain soft, we will all likely have the opportunity to take the make-up test."
BPA Conservation
Bonneville's $13 million in energy efficiency budget cuts fall on Conservation Augmentation, an umbrella for numerous energy-saving initiatives. BPA's conservation/renewables wholesale rate discount is not directly affected.
The dollar savings will accrue from not tapping $84 million of capital borrowing authority, which will reduce interest and amortization costs by $13 million, explained BPA's John Pyrch. Bonneville initially budgeted $290 million in ConAug capital borrowing to achieve 100 aMW of ConAug savings over the five-year rate period. That figure shrank to $240 million last year, he told Con.WEB, and with the new budget cuts it will drop to $156 million.
BPA thus expects to save 100 aMW through ConAug at an average cost of about $1.5 million per average megawatt--a level the agency achieved in racking up 23.6 aMW of 2002 ConAug energy efficiencies. That compares favorably with BPA's historical conservation acquisition costs of about $2 to $2.50 per average megawatt, Pyrch said.
"We think we've added a lot of value, gotten a lot of megawatts done, and found ways to do it a lower cost," BPA Power Business Line senior vice president Paul Norman told the NWEC fall conference. "Despite the financial stresses we're going to stay off the [historical conservation] roller coaster, continue to focus on low cost and pursue new ideas."
Norman and Wright praised BPA's energy efficiency staff, led by vice president Mike Weedall, in gaining lower-cost savings.
Weedall said he attaches more importance to the 220 aMW target than the allocated budgets. "We feel fully confident with the resources we're being given that we can do it," he told Con.WEB.
BPA will meet its goal if it duplicates or exceeds 2002 conservation numbers throughout the rate period. The agency tallied 50.7 aMW of installed savings for the just-ended fiscal year, Pyrch reported. Among ConAug ventures a major contract with Seattle City Light brought in 9 aMW, while compact fluorescent lamp coupons added about 4.5 aMW and federal agency initiatives tallied 3.2 aMW. Bonneville also chalked up 14.8 aMW from C/RD, 12 aMW from its share of regional market transformation and 0.25 aMW from low-income weatherization, according to Pyrch.
"It'll be a challenge for us in the future to see if we can get it at this [cost] level," he said. "You go up the supply curve in conservation and the cost goes up."
Weedall also acknowledged a challenge. So did senior policy analyst Charlie Grist of the Northwest Power Planning Council, who said the conservation cuts represent a "fairly paltry savings in rates and a fairly big decrease in their capital budgets for stuff that they finance."
The region's rough historical average for conservation savings slightly exceeds $2 million/aMW, he noted. "Can we get it for a whole lot less? I don't know. We got a bunch last year with CFLs. How many more CFL binges can you pull off? We had one in the mid-90s with showerheads. Will that happen in the future? I hope so." He suggested BPA could provide more incentives for more cost-effective C/RD savings. "That's probably the biggest area for improvement."
"We'll continue to look for new programs, new initiatives to get other ways to contribute," said Pyrch. Weedall listed a new residential loan program as one upcoming offering from Bonneville.
Meanwhile, BPA is lifting its ban on new long-term ConAug agreements with utilities, according to Norman. Weedall said the agency thought it unfair to customers to sign any such contracts during the discussions on BPA's financial future.
BPA Renewables
BPA has long been a regional force in non-hydro renewable energy. As a major example it buys energy from about 198 MW capacity of wind power, making Bonneville a nationally prominent wind purchaser. "We're proud of that," said Wright, but quickly added, "We do think our role is going to change."
Bonneville has served as the Northwest's primary resource gatherer, he told the NWEC conference. But, "all of the signals are folks don't want us to be" in the future.
For renewables acquisitions, Wright continued, BPA now plans to function more as an aggregator and less as a soloist. Bonneville could act as a minority purchaser for wind projects, to help make them happen in collaboration with other partners. "It's difficult to sustain the amount of financial risk we have in this type of environment we're operating in," he said.
The renewables budget cuts through 2006 amount to $4 million total over the next four years. Among the effects will be a scaled-back wind forecasting venture, along with fewer dollars for resource acquisitions, said BPA renewables program manager George Darr. "There's still money in there for us to acquire resources, but not as much," he told Con.WEB.
Darr also said Bonneville has stopped actively working on four remaining submittals from its 2001 wind-energy solicitation. The agency has proceeded with environmental reviews on the proposed 150-MW-capacity Maiden Wind Farm in south-central Washington, "so if we do need the power we can acquire it quickly."
BPA will continue its "fundamental program" of financially supporting renewables up to a $15 million annual net cost, Norman told the NWEC conference. He called renewables "a very entrepreneurial function within Bonneville, incented to maximize green revenue. I think it's worked very well." A recent Financial Choices document from BPA reported that Bonneville forecasts net renewables costs (generation values and green attribute values minus total costs) of $3.1 million in FY 2002, rising to $10.1 million in 2006, based on then-current spending levels.
"We'll try to add value, not just by buying power, but also facilitating services and commitments," Norman said.
Indeed, Bonneville can support wind power beyond buying electrons, said NWEC's Weiss. "One of the ideas Bonneville has is that instead of spending its limited amount of money for renewables directly on renewables, why don't we spend it on giving other developers cheap or free ancillary services. The dams really can deal with intermittency very easily, at almost no cost … Maybe they could leverage other developers and actually create more renewables than they could by buying [power]."
That scenario could work, said marketing vice president Dave Roberts of SeaWest WindPower, which has two Northwest wind proposals, 100 MW to 200 MW apiece, in the now-idled BPA wind solicitation. "Bonneville is in a fairly unique position to be able to aggregate demand and then manage the intermittency of the wind resource with their hydro capabilities and then provide back to that demand a firmed green product," he said.
Roberts acknowledged BPA's financial predicament and its uncertain resource acquisition future. He said SeaWest continues to collect wind data and work on other tasks (short of a full environmental review) for the two proposed projects, one in Klickitat County, WA and the other in Wasco County, OR. Those sites were planned with the Bonneville system in mind, Roberts said, although they could be arranged for other power buyers.
Times have changed since the Bonneville wind solicitation less than two years ago, said senior resource analyst Jeff King of the Northwest Power Planning Council. "The above-market costs of renewables have increased fairly substantially over levels people thought it would be" in early 2001. "I would be really surprised if Bonneville moved ahead [on the wind proposals] in the near future." If Bonneville were to seek new renewables, he said he would anticipate a new request for proposals.
"I suspect that the astute [wind] developer is probably looking for other opportunities," he said, mentioning the Energy Trust of Oregon, PacifiCorp's wind-friendly draft integrated resource plan (see related story), Puget Sound Energy's avowed interest in owning new power generation facilities, and NorthWestern Energy's power supply needs in Montana.
In addition, BPA whacked $4 million from its Energy Web program through 2006. "Some Energy Web research and development efforts will continue, but at substantially reduced levels, as we look for ways to leverage our funding with other regional partners," Wright wrote.--Mark Ohrenschall
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A proposed wind turbine manufacturing plant in the Pacific Northwest is officially becalmed.
Vestas Wind Systems A/S announced Nov. 26 that its investment plans for a Northwest manufacturing facility are "on hold." A company news release did not elaborate, although it noted plans for reduced capital spending in 2003 amid lowered expectations for the U.S. wind market. Vestas officials could not be reached by Con.WEB for comment.
The prospective factory and its many hundreds of jobs were touted just nine months ago as a huge clean energy economic development coup for Portland, and a sign of confidence in wind's regional and national future by the world's leading turbine manufacturer. But the Vestas plant has grown increasingly uncertain with a slowdown in the U.S. wind market and congressional inaction on the future of the federal wind energy production tax credit.
'On Hold'
"Investments in manufacturing facilities in the USA ... have been put on hold," stated the Nov. 26 Vestas news release.
That differs substantially from an Aug. 22 company pronouncement that, "Activities concerning preparations for production facilities are still ongoing in the Portland area. Final location and timing for establishment is related to a clarification regarding extension of the PTC scheme."
A Vestas official in Portland told Con.WEB in late September that her firm was still considering a Northwest plant, and that the list of potential sites had expanded from Portland (the original pick) to Vancouver and Longview in Washington. "We're anxiously awaiting in Congress action on the production tax credit," said human resources vice president Jo Anne Firestone of Vestas-American Wind Technology, a Vestas subsidiary. "Once that comes through we'll look at the feasibility of where we need to locate." An extension of the current 1.8 cents per kilowatt-hour credit failed to materialize this fall, and thus it is still scheduled to expire at year-end 2003.
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VAWT moved its corporate offices from Palm Springs, CA to Portland, and as of late September employed more than 100 people.
The manufacturing plant at full production would employ more than 800 people, according to Firestone. Vestas' initial announcement in April called for a 227,000-square-foot plant designed to assemble nacelles, produce blades and make towers, on an estimated investment of $35 million in production equipment. The company at the time anticipated opening the plant in summer 2003 and reaching full capacity by early 2004.
Vestas Projections
Vestas' Nov. 26 news release indicated the PTC could be extended in March or April of 2003, although "it will most likely not happen until October/November 2003. Therefore, the expectations for order intake for the American market this year have been reduced." The Denmark-based firm forecasts gross revenues of about 1.3 billion Euros in 2002, down from prior projections of 1.4 billion to 1.5 billion Euros. It expects 2003 revenues to grow to 1.7 billion to 1.8 billion Euros, lower than earlier projections of 2.1 billion to 2.2 billion Euros. (A euro roughly equals a dollar under current exchange rates.)
The company characterized non-U.S. wind market developments as "positive as expected" for the second half of 2002, particularly in European countries including Germany, Italy, United Kingdom, Ireland and the Netherlands.
"Vestas' expectations for the world market in 2004 and onwards are very much related to the American market," the news release said. "In case of an early extension of the PTC in 2003, the expectations for the American market in 2004 and onwards are positive. In case of a late extension of the PTC in 2003, the expectations for the American market in 2004 are lower, however, growth is expected again in 2005 and 2006."
Vestas in early December announced layoffs of 533 people from its Danish facilities.
Executive director Randall Swisher of the American Wind Energy Association called Vestas' recent announcements "unfortunate, but reflecting the hard realities of the wind business in the U.S. today. The U.S. independent power market is in turmoil at the moment, with many companies slashing plans to build new power plants, and that certainly has not helped matters," Swisher said in AWEA's Wind Energy Weekly. "At the same time, this news underlines the urgent need for Congress to act on an extension of the production tax credit and to put policies in place that will promote the sustained, orderly development of wind and other renewable energy technologies, instead of the roller-coaster, off-again, on-again situation we have at present."--Mark Ohrenschall
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FPL Energy has asked the Oregon Energy Facility Siting Council to approve construction of another 279 turbines at its Stateline Wind Energy Center, an expansion that would bring the project's total capacity to 484 MW.
This potential addition to what is already the nation's largest individual wind farm would likely be completed by 2005. Stateline now consists of 454 wind turbines with 300 MW capacity along the Washington-Oregon border southwest of Walla Walla, WA; 55 recently installed turbines raised the capacity from 263 MW. The 279 new turbines would be sited on the Oregon side.
Expansion Plans
Under its current permits Stateline can generate up to 300 MW, all of which has been sold to PacifiCorp Power Marketing.
FPL Energy spokeswoman Anne Walsh said the success of the project persuaded the developer to expand the site. But neither FPL nor PPM representatives would confirm the Portland-based power marketing firm has agreed to buy the additional output, if it becomes available.
"We have no firm commitment at this time to purchase beyond what we have, but of course, we're interested in further wind development, if the economics work out," said PPM spokeswoman Jan Johnson. PPM has been "very happy" with the market response to the existing 300 MW capacity, which has nearly sold out, added Johnson. PPM sells output from 100 MW to Seattle City Light (with future escalations), 90 MW to BPA and 25 MW to Eugene Water and Electric Board, as well as smaller amounts to other utilities.
The additional turbines would rise in three clusters of turbine strings, all on private land, according to an Oregon Office of Energy summary. FPL also proposes to build an 8.5-mile overhead 115-kilovolt transmission line and a new substation, which would connect to transmission lines in Washington. All the new facilities, including roads, would occupy about 75 acres, most of which is wheat land or otherwise developed.
The Oregon siting council took comments on the proposal until Dec. 20. John White of the Oregon Office of Energy said he didn't expect a decision on the permit until April, at the earliest. No public comments and no adverse reactions from government agencies had been received as of Dec. 17, White said. If the permit is granted, FPL Energy said it would complete construction by 2005.--Lynn Francisco
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The Northwest's potentially biggest landfill-gas-to-energy plant is moving toward development.
Projected at up to 27 megawatts capacity, this renewable energy project would be located at the Cedar Hills Regional Landfill 20 miles southeast of Seattle--the only active landfill in the region's most populous county.
Contract negotiations are progressing between landfill owner King County and Energy Developments, Inc., the firm selected through a request for proposals to buy landfill gas from the county and build and operate the power generating venture. EDI expects a final contract by early 2003. County project manager Mark Buscher expressed optimism about a development pact, but cautioned it's not a certainty because of lingering questions about Cedar Hills' economic feasibility, which is tied to wholesale power market conditions.
Multinational EDI has sent inquiries to would-be power purchasers--Northwest utilities and others--seeking expressions of interest by early January.
Electrons could start flowing by late 2004, from what would be one of the nation's largest landfill-gas ventures. The project would likely use gas-fired turbines with heat recovery and a single steam turbine, according to EDI.
Landfill Gas Opportunity
King County has long eyed the energy potential at its Cedar Hills landfill, according to a March 2001 study by consulting firm R.W. Beck. "Up to this point, however, project economics were unfavorable due to the relatively low price for electricity and natural gas in the region. Recent run-up in energy prices and advances in technology have improved project feasibility."
Buscher concurred that the energy crisis fueled renewed interest in this landfill-gas venture. Over the past dozen years, he told Con.WEB, the county selected at least two other companies to develop a project, but each concluded the pursuit of profitability was too risky, given the region's low electricity prices.
"We do expect over the long term that wholesale energy prices ... are going to grow and grow somewhat steadily," Buscher said. King County's Solid Waste Division issued a request for proposals in October 2001, generating six responses. Energy Developments was chosen for negotiations based on environmental performance, community impact, mitigation plans, financial resources, technical expertise, experience, safety record and price proposed to buy the landfill gas to convert into electricity, according to the Division's 2002 annual report. "This is their core business, making energy from secondary fuel sources," said Buscher. "We're really happy to be working with them."
EDI, which specializes in renewable energy projects, expects a finalized contract this month or early 2003, wrote business development vice president Dennis Bollinger in an e-mail interview. "We do not foresee any particular issue arising."
Buscher characterized the contract negotiations as "productive" and believes there is a "good chance" they will reach fruition. "Is this a done deal? No, it's not, simply because of the market conditions we all have to be subject to," said Buscher. The big question: "Can they generate energy from the landfill gas in a manner that successfully allows them to sell energy in the market?"
Asked about the market for landfill-gas energy, especially amid low power prices, Bollinger responded: "Demand for renewable resource power continues to grow throughout the country; therefore, EDI will continue to develop clean energy power plants."
The company is focusing on utilities as potential buyers of Cedar Hills power, he noted, and is discussing prospects with "several" Northwest utilities.
Capital and energy costs for the venture are still undetermined, according to Bollinger. Buscher declined comment on cost questions. EDI expects to sell net generation of 27 MW from its landfill-gas-fired generation project, according to the company's Nov. 27 solicitation of interest. (Buscher and county documents listed potential capacity of 22 MW to 26 MW). A total of 17 MW would be available by late 2004, the company said, with another 10 MW anticipated by early 2006. That second phase refers to a heat-recovery system (from gas-fired turbines) for steam turbine power generation, Buscher said.
EDI intends to sell firm power from the project until the plant shuts down at the end of 2024, stated the letter of inquiry. The company expects Cedar Hills to continually generate near its capacity through the landfill's projected closure in 2012, after which output "may decline" slightly over the years.
Transmission access should be doable, according to EDI. Crossing the landfill are two 500-kilovolt and three 230-KV Bonneville Power Administration lines, one of which is leased to Puget Sound Energy. However, EDI acknowledged it does not yet have transmission rights for Cedar Hills power.
Green certification and tax credits are likely to be available from the project, EDI also said.
Lots of Trash
At 27 MW, Cedar Hills would more than double the size of the next-largest landfill-gas plant in the Northwest, Klickitat PUD's H.W. Hill Landfill Gas Power Plant, with a 10.5 MW capacity. At least four other smaller landfill-gas projects operate in the Northwest.
Cedar Hills contains plenty of trash from which landfill gas is created. Opened in 1962, the 920-acre landfill near suburban Renton holds an estimated 26 million tons of accumulated garbage, and with about 1 million new tons received annually, it should have about 35 million tons by its planned 2012 closure.
Each day at Cedar Hills, according to the Solid Waste Division, anaerobic decomposition of organic wastes produces some 14 million cubic feet of landfill gas, predominantly methane and carbon dioxide. This gas is now collected and burned in five flares. "The project will largely replace the constant, high-temperature flares that currently burn off the landfill's gases," said an October media advisory from King County. "The gas-to-energy project will improve air quality while being quieter and less visible than the current flare systems."
Making productive use of this waste gas represents a net environmental gain, Buscher said. It would also reduce the need for power from other sources, especially in peak periods.
The project also would generate dollars for the financially troubled county--perhaps up to $1 million or more in annual revenues, depending on the contract terms, according to Buscher.
In addition to a signed contract EDI still needs air, solid waste, water and other permits to develop the landfill-gas plant, although, "There are no environmental issues at this project location," Bollinger told Con.WEB. The county's Solid Waste Division described in its annual report "a high level of support for the project from the public and regulators."
The county has held two public meetings on the Cedar Hills landfill-gas-to-energy proposal. "Nobody has stepped forward and said, 'Well, we don't think this is a good idea,'" said Buscher. "To the contrary, those people that have expressed an opinion are favorable to the project." Still, he added, "We're certainly not taking the opinion there is no opposition or there are no concerns that have to be addressed."--Mark Ohrenschall
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A small hydroelectric plant in the Washington Cascades generated green power--until this fall, anyway.
Packwood Lake Hydroelectric Project now produces standard electrons, even though the 27-megawatt-capacity facility still runs in the same environmentally benign fashion south of Mount Rainier.
The only difference is a new power sale arrangement. Packwood Lake electricity formerly went to Bonneville Power Administration, which sold it as Environmentally Preferred Power from a low-impact hydro resource, endorsed as such by regional environmental organizations--an endorsement predicated on the price premium supporting new renewables or watershed restoration, according to vice president Rob Harmon of Bonneville Environmental Foundation.
As of Nov. 1, however, Packwood Lake's firm electricity output goes as conventional power to Benton PUD and Franklin PUD, members of project owner Energy Northwest. Benton and Franklin "did offer more for the power than BPA was offering, but it was basically they just decided they could better use it and bring it into their portfolio," ENW project manager Dawn Sileo told Con.WEB.
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| Packwood Lake (Photo courtesy of Energy Northwest) |
Energy Northwest is considering pursuing green power certification for Packwood Lake, Sileo said. The two southeastern Washington public-power utilities, meanwhile, continue to buy green power from other resources.
Packwood's changed circumstance does reduce the Northwest's stock of official green power, although Bonneville's EPP still contains output from about 198 MW of wind capacity, along with other renewable resources including a low-impact hydro project near Idaho Falls.
This won't noticeably affect BEF, according to BEF president Angus Duncan, whose organization receives a slight majority of EPP premiums. The EPP portfolio in any case is gradually shifting toward new renewables, which Harmon described as an indicator of success
Packwood Lake Power
Duncan said BPA began eyeing the Energy Northwest hydro facility as a potential green power resource in the late 1990s. Packwood Lake garnered endorsement as a low-impact hydro facility from the Natural Resources Defense Council, Northwest Energy Coalition and Renewable Northwest Project, with the caveat BPA would earmark some green power premiums from endorsed renewables to regional environmental benefits--hence, BEF was formed.
Situated near the Cowlitz River headwaters, Packwood Lake was created by a landslide more than a millenium ago, according to BEF. It hosts native rainbow trout but no migrating fish--a natural waterfall spills from the lake's creek, Sileo said.
The hydro project began operating in 1964. It consists of a small diversion structure on the creek and an approximately four-mile-long underground pipeline that drops 1,800 feet in elevation to a powerhouse close to the town of Packwood.
BPA paid Energy Northwest 4 cents per kilowatt-hour for Packwood Lake power under a 15-month contract that expired Sept. 30, Sileo said. "They were paying us for the green power, essentially."
Benton and Franklin PUDs offered a higher price than Bonneville for a new shared contract, Sileo confirmed--2.5 cents/KWh for the firm output, according to Franklin power manager Sue Harp. "I think we were able to put together an offer with more certainty of covering the fixed prices of the contract," said Benton power management director Randy Gregg.
The two BPA Slice customer utilities also need additional resources, Sileo said.
"The PUDs thought they could get higher value than what we were offering ... a market-based offer with a cap and a collar," said BPA's Tom Osborn. Packwood generates most of its power in late spring and early summer, the lowest-value hydropower period, he noted. Benton and Franklin will be "able to do some daily shaping," he said. "As Slice customers they'll be able to manage that and make more money than just buying it from BPA. It's in their [economic] interest to take it back."
The new arrangement for Packwood Lake distributes 3.6 average megawatts of firm output to Benton and 3 aMW to Franklin, according to Harp and Gregg, whose utilities are among 12 ENW member participants in the project. Those megawatts displace BPA block power.
Now What?
Packwood Lake hydro operates under the same parameters as it did Sept. 30 when the BPA contract ended (the project closed in October for its annual maintance outage, before the new deal began Nov. 1). "The only thing that's changed is who we're selling the power to," said Sileo.
ENW and its member utilities are considering green power status for Packwood Lake, according to Sileo. If the consortium goes for the green, she said, it would most likely do so via certification from the Portland-based Low Impact Hydro Institute. ENW would likely wait until later in 2003 to pursue LIHI certification, which could require installing fish screens at the end of the tailrace, or other measures.
Both Franklin and Benton purchase other green power resources. Franklin gets 1 aMW from EPP and Benton receives 1 aMW from both the Nine Canyon Wind Project and Klickitat PUD's H.W. Hill Landfill Gas Power Plant. Benton also offers a retail green power program numbering about 700 participating customers, Gregg said.
The new Packwood Lake contract ends in September, he noted, and future options include continued Benton/Franklin purchases, a return to Bonneville and/or a third party interested in a environmentally preferred resource.
BEF, meanwhile, anticipates minimal direct impact from Packwood Lake's de-greening, either on green power supply or revenues, according to Duncan. Bonneville's blended EPP now consists of 50 percent new renewables, mostly wind, and the percentage of new renewables in the blended EPP should rise to 75 percent by 2005. "That's terrific," said Harmon. "That's exactly what's supposed to happen. Hats off to BPA."
On the revenue side, Duncan said BEF will take in about $1.9 million in gross revenues this year, primarily from EPP and green tag sales. The foundation's 2003 budget anticipates gross revenues of slightly more than $2 million.--Mark Ohrenschall
In these darkest days of Northwest winter, Con.WEB brings you some sunshine--in the form of a special section on solar energy.
This section looks at the solar industry's future and its generalized growth, particularly the rise in grid-connected applications; some solar technology trends; discussions on solar barriers and solutions; a look at Chelan County PUD's homegrown green power program, fostering a market between local customers and local solar and other renewable energy producers; a regionally available solar water-heating program from Bonneville Power Administration, via Eugene Water & Electric Board; summaries of some Northwest utilities' solar activities; and brief descriptions of some other solar programs and resources, from the Northwest and beyond.
Emerging Grid-Tied Applications, Solar Markets
Grid-connected applications are an emerging market for solar electricity, according to speakers at the Northwest Solar Summit in north-central Washington and Energy Technology Showcase 2002 in Portland, both held in October.
Off-grid and on-grid solar power have been "two distinct markets," said Christopher Freitas of OutBack Power Systems, speaking at the Solar Summit. "But where we're headed, I believe, is the in-between--not pure off-grid, not pure grid-connected, but something in between the two." For example, a cluster of homes beyond power lines could form a solar-electric "micro-grid." Meanwhile, solar homes connected to a distribution system could take advantage of time-of-day rate incentives, selling excess power to the local utility during the day.
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| The Sun Rover traveled to the Northwest Solar Summit. (Photo by Mark Ohrenschall) |
"We're not going to do this because it's possible," said Freitas. "We're going to do this because it adds value in the customer's eyes." Solar electricity may be a questionable financial investment, he acknowledged, but it can reflect personal values such as environmental concerns.
"We need to start providing the information and feedback to the customers that helps them see the other values we're providing," said Freitas. He cited as an example solar panels installed atop BP gas station canopies. Some of these combined electricity generation/shelter facilities are metered to show energy production and carbon dioxide emission reductions, said BP Solar International's Sherwin McDonald.
McDonald agreed that a shift toward grid-connected solar electric applications has occurred since the late 1990s.
Vincent Schwent of Sacramento Municipal Utility District, which has installed more than 1,000 solar electric installations in the past two decades, concurred. "The trend is on-grid," Schwent said at the Showcase conference. "Five to six years ago, on-grid was virtually zero. Today, over half is into on-grid. In the future that will completely dominate where PV goes, hooked up to the grid." Utility and government demonstrations in the 10-kilowatt to 100-KW range have characterized solar electricity, he said, but new homes represent an emerging market.
Schwent predicted solar electricity costs will drop 50 percent in the next five to 10 years, to a grid-competitive $3 to $4 per watt, through such factors as larger modules with reduced installation costs, building-integrated solar and less expensive inverters. "At that point the market explodes," he said. "You're no longer limited by government subsidies."
A leading inverter manufacturer, Xantrex Technology, sees many niche markets for renewables around the world, according to Xantrex's Ezra Auerbach. His company's series of three-phase, battery-free inverters for solar electric applications targets the small commercial and light industrial market. Businesses are less dependent than homeowners on direct cash subsidies for solar, Auerbach said at the Solar Summit. They can also take advantage of accelerated depreciation and other tax benefits, account for corporate greenhouse gas reductions and use solar as a marketing tool to attract environmentally minded customers--"so that folks like us will turn right at those [BP] solar panels instead of going down to the next brand of gas station."
U.S. Solar Manufacturing Grows More than Generation
U.S. solar-electric growth is apparent in manufacturing, although total solar power generation (including solar water-heating) is flat, according to the U.S. Energy Information Administration.
Total U.S. shipments of solar photovoltaic cells and modules grew 11 percent from 2000 to 2001, reaching 97.7 peak megawatts, EIA reports in its Renewable Energy Annual 2001. The domestic market boomed, rising from 19.8 peak MW in 2000 to 36.3 peak MW in 2001, which EIA attributes to new product lines with increased market penetration, new companies in the market and "[s]izable increases in domestic sales to a wide variety of sectors." U.S. PV manufacturing employment grew from 1,913 in 2000 to 2,666 in 2001, although the number of companies declined from 21 to 19. The total value of cell/module shipments exceeded $300 million in 2001, up 13 percent from 2000.
Grid-connected cell/module shipments outpaced remote applications in 2000 and 2001, EIA reported.
Installed photovoltaic capacity worldwide increased 35 percent in 2001, to 982 MW of peak capacity, the International Energy Agency recently reported. Annual growth has ranged from 20 percent to 40 percent every year since 1992, according to IEA, which also quantified the surge in grid-connected PV, from 29 percent of cumulative installed capacity in 1992 to 68 percent in 2001. The agency said government and utility supported programs in Japan, Europe and the United States have driven the grid-connected trend.
U.S. net solar power generation, however, expanded only slightly, from 493.3 million kilowatt-hours in 2000 to 494.1 million KWh in 2001--an actual decrease from 1997 through 1999, EIA figures reveal. EIA's Louise Guey-Lee told Con.WEB that solar thermal collectors, which account for the majority of U.S. solar consumption, are being retired more quickly than new ones are being installed.
Overall, solar remains a very minor contributor to total U.S. energy supply. Fossil fuels accounted for 86 percent of U.S. energy consumption in 2001, according to EIA, and nuclear added another 8 percent. Renewables totalled 6 percent, predominantly from hydroelectricity and biomass; solar amounted to 0.06 percent of national energy consumption.
Solar Technology Trends
In solar electric technology, polycrystalline silicon PV is starting to exceed monocrystalline silicon, according to Schwent. Thin-film applications are also expanding in solar manufacturing, he said. Thin-film silicon cell/module shipments jumped from 3.2 peak MW in 1999 to 12.5 peak MW in 2001, EIA reports, although it still lags far behind crystalline.
The United States formerly dominated solar PV manufacturing, he said, but the Japanese have "shot past us the last couple of years." (U.S. PV exports to Japan have dropped 83 percent since 1999, according to EIA.) Schwent said Japan made solar electricity one of 18 key industrial technologies and has nurtured domestic suppliers and markets.
Looking ahead, Mike Nelson of Washington State University Cooperative Extension Energy Program and Western S.U.N. Cooperative described a project by PV manufacturer AstroPower in which silicon is affixed to a thin steel layer. This uses one-twentieth the silicon of conventional solar PV manufacturing and promises "dramatically lower" prices, he said on a recent Seattle public radio station KUOW talk show.
At the Solar Summit, Nelson touted a recently simplified process to connect junction boxes to solar modules. "That is a significant improvement," he said. "The whole industry is doing lots of smart things like that."
Solar Barriers/Solutions
If solar is so great--clean, renewable, local, modular, energy-independent--why isn't there a larger market for it?
The Solar Summit tackled this issue in small-group discussions on barriers and solutions, in which four general themes emerged: cost, government policies, awareness and infrastructure.
At up to 25 cents per kilowatt-hour or more, solar electricity is quite expensive on a straight-line basis, especially compared to low-priced Northwest hydro-based power. What to do? Summiteers offered some ideas: tax credits, power production payments, increased sales volumes, public-purposes funding, research and development, and incorporation of environmental externalities in prices.
Nelson equated the cost of a solar electric system to adding a third bathroom in a home remodeling project. "I think it's already just a consumer choice" to go solar, he said on KUOW. Asked about economic payback, Nelson called solar an investment in one's home, but said the market is still too small to quantitatively value that investment.
On the policy front, Solar Summiteers suggested legislative champions, identification of regulatory constraints, more favorable codes and zoning, and public building solar demonstrations.
Policies make a difference for solar, which is "always going to be a consumer market," said Christy Herig of the National Renewable Energy Laboratory in an earlier Summit conference presentation. "It typically takes more than one policy," she said, after listing such options as renewables portfolios standards, public-purposes funding, tax incentives, financing, government purchasing, production incentives, energy incentives, equipment depreciation, net metering, interconnection rules, green pricing programs, power source disclosures, green tags and equipment/contractor certification.
Washington actually ranks sixth among the 50 states as a solar electric market, based on residential PV system break-even turnkey costs, reports a recent study co-authored by Herig--although this ranking is "somewhat misleading," the study said, because it gives undue weight to Chelan County PUD's production incentive (see story below). The Evergreen State fares poorly in some other respects, such as comparatively low residential rates and annual solar production capabilities.
Nevertheless, Washington already hosts 252 KW of grid-tied solar electric capacity, according to Nelson. Net metering has contributed to a tripling of new solar homes since 1999, he said. And if the state gains its proportional share of the installed solar capacity projected in the Photovoltaic Industry Roadmap, Washington solar electricity capacity will climb to 720 MW by 2020, he said.
Solar Summiteers also described a need to expand awareness of solar, with more demonstrations. And some believe solar would benefit from more and better-trained installers, which would stimulate demand.
Chelan County PUD Fosters Homegrown Green Power
Chelan County PUD is fostering a homegrown green power market, including solar, by connecting local renewable energy producers and buyers.
"Local people, Local decisions, Local power," reads the marketing slogan of Chelan's Sustainable Natural Alternative Power (SNAP) program. Participating PUD customers voluntarily pay a monthly premium ranging from $2.50 to $50, all of which is proportionally distributed to local small-scale grid-connected renewable energy generators based on their energy output.
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| (Courtesy of Chelan County PUD) |
SNAP differs from typical utility green power programs because it relies solely on local renewable resources and it links kilowatt-hour production payments to monies collected from customers. The central Washington public-power utility thus is developing a local green power market on both the supply and demand sides. "Your voluntary SNAP payment, along with the voluntary payments of others, will determine how much new alternative energy is generated in Chelan County," declares the program Web site.
Nelson called this "the most interesting incentive program in the state," with a low-rate utility offering production incentives of up to $1.50 for each kilowatt-hour.
The current SNAP producer roster consists of five renewables installations--four solar photovoltaic systems and one wind turbine, with a collective capacity of slightly more than 30 KW. Some 660 PUD customers support this local green power through their monthly premiums. That's about 1.9 percent of the utility's customers, slightly higher than the 1.6 percent average recently reported in a Renewable Northwest Project survey of 27 Western utility green power ventures.
"We have a long ways to go," said PUD energy services engineer Jim White, acknowledging the current program numbers as "a drop in the bucket." Participating customers do like SNAP's local orientation and the environmental benefits of renewable power, he reported. And significant interest in the program has emerged well beyond Chelan's service territory, even from European publications.
Local Orientation
Before launching SNAP in August 2001, White said, Chelan looked into the more conventional green power approach of selling kilowatt-hour blocks derived from distant renewable energy sources. But PUD officials opted for home. Surveys showed about 60 percent of customers expressed interest in green power, specifically from local generation, according to RNP.
SNAP-qualifying resources include wind, solar, geothermal, qualified hydro and biomass, limited to 25-KW capacity connected to the utility's distribution system. Producers pay the PUD a $100 interconnection fee (including installation of a separate meter to measure output), a $10 account service charge and a $3.65 monthly meter charge.
Three of the five SNAP producers are institutional: a 9.9-KW-capacity solar PV system on the Wenatchee Federal Building/Post Office, a 9.2-KW-capacity solar PV system at Wenatchee Valley College and a 600-watt-capacity PV array at Cashmere Middle School. Bonneville Environmental Foundation, the federal government and personal donations from U.S. Environmental Protection Agency employees in the Seattle office contributed financially to these installations. A 10-KW-capacity wind turbine at a ranch south of Wenatchee and a 340-watt-capacity PV array at a Chelan residence also generate SNAP power.
Producers split the accumulated SNAP dollars proportionally, up to a maximum of $1.50/KWh generated. Annual payments are made in April, and any excess carries over to the next year. The PUD also pays SNAP generators 75 percent of the average low-load-hour wholesale electricity price at the Mid-Columbia trading hub--about 2 cents/KWh at the moment, White said.
Participating customers choose to pay $2.50, $5 or $7.50 monthly (residential) or $10, $25 or $50 (business). Average monthly contribution is about $4.75, said White, noting that most participants are residential. The SNAP fund through early December slightly exceeded $30,000.
PUD management initially took a lukewarm attitude toward SNAP, White said, believing the program created little risk or cost for the utility. But with a higher-than-anticipated participation rate and positive reviews from many sources, "They've really tended to come on board with it." SNAP has even garnered a featured placement on the utility's Web site.
Future potential plans for SNAP include a community solar farm, separate options for different renewable resources and expanded marketing to commercial customers. Chelan eventually hopes to achieve a 3 percent to 4 percent customer participation rate and a balance between producers and buyers.
Bonneville Environmental Foundation's Rob Harmon said his organization is working on multiplying SNAP across the region for small utilities. The Solar Summit small-group discussions also listed SNAP as a promising model for promoting solar.
BPA Offers Solar Water Heating Program
A solar water-heating program is now available free to utility customers of Bonneville Power Administration.
BPA has purchased distribution rights for Eugene Water & Electric Board's solar water-heating program, titled The Bright Way to Heat Water. Utilities running this program can receive conservation/renewables discount credits from Bonneville.
Photovoltaics are "the favorite sun" in solar these days, said EWEB's Steve Still at the Solar Summit, which also served as a Bright Way training venue (he conducted the training as a BPA representative). But solar water-heating offers much better economics than solar electricity--"no comparison," he said. A $2,000 solar water-heating installation in Eugene with incentives and tax credits produces as much as a $15,000 solar electric system. Solar water-heating also can save more energy in Eugene than residential weatherization, according to Still. The Regional Technical Forum lists annual solar water-heating savings around the Northwest ranging from 1,862 KWh to 2,629 KWh.
Utilities can operate Bright Way differently than EWEB, although BPA has set requirements for system and contractor eligibility, written warranties, installation verifications for C/RD credits, minimum general/technical specifications and homeowner education. Only homes with electric water-heating are acceptable. (For more information on Bright Way, contact BPA's Mark Johnson: phone, (503) 230-7669; e-mail, mejohnson@bpa.gov; or contact a Bonneville energy efficiency representative).
Other Northwest Utility Solar Activities
In addition to Bright Way, which has led to 850 solar water-heating installations on local residences, EWEB also promotes solar electricity. Oregon's largest public-power utility offers net metering as well as a PV Partnership venture ($1 per installed watt and an interest-free loan of $5/watt, up to $15,000) with 7.5 KW completed, and a PV power purchase arrangement (EWEB pays 25 cents/KWh generated from systems sized from 10 KW to 50 KW) with 38 KW committed. An EWEB handout showed solar electric installations at a local rental house, high school, low-income housing project and the University of Oregon, along with plans for a 45-KW (15 KW building-integrated) system at the UO's reconstructed business school.
Other Northwest utilities also are active in solar electricity, based on a roundtable discussion at the Solar Summit (which attracted predominantly Washington utility representatives).
School solar is happening in the service territories of Ferry County PUD, Snohomish County PUD, Seattle City Light and the city of Ellensburg, among others. Snohomish, meanwhile, counts a half-dozen net-metered solar installations, reported the PUD's Chris Fate.
Clark Public Utilities plans to offer a low-interest loan (5 percent interest, for up to five years and up to $10,000) for solar electricity or water-heating applications, beginning in March 2003, said Clark's Bruce Carter.
And in the way of spreading the solar message, Ellensburg's Gary Nystedt raised the idea of a community solar electricity system on city property along Interstate 90, in which output is sold to local customers as a form of net metering. Such a facility could be developed elsewhere in the highly visible I-90 central Washington corridor with other utilities involved, serving also as a center for classes and workshops, he said.
Other Programs, Resources
The Solar Summit--held at the aptly named Sun Mountain Lodge outside of Winthrop, WA--also spotlighted a number of other programs and resources.
The federal Million Solar Roofs Initiative actually counts more than a million pledged rooftop systems around the country (electricity, water heating and pools), reported Heather Mulligan from the U.S. Department of Energy's Seattle office. Some 290,000 solar systems had been installed between 1997 and January, although she acknowledged some may not be directly attributable to the program. Million Solar Roofs also lists 67 state and local partnerships (including at least one in every Northwest state) and $1.6 million in 2002 grants. "We are definitely seeing progress," she said.
Regional solar promoters include Bonneville Environmental Foundation, which invests in numerous solar projects and sells solar-originated green tags; Western S.U.N. Cooperative, which offers cost-based solar technologies along with education, training and marketing support to its members (26 Northwest utilities are listed as 2002 members); and the fledgling Northwest Renewable Energy Cooperative, funded by BEF green tag sales and offering 10 cents/KWh over five years for new solar electricity production (contact Doug Boleyn for more information: phone, (503) 655-1617; e-mail, cascadesolar@attbi.com).
Montana's public-purposes funding (known as the Universal System Benefits program) has contributed wholly or in part to solar electric installations on 22 schools, 54 homes and five other non-residential applications, including the state capitol, according to Jim Tracy of Butte-based National Center for Appropriate Technology.
From farther afield, Jerry Ventre of the Florida Solar Energy Center made a pitch for Northwest collaboration on collection and analysis of solar electric performance and reliability data, quality control measures, curriculum and other educational resources, and testing and evaluation of distributed generation systems. George Ingham of the National Photovoltaic Construction Partnership discussed a new program to encourage electricians to install solar electric systems on their own homes.--Mark Ohrenschall
PacifiCorp's draft integrated resource plan relies more on renewable energy than previous such blueprints, although thermal-based resources still play a big role.
Customer demand is expected to increase by about 4,000 megawatts in the next 10 years, and PacifiCorp will need to develop a diversified resource portfolio that includes a mix of demand-side management, renewables and traditional resources, concludes the draft IRP. It calls for acquiring up to 450 average megawatts of DSM and 1,146 aMW of renewables, predominantly wind energy.
The investor-owned utility is fine-tuning its plan for delivery to state regulatory agencies by early 2003.
Meanwhile, renewables advocates are praising PacifiCorp's draft IRP for its substantial inclusion of non-fossil-fueled resources.
Background
PacifiCorp and many other of the region's investor-owned utilities are developing updated integrated resource plans to guide resource acquisition choices for meeting future load growth. The plans--also referred to as least-cost plans--first gained importance in the 1980s, when utilities added energy efficiency strategies to their resource mixes. They fell out of favor as the competitive electricity marketplace evolved, but are now resurgent.
PacifiCorp is required to develop an updated, 20-year integrated resource plan every two years. The utility started working on this plan about a year ago, said spokeswoman Shannon Shoul. Initial meetings were held on a state-by-state, stakeholder-by-stakeholder basis, she said, with the first group meeting in February. Work groups subsequently met monthly until the draft plan was completed in November and distributed to about 30 parties for additional input and comment.
The plan predicts customer demand will grow by 2.2 percent annually on the east side of PacifiCorp's system--Utah, Idaho and Wyoming--and about 2 percent per year on the west side of the system--California, Washington and Oregon. At the same time, output from the utility's existing resources is expected to diminish, owing to lost capacity at aging power plants, environmental or fish mitigation constraints on output, and potential increased regulatory requirements for supply reserves. As a result, the utility will need about 4,000 additional megawatts between 2004 and 2014.
Results
PacifiCorp used extensive modeling and risk analysis to develop the plan, formulating a variety of resource portfolios, simulating the operation of each portfolio, analyzing costs and screening the portfolios to select those with the most promising performance. From there, the company conducted various risk scenarios and stress tests.
The results suggested a number of different potential paths, Shoul said. These include a diversified gas-coal approach, with several variations; a diversified coal-gas approach, also with several variations; all natural gas; PacifiCorp build; a renewables portfolio; and a transmission portfolio.
Demand-side management, supply-side strategies and renewables were built into each of the portfolios, Shoul said. "We looked at these as resources," she said. The draft plan calls for acquiring up to 450 aMW of DSM and 1,146 aMW of renewables--primarily wind, but possibly geothermal--"consistent with anticipated state and federal portfolio standards." The plan may call for more aggressive procurement of renewables, depending on results of further evaluation of such issues as transmission integration costs associated with wind and the number of sites at which additional large wind projects can be developed. Shoul described the DSM and renewables numbers as "aspirations ... ambitious goals."
In the short term, the utility proposes securing between 300 MW and 700 MW of power through shaped products and power purchase agreements to cover initial load growth, until physical assets can be built. Also needed are 2,200 MW of base-load resources--which could include new power purchase agreements, both to replace expiring contracts and to cover load growth. The utility expects it will need 1,000 MW for system peaks, and looks to transmission upgrades and additions to "further optimize the use of the network, provide greater access to market and support the addition of new assets."
One transmission option identified in the plan is construction of a new direct current (DC) line to connect the utility's east and west control areas. PacifiCorp modeled both 1,000 MW and 2,000 MW additions, said Janet Morrison, director of commercial business. Such an addition would be expensive, she said, but might reduce the need to build new plants. "Transmission is kind of like peaker [plants], with high value some of the time," Morrison said. "If more companies participate, it can be sized better, while sharing costs and benefits." That's a possible scenario if plans for a regional transmission organization move forward.
Thermal options have good prospects for siting and licensing generation, the plan indicates, since several of PacifiCorp's existing coal facilities have room for expansion. Adding another unit at the Jim Bridger plant in Wyoming or the Hunter facility in Utah would also allow the utility to use existing transmission corridors. "We have transmission capacity available in southern Utah," Morrison said, "although we would still need some upgrades."
PacifiCorp is not biased in favor of any one particular option, or any particular fuel, said Bob Klein, PacifiCorp's senior vice president for commercial building. "Our objective is not to push or avoid building [new plants]," he said. "We want the least-cost solution to the things that could happen" in the future.
While PacifiCorp's IRP puts more emphasis on renewables than any past plans, the utility doesn't put a lot of weight on new technologies such as distributed generation. "The problem for a load-serving entity developing an IRP is that we have an obligation to always keep the lights on," Klein said. "So we have to make a plan to deliver that obligation. The first thing is to build a reliable, economic system." Energy technologies still under development or in a pilot phase would receive higher priority after they've been proven, he said. "Our objective is long-run, least-cost. If new technologies can bid their way into the dispatch stack, they're in."
Positive Reviews
PacifiCorp's draft plan has received positive reviews. "This is one of the most impressive integrated resource plans I've seen," said Phil Carver of the Oregon Office of Energy. The utility has done a good job of integrating wind modeling, he said. OOE would like PacifiCorp to put less emphasis on new coal development and more on renewables, but Carver still gives the plan "mostly kudos." He also would like PacifiCorp to examine real-time and critical peak pricing as demand response tools.
"Clean energy advocates have long been trying to persuade electric utilities that renewable power sources such as wind and geothermal energy are a cheaper long-term investment than fossil-fuel plants," wrote Steve Weiss of the Northwest Energy Coalition in a PacifiCorp IRP summary. "At last, a utility has put that notion to a fair test--and found that renewables are indeed a winner."
Ralph Cavanagh of the Natural Resources Defense Council applauded the plan's conclusion that renewables are cost-effective on a large scale. He called it "the most sophisticated and most consequential IRP that has been prepared in the region in the last five to 10 years." Still, the utility's draft plan continues to significantly understate opportunities to acquire cost-effective energy efficiency, NRDC said in joint comments filed with NWEC. The two environmental groups also have "profound concerns about any additions of coal-fired generation to a portfolio that is already grossly top-heavy with coal."
Cavanagh said it's important that the electric resource portfolio management function of utilities be restored, and said PacifiCorp's draft IRP is a potential watershed in this process.
"It is a good faith effort to assume the responsibilities [of resource planning] and conduct them in the right way," he said.--Jude Noland
Getting power directly from the plants that produce it and using more renewable energy are at the heart of Portland General Electric's draft integrated resource plan.
The renewables piece, however, has encountered some criticism. Industrial customers contend PGE shouldn't pay for above-market costs of new renewables beyond Oregon's public-purposes charge, while the Northwest Energy Coalition believes the investor-owned utility relies too much on natural gas-fired resources and uses inflated wind power costs.
Signing long-term contracts and tolling agreements, purchasing an equity share in one or more generation facilities and building its own power plant also are on PGE's list of possibilities for rounding up resources to serve customers.
Just as PGE wants to expand its use of long-term contracts and buy equity in one or more power plants, the utility wants to reduce its exposure to wholesale energy markets. Maintaining a "load-resource energy balance over the year" is PGE's favored strategy over "deliberately going long or short" and having to depend on the market either to buy or sell power, according to the plan.
Stability Favored
PGE's preference for longer-term resource supply arrangements came partly from customers, who said they favored stable prices and planned energy supplies, said Mike Mikolaitis, PGE's general manager of power supply engineering and strategy. "Price management, with regard to price volatility and the significant change from year to year, was a big problem" for customers, he said, particularly those who use between 30 kilowatts and 1 megawatt. "We tried to factor that into our planning."
The result is a draft plan that focuses on owning or contracting for resources that "have an honest-to-goodness plant behind them, through a purchase or tolling agreement," Mikolaitis said. PGE wants to get away from buying power from brokers, traders or short-term marketers, he said, and therefore it plans to move "to a longer-term commitment with the ability to lock in the price."
Despite a recent economy-related slowdown in customer energy use, PGE expects its loads to grow an average of about 2 percent a year through 2051. In this light, following through with development of the company's planned 650-MW Port Westward gas-fired plant in Oregon makes sense, according to the plan. "We haven't made a commitment yet to build the project," Mikolaitis cautioned. "We'll have to compare Port Westward to all the other potential alternatives."
A Renewables Target
Although a number of variables remain undecided in PGE's resource plan, the utility has set its sights on two targets: acquiring 40 average megawatts of renewable energy by 2010, and realizing 25 aMW from efficiency upgrades at its existing power plants.
Adding more renewables means lower costs from transporting natural gas and fewer headaches from environmental concerns about burning fossil fuels, the company said in its plan.
PGE plans to purchase renewable resources both from subsidized funds--the 3-percent public-purposes fee established with Oregon's electricity industry restructuring--and from straight resource acquisition budgets. Meanwhile, the utility is trying to persuade customer representatives that going beyond this subsidy and buying renewable energy at prices within $5 per megawatt-hour (0.5 cents per kilowatt-hour) of the cost of non-renewable resources is a good deal, particularly since a growing number of customers appear willing to pay a premium to develop green energy resources.
Skepticism on Renewables
Industrial Customers of Northwest Utilities, however, is skeptical of PGE's plan to pay above-market prices for renewable power outside its subsidy. "The 3-percent public purpose charge was to support the above-market cost of renewable resources ... and that's all customers are obligated to pay for," said ICNU executive director Ken Canon. "To the extent PGE wants to do something beyond that and above market, they should do it on their own and not charge ratepayers."
The Northwest Energy Coalition, however, said PGE's integrated resource plan relies too much on gas-fired power resources. The group criticized PGE's renewable resource plan, as well as its forecast of natural gas prices.
In comments filed last month with the Oregon Public Utility Commission, the coalition criticized PGE's estimate that gas prices would remain between $2.50 and $3 per million British thermal units, whereas PacifiCorp, in a similar integrated resource plan, concluded that gas prices would be more like $4 to $6 per million Btu (see related story). A new Alaska pipeline or more liquified natural gas import facilities would be needed to keep gas prices low, and gas price volatility has driven investors away from such projects, the coalition said in its comments. "Certainly the 2002-2007 prices for 12-month strips that we have seen recently argue that a cost of at least $3.50-4.00 would seem more reasonable than PGE's lower estimates," wrote NWEC's Steve Weiss.
The coalition also criticized PGE for inflating the price of wind power, compared to PacifiCorp. PGE estimated wind resources to cost between 6 cents/KWh and 7.5 cents/KWh, eventually dropping to 4.5 cents/KWh in 20 years. (The utility estimated gas-fired generation power costs at 4 cents/KWh). PacifiCorp, by contrast, estimated wind power would cost between 3.3 cents/KWh and 6.2 cents/KWh, averaging about 4.75 cents/ KWh--"quite a difference in the early years," Weiss wrote.
He criticized PGE for basing its integrated cost calculations for wind on a figure provided by Bonneville Power Administration, which, he said, the agency later admitted was inaccurate and would be recalculated. PacifiCorp conducted its own integrated cost calculations for wind and arrived at the lower figures.
The Oregon Office of Energy, meanwhile, agreed with ICNU that PGE should not charge customers for above-market renewable resource costs. In comments filed with the OPUC last month, the OOE also urged PGE to look more closely at gas price volatility, and at PacifiCorp's analysis of wind integration costs, among other factors.
OPUC staff is expected to issue a draft recommendation on PGE's resource plan by the end of the month; a final staff recommendation and a commission meeting are planned for early 2003.--Cassandra Sweet
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