CWEB.109/February.11.2005
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Correction, Clarification In the Dec. 22 issue of Con.WEB, a story on Northwest wind project developments mistakenly referred to the location of a planned 104-megawatt-capacity project by Columbia Energy Partners in north-central Oregon. It is in Gilliam County. We apologize for the error. In the same issue, a News Bytes item referenced Idaho Energy Division low-interest loans to homeowners who switch from electric heating to natural gas or propane heating. Division administrator Bob Hoppie e-mailed us that the division allows but does not specifically seek fuel-switching opportunities; heating system upgrades are the main focus. |
Energy conservation and wind power are foreseen as cornerstones of the region's energy resource future, in the eyes of the Northwest Power and Conservation Council.
The Council's latest regional power plan, approved in mid-December, calls for 700 average megawatts of cost-effective energy savings through 2009 as a focal resource development action for the Northwest. That mirrors the conservation amount recommended in an earlier draft version of the plan (see Con.WEB, Oct. 29, 2004).
This negawatt campaign reflects the Council's interest in minimizing costs and risks to the regional electricity system, to help avoid another energy crisis.
"The Council's analysis shows that improved energy efficiency costs less than new construction of new generation and provides a hedge against market, fuel, and environmental risks," the plan states. "To achieve these benefits fully, however, stable and sustained investment in conservation is necessary. Although conservation may result in small rate increases in the short term, it can reduce both cost and risk in the long term."
On a longer horizon, the Council advocates acquisition of some 2,500 aMW of regionwide energy savings over 20 years.
It characterizes these energy-saving targets as "ambitious but achievable."
The plan also recommends 500 MW of demand-response capability in the next five years.
On the supply side, the Council forecasts 1,100 MW of new wind capacity installed in the region through 2014, deriving from state public purposes funding and utility integrated resource plans. The Council believes up to 5,000 MW of additional wind capacity could be needed by 2025, although the planning agency wants to examine issues surrounding huge wind expansion in the region.
Coal-fired power, either conventional or emerging gasification technology, could be needed sometime after 2010, the Council projects. More natural gas-fired generation, however, is on the plan's back burner until late in the 20-year planning period, owing to volatile gas prices.
Power Plan
This fifth power plan from the Council is its first since the 2000-2001 energy crisis, and is designed to help avoid a recurrence of soaring power prices and limited supplies.
The plan acknowledges many unknowns about the future, notably power demand, hydroelectric generation, fuel prices, environmental regulations and power market prices. The Council, it said, is challenged to "provide a flexible resource strategy that can perform well under the expanded and intensified range of future uncertainties."
To do so, the Council analyzed different resource portfolios in some 750 future scenarios. What emerged was "a resource plan that entails somewhat more cost on average but considerably less risk than the absolute least-cost plan. This plan reflects concerns about the adverse effects that very high-cost outcomes can have on the power system; the social and 'non-power' economic costs not included in the Council's risk measures; judgments regarding the value of improved reliability and reductions in price volatility, and the desire for a diverse and orderly development pattern."
Conservation
Heading the list of recommended action items is conservation, specifically 700 aMW from 2005-2009, starting at 130 aMW this year and rising to 150 aMW in 2009.
"The Council's analysis indicates that regional investment in cost-effective conservation at this level is more likely to lead to a more economical and reliable power system than alternative development policies," the plan states.
Some commenters on the draft plan thought this target too high, others considered it too low and some considered it appropriate, said Council power planning director Dick Watson. The Council eventually concluded that "pursuing conservation on an aggressive and sustained basis is a smart thing to do," he said. "There's a bunch of this conservation that's cheap compared to any alternative we have available to us," and its development can tamp volatility.
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| (Courtesy of NWPCC) |
Achieving the Council's goal should cost the utility system an estimated $1.3 billion to $1.45 billion over five years--an increase from the present, but less than the $1.56 billion (in 2004 dollars) spent on conservation from 1992 through 1996, the plan noted.
The 130 aMW first-year ambition is comparable to energy crisis conservation acquisitions, the plan said. It also noted the Northwest has saved as much as 146 aMW a year, just below the 150 aMW targeted in 2009.
The plan details specific conservation actions, including increases in both lost opportunity and discretionary acquisitions, higher budgets, expanded market transformation and upgraded energy codes. It also encourages regional coordination and tracking of negawatts, along with addressing obstacles to conservation, particularly financial.
A resource supply curve through 2025 list specific measures, and their costs and regional potential. Commercial lighting tops this chart, with 245 aMW of potential, at an average cost of 1.32 cents per kilowatt-hour. All but one of the first 21 measures are conservation. " ... it is indicative of the analytical results that the low-cost end of the supply curve is composed primarily of various conservation measures and some specific types of wind development," the plan said.
Renewables/Supply-Side Resources
The Council plan does not anticipate much generation development before 2010--unless demand spikes, existing resources vanish or conservation efforts falter.
Yet the planning agency does expect considerable wind installed by 2014--1,100 MW--just from public-purposes ventures and IRPs. By 2011, more wind could be needed, and up to 5,000 MW could be built by 2025. Wind's prominence owes to more assertive carbon dioxide reduction policies, abundant resources, declining costs and transmission availability at windy sites.
But the Council also wants to tackle questions about massive new Northwest wind development, particularly how intermittent wind fits into the hydro-based utility system. "We acknowledge there are uncertainties about integration costs and so on; therefore one of the key action items on this is to try and organize an effort to get a better handle on it," said Watson.
The plan also envisions a place for coal-gasification resources, as less costly and risky, and environmentally friendlier, than conventional coal-fired power. Some 425 MW could be needed in the region to supplement wind power as early as 2016, the plan said. However, if coal gasification technology development lags, standard coal could be required for service as early as 2013.
Natural gas-fired generation is not listed in the five-year action plan, but the Council thinks it could attain a role later in the 20 years, as good wind sites are developed and CO2 emissions become more problematic.
Non-wind renewables also were considered, specifically solar electricity, geothermal, small hydropower, wave energy and biomass.
Solar is "very expensive," but potentially cost-effective in small, remote areas, the plan said. Geothermal is promising with declining costs and baseload prospects, but has not yet reached fruition in the Northwest. Wave has "substantial potential," but commercial technology is unavailable. Biomass is generally expensive and limited, though it can help dispose of wastes.
The Council encourages further assessment and application of these resources as appropriate, but none were included in the portfolio analysis.
Now What?
The Council concedes that individual utilities could well make different resource choices and with different timing than it suggests, for their own valid reasons.
In addition, the plan is a plan, and non-binding except on Bonneville Power Administration, which is legally obligated to make conservation and resource acquisition decisions consistent with the Council's plan.
But the Council thinks the plan has considerable merit as a regional blueprint. "Through a rigorous examination of various energy options and a healthy willingness to question given assumptions, the Council believes its new power plan offers sound guidance on how the region can secure its energy future," a summary reads.
The Council will undertake various follow-up planning processes, particularly for conservation acquisition strategies and wind power issues. It will monitor developments. And it will spread the plan throughout the region. "We'll be on the rubber chicken circuit, for sure," said Watson.--Mark Ohrenschall
More Information:
Northwest state legislatures are considering numerous bills to advance renewable energy and energy efficiency in their domains.
Washington lawmakers are pondering a proposal to require integrated resource plans from all utilities as a basis for renewable energy goals, along with yet another attempt to enact statewide renewables and efficiency standards. Evergreen State legislators also are mulling state efficiency standards for 13 products, as well as financial incentives for the solar industry and small-scale wind and solar energy producers.
Montana legislators have before them a proposed renewables portfolio standard--still in draft form as of Feb. 8--along with plans for an extension of the state's public purposes funding for conservation/renewables through 2009 and property tax reductions for wind energy developers. If approved, this RPS would be the first in the Northwest.
Idaho legislators are considering a proposal for a statewide energy resources authority that could finance renewable energy projects, and provide energy conservation loans. Also on the Gem State agenda is a proposed sales and use tax exemption for renewables equipment and machinery.
Washington
In recent years the Washington Legislature has mulled, but never approved, proposals to establish statewide standards for renewable energy and, in some cases, energy efficiency (see Con.WEB, Feb. 27, 2004 for a look at last year's session).
This year's legislative gathering brings another standards bill, as well as two other legislative pieces that would require utilities to perform integrated resource planning; one of those would use IRPs to fashion renewable energy targets (but not requirements) for Washington.
House Bill 1059 resembles legislation that passed two House of Representatives committees in 2004, but never received a full House vote. HB 1059 would require utilities to derive 5 percent of their annual retail load from renewables and/or renewable energy credits by 2011, 10 percent by 2016 and 15 percent by 2024. The proposal includes a cost cap of 4.5 cents per kilowatt-hour, exemptions for small utilities and Bonneville Power Administration full-requirements customers, and credits for new renewables and those located in Washington.
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An energy efficiency standard also would be enacted for utilities, with a mandate for annual program efficiencies equal to 0.75 percent of retail load in 2007, rising to 0.85 percent beginning in 2011. It includes exemptions for small utilities and full-requirements customers, and an allowance for high efficiency cogeneration to meet up to 15 percent of needed energy savings.
HB 1010 would require all Washington utilities to prepare and regularly update IRPs, assessing supply- and demand-side options, and also to craft action plans. HB 1047 would, too, but it would go further by using IRP results to establish renewables goals, starting for 2010 and updated for 2015 and 2020.
Integrated resource planning is "something we need to do as a state," said Rep. Jeff Morris, co-sponsor of HB 1010 and chair of the House Technology, Energy and Communications Committee. He said the two IRP bills collaborate with utilities to find out the state's future electricity needs, rather than setting "an arbitrary number" as in standards.
Stakeholders remain divided on the best approach, judging from a Jan. 18 TEC committee hearing on HB 1010 and HB 1047.
Representatives of Renewable Northwest Project, GE Wind Energy, Northwest Energy Coalition, Washington Public Interest Research Group and League of Women Voters liked the IRP bills, but preferred HB 1059. "For Washington to see a lot of development, in particular wind, you need to drive the market, set a standard, require incremental growth of new renewables," said RNP's Ann Gravatt.
Representatives of large utilities Seattle City Light, PacifiCorp, Avista Utilities and Puget Sound Energy signaled their backing of HB 1010.
Some concerns arose from an Industrial Customer of Northwest Utilities representative worried about potentially higher energy costs from renewables. "We do believe these are still high-cost resources," said Tim Boyd. "The firms I represent simply cannot accept any other cost."
Public power trade group representatives also had reservations, especially over the resource planning uniformity that would be imposed on utilities of varying size, location and resource characteristics. "A one-size-fits-all IRP is very problematic for us," said Dave Warren of the Washington PUD Association. He noted that investor-owned utilities are already required to do IRPs, and large publics such as Seattle and Snohomish have chosen to do so. Another speaker said IRPs can cost utilities tens of thousands to hundreds of thousands of dollars, which could affect utility rates.
As of Feb. 7, HB 1059 remained in committee without a hearing; no committee action had been taken on HB 1010 and HB 1047.
Also under consideration in Olympia is a bill that would set state energy efficiency standards for 13 product types for which the federal government has not already established them: automatic commercial ice cube machines; commercial clothes washers; commercial pre-rinse spray valves; commercial refrigerators and freezers; digital television adapters; illuminated exit signs; low-voltage, dry-type distribution transformers; metal halide lamp fixtures; single-voltage external AC to DC power supplies; state-regulated incandescent reflector lamps; torchieres; traffic signal modules; and unit heaters.
Senate Bill 5098 was requested by former Gov. Gary Locke, and stemmed in part from a West Coast governor's initiative to combat global warming, including through energy efficiency, said Tony Usibelli of the Energy Policy Division of the state Department of Community, Trade and Economic Development. These rules could save consumers $480 million over 20 years, he said. Products under this legislation are available from several manufacturers, and paybacks through energy savings are under four years, according to CTED testimony.
Lining up in favor of this bill--at a Jan. 18 hearing before the Senate Water, Energy and Environment Committee--were representatives from the Northwest Energy Efficiency Council, WashPIRG, Northwest Energy Coalition, city of Seattle, Puget, Snohomish County PUD, Avista, RNP, Climate Solutions and Washington PUD Association. Energy savings, environmental gains and lower electric bills for consumers and businesses were touted.
Some unease, however, emerged from representatives of retailers, the food industry, restaurants and Association of Washington Business. They wanted more technical analysis of the proposed standards, and also expressed worries about additional purchase costs and uneven applicability of products covered under these proposed standards.
The WEE Committee passed a substitute version of SB 5098 on Feb. 10.
Solar electricity is the focus of two other proposed bills.
SB 5111 would offer tax breaks for solar system manufacturers, specifically a 50-percent reduction in the business and occupation tax rate; B&O tax exemptions for manufacturers locating in counties with high unemployment; B&O credits based on number of employees; sales tax exemptions for labor, services and sales involved in the building of solar manufacturing plants in high-unemployment counties; and a property tax exemption on machinery and equipment used in such solar manufacturing facilities.
SB 5101 addresses solar electricity and wind production, through a proposed base incentive of 15 cents/KWh of wind or solar power generated by individuals, businesses or local governments. Higher rates would be available for solar and wind systems with Washington-made components, but all payments would be capped at $2,000 annually. Utilities would pay the incentives, and receive credits against their public utility taxes.
"The bottom line is we're trying to boost the production and use of solar power in Washington state, and bring jobs to Washington state," said co-sponsor Sen. Erik Poulsen at a Jan. 18 WEE committee hearing on the bills. "Solar power is becoming a multimillion-dollar industry, where such countries as Japan, Germany and California have a competitive advantage over us. That's the ill we're trying to cure."
Co-sponsor Sen. Bob Morton noted the opportunities for smaller, economically struggling counties.
The solar bills generated broad support at the hearing, particularly from utility, advocacy group and solar business representatives.
They touted the package as market-enhancing, industry-boosting and job-creating. Danielle Dixon of the Northwest Energy Coalition called the bills "complementary efforts, where the whole is even greater than the sum of its parts."
"If Washington state passes this legislation [HB 5101], we will have the best solar legislation in the United States," as a pay-for-performance approach compared to cost-based incentives elsewhere, said Jim White of Chelan County PUD.
Substitute versions of both bills were passed in early February by the WEE Committee.
Montana
At the request of the state's new governor, Democrat Brian Schneider, Montana lawmakers are expected to consider a renewables portfolio standard for the Treasure State.
A draft version would require regulated utilities and competitive electricity suppliers to procure eligible renewables for 5 percent of retail sales by 2008, 10 percent by 2010 and 15 percent by 2015. Cooperative utilities would be exempt.
Also on the Montana legislative docket is a bill to extend the state's public purposes funding for conservation and renewables through 2009, from its currently scheduled expiration at year-end 2005.
HB 141 additionally would revise the formula by which Universal System Benefits initiatives are funded. The current rate is 2.4 percent of utility revenues in 1995. It would go down to about 2.2 percent for regulated utilities and 1.9 percent for cooperatives, for the prior year's retail sales, starting in 2006. However, this change should generate the same or even slightly higher annual USB dollar amounts, given retail load growth, according to legislative environmental analyst Todd Everts. The bill also would raise the mandated proportion of USB funding earmarked for low-income energy and weatherization assistance programs by regulated utilities--25 percent compared to 17 percent now. Co-ops would continue to have a 17-percent minimum.
As of Feb. 7, the House Federal Relations, Energy and Telecommunications Committee had not heard or taken action on this bill.
Another proposed bill would lower the property tax rate for Montana commercial wind farms, of which there are none at the moment (see related story). The current taxable rate is 6 percent of market value; SB 115 would drop it to 1.5 percent, while adding a local impact fee of up to 0.5 percent of total construction costs for three years.
Bill supporters said the legislation would spur wind development, and associated economic development, in Montana, according to a Jan. 14 Great Falls Tribune article. "There is tremendous opportunity in wind generation in Montana," said sponsoring Sen. Jim Tester, the newspaper reported. "We have yet to take much advantage of that. Senate Bill 115 takes a step in the right direction to do that."
The bill passed the Senate 44-6 in late January, and was in the House of Representatives as of Feb. 7.
Idaho
Idaho legislators are scrutinizing a proposal to create a statewide energy resources authority. This entity would be able to issue revenue bonds--on behalf of participating utilities--to finance energy facilities, including power plants, transmission and renewable projects. It could also offer energy conservation loans to utilities for their customers.
The underlying purpose is to help develop Idaho's energy infrastructure. At the moment, according to HB 30, Idaho imports more than half the power used in the state. "This bill would provide a great opportunity for us to control our energy destiny," said Rep. George Eskridge, a bill sponsor, as quoted in The Spokesman-Review newspaper. "We could come together to build alliances to keep energy costs low."
Idaho utilities (public and investor-owned) and independent power producers (for renewables only) would be eligible for this low-cost bond financing, and responsible for debt service; the state would have no bond payment obligations.
Some Idaho lawmakers were hesitant about eminent domain powers conferred on this prospective authority, according to The Spokesman-Review. The House Environment, Energy and Technology Committee had not taken formal action on the bill as of Feb. 8.
Also on the legislative docket is a bill proposing a sales and use tax exemption for machinery and equipment used to generate at least 5 megawatts of renewable power. No committee action had been taken as of Feb. 8. State income tax credits for renewables passed the 2004 Legislature, but were vetoed by Gov. Dirk Kempthorne for fiscal reasons (see Con.WEB, April 29, 2004).--Mark Ohrenschall
More Information:
Energy conservation and renewable energy figure prominently into Bonneville Power Administration's just-announced power supply policies for fiscal years 2007 through 2011, but their precise roles are still largely undetermined.
BPA pledges to pursue its share of regional cost-effective conservation targeted by the Northwest Power and Conservation Council, while emphasizing low costs and local approaches.
However, BPA is punting on conservation program specifics, pending an ongoing collaborative planning effort in which a regional advisory group has recommended Bonneville keep a similar structure and funding for future conservation initiatives as now (see related story).
For renewables, Bonneville expects to play "an active and creative facilitation role," through such potential means as wind integration services, transmission upgrades and rate discounts. BPA will spend up to $21 million annually (net) on this renewables facilitation. It will consider acquiring renewables under certain circumstances.
This marks a big strategic change from BPA's prior focus on large-scale renewables purchases; the agency buys output from 198 MW of renewables capacity. Some regional interests want Bonneville to play a larger and more direct role in renewables development, while others like the facilitation function. BPA thinks its chosen role is the "most appropriate," given more regional renewables activity and the agency's aim to limit sales of its lowest-cost power to the federal system's existing capabilities.
These conservation/renewables directions are very similar to BPA proposals issued in July as part of its Regional Dialogue process.
Bonneville's policy and administrator's record of decision, both issued Feb. 4, also cover a range of key rate structure, service and product issues.
Conservation
BPA reaffirmed five general principles to guide its conservation efforts starting in FY 2007.
First is applying the Council's latest power plan (see related story) to set BPA's energy-saving target. The Council calls for 700 average megawatts of regionwide energy savings from 2005-2009; BPA's goal, though on a slightly different timetable, would be 280 aMW, or 55 aMW annually, based on its 40-percent share of regional load.
BPA stresses most conservation is best pursued and achieved locally, though with some regional approaches, such as market transformation via the Northwest Energy Efficiency Alliance.
It pledges to "seek to meet its conservation goals at the lowest possible cost to BPA."
Bonneville also commits to an "appropriate level of funding" for local administrative costs, education, outreach and low-income weatherization.
BPA's policy acknowledges a need for "significant detail" on a "specific program structure that best serves the region," and defers a final conservation policy until after the BPA post-2006 conservation planning effort is completed.
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| (Courtesy of BPA) |
In addition, the policy promises that conservation/demand-side management will be "carefully considered" as alternative solutions to transmission constraints.
These general conservation principles were widely supported in public comments, BPA said in its record of decision. So was retaining a conservation rate credit, as well as the joint process for devising a conservation program structure.
Some commenters worried about how energy savings by utilities might affect their future allocations of low-cost BPA power, as a potential disincentive to conservation. BPA will address this issue in coming months as part of discussions on power supply distributions, the ROD said.
Renewables
"BPA will shift from a program focused on direct acquisition to an active and creative facilitation role with respect to renewable resource development," the policy summarized. "Although BPA will still consider acquisition as a viable facilitation option under the appropriate circumstances, the agency's primary focus will be to reduce the barriers and costs interested customers face in developing and acquiring renewables. As an added benefit, BPA believes its facilitation role will also help non-BPA customers develop renewable resources in the region."
Facilitation tools for BPA could include wind integration services (two of which are already offered), helping to build new transmission to nurture wind development and a continuing rate discount for renewables. Bonneville promises to "engage with its customers and other stakeholders to determine which facilitation options will most effectively leverage the agency's available funds to maximize regional development of renewable resources."
BPA leaves open the possibility of buying renewables, if it needs to purchase power for its regional firm load obligations--a scenario it doesn't expect through 2011. "The agency will consider other acquisition activities as well if they are the most cost-effective among competing facilitation options and can be accomplished consistent with the agency's financial objectives and governing statutes," the policy said.
BPA's renewables approach generated nearly 100 comments, which the ROD called "a clear indication of how important the topic of renewable resources is to the Pacific Northwest."
Some commenters were skeptical of BPA's proposed facilitation tack on renewables, the ROD reported. They thought it would lessen renewables development around the region, with negative consequences for resource diversity and adequacy, the environment and economic development, among others. Many of these opinions were summarized as encouraging BPA to take a long-range, broad perspective on its renewables role.
Others, however, supported the facilitation angle--particularly many utilities and customer organizations. They thought it consistent with BPA's intent to limit firm power sales to existing system capabilities.
BPA concluded that facilitation is not a retreat from encouraging renewables development, and that such efforts can benefit the region by addressing renewables obstacles, such as wind integration. But at the same time, Bonneville kept open the option of renewables acquisition under the above-mentioned circumstances, although it officially declined an "anchor tenant" role.
On the $21 million funding, BPA said it encompasses above-market costs of renewables acquisitions, plus the Conservation and Renewables Discount program element and direct costs for research and development, all included in wholesale rates. Some expenses for facilitation products and services could be recovered through separate, direct charges, the ROD noted. Also, the agency may not spend exactly $21 million a year. "Rather, BPA will make incremental commitments over time that will eventually exhaust the $21 million management target/policy benchmark."--Mark Ohrenschall
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Bonneville Power Administration conservation initiatives starting in late 2006 would look similar to BPA's current offerings, under recommendations from a regional advisory group.
BPA would retain variations of its flagship programs, the Conservation and Renewables Discount and Conservation Augmentation, and continue to financially support the Northwest Energy Efficiency Alliance and some regional acquisition infrastructure. Annual conservation budgets from fiscal years 2007 through 2011 would be about the same as now, around $80 million, the post-2006 BPA conservation work group advised.
"The structure of it isn't much different than what's in place now," said Keith Lockhart of Springfield Utility Board, head of the advisory group's program design subcommittee.
However, some panel members question whether the planned budget will enable BPA to reach its higher energy-saving targets for 2007-2011: about 56 average megawatts annually, compared to 44 aMW now. Advisors urge Bonneville to assess its progress after 2008 and adjust budgets and payment levels if necessary.
The panel's recommended approach, officially presented to BPA officials Jan. 20, is tied to several assumptions. One is sufficient cost-effective conservation measures available through BPA ventures; a draft list was just released. "There was definitely consensus that if this measure list that comes out is not adequate, there was going to have to be some adjustments made to our recommendation," Lockhart said. BPA's willingness to sufficiently pay for measures is assumed as well.
Advisors also count on resolution of a utility concern about reductions in BPA power allocations tied to energy savings, such that the outcome of this issue is not "a disincentive for conservation." This "decrement" issue is under review elsewhere within BPA.
BPA energy efficiency implementation manager John Pyrch characterized the group's recommendations as "workable" for Bonneville.
BPA will offer its own post-2006 conservation proposal in the near future, followed by another phase to hash out program design and other details.
Shaping BPA Conservation
The federal power marketing agency has pledged an ongoing commitment to energy conservation in its next five-year rate period starting Oct. 1, 2006. It has shared some guidelines, notably including a low-cost acquisition focus, minimal wholesale rate impacts and pursuit of its share of the Northwest Power and Conservation Council's regional conservation target.
But these outlines have left many details outstanding.
In late summer, Bonneville assembled a regional advisory panel to help shape its post-2006 conservation initiatives (see Con.WEB, Sept. 30, 2004). It attracted more than 50 people, mainly from BPA customer utilities, but also representatives of governments, interest groups, businesses and tribes.
The work group suggests an $80 million annual conservation budget (indexed for inflation), with an additional 2 percent, or $1.6 million, earmarked for regional acquisition support. That figure roughly equates to current spending, as well as BPA's planning numbers for 2007-2011.
Work group members are divided on the budget and BPA conservation targets, according to Lockhart. Some believe reaching 56 aMW a year will require more money; the Northwest Energy Efficiency Council estimates a likely annual cost of $88 million to $106 million.
Another faction thinks the budget should stay at $80 million, and the goal should be lowered, said Lockhart.
The advisory group concluded it would make a "good faith effort" to pursue the 56 aMW target, provided that if shortcomings are evident after two years, BPA would reassess and, if necessary, adjust budgets and willingness-to-pay criteria.
The $80 million would cover acquisition programs, market transformation, administration and utility contracts for low-income weatherization. But Lockhart said the group did not suggest specific allocations between the proposed rate discount and bilateral contract programs, without knowing eligible cost-effective measures. Seeing that list "might take care of some people's concerns," according to Pyrch.
Other general recommendations include budget and program flexibility for BPA in meeting the five-year goal, a focus on lost opportunity savings in new construction, more flexible reporting, oversight similar to ConAug, support of "bridge" agreements for projects that overlap the current and next rate periods, and a 7.5 aMW maximum annual load for defining small utilities for BPA conservation program purposes.
Program Proposals
Bonneville's two main energy-saving programs would continue with some revisions, under the advisory group's recommendations.
A conservation rate credit patterned after the C&RD would be established for 2007 through 2009. "A large majority of people were happy with the [rate credit] mechanism that's in place," said Lockhart.
The credit would be set at 0.05 cents per kilowatt-hour of BPA power purchases, as with the C&RD, and utilities could choose either a kilowatt-hour-savings or dollar target for their proportional amount.
However, with BPA's emphasis on shrinking conservation costs, the number of qualifying discount measures would be smaller than now allowed under the C&RD--perhaps one-third less, Pyrch estimated in late January. The C&RD now features more than 3,000 efficiency measures, but some would not meet proposed cost-effectiveness tests. The program was originally designed to rev up regional conservation, not strictly to acquire the lowest-cost energy savings.
Some want the C&RD to continue unchanged, Pyrch acknowledged, but others understand BPA's interest in tightening up the program, with "better reporting, proper oversight and accountability."
Utilities could count subcontracts with energy entities, provided the resulting efficiencies reduce BPA's load. Low-income weatherization funding would not be capped, but only approved weatherization measures would receive credits. And although the discount would not apply to large-scale renewables, so-called "direct application" or small-scale renewables would be eligible, under the same criteria for conservation measures.
A ConAug variant also would be offered. By way of rationale, the group's recommendation said, "Conservation resources are not evenly distributed across the region. Given this, it is essential that BPA provide funding to utilties that can obtain conservation in excess of that that is acquired through the rate credit funding."
This would feature bilateral contracts between BPA and utilities, for both customized and standard programs. Any such custom deal would be available to other contracting utilities, preferably at the same payment rate, the work group recommended.
This program category would especially apply to efficiency projects by large commercial and industrial customers. But residential ventures also would be eligible, creating an opportunity for utilities with primarily residential loads, said Lockhart. "Basically all measures that work under C&RD will now work under ConAug. Today, that's not the case," he said.
Third-party contracts also would be allowed, encompassing the Alliance ($10 million in committed BPA funding through 2009) and also bulk purchases and vendor programs.
The fourth category of recommended programs is labeled "regional acquisition support activities," and could involve regional marketing, education and outreach; collaboratively funded research and demonstration; evaluations and market assessments; and enhanced support for the Regional Technical Forum and other tracking activities.
Lockhart called the work group deliberations "a worthwhile process," and likened the outcome to a baseball hitter knocking a ball to the outfield wall, but not over, with the bases loaded. "We didn't quite get it over the fence for a grand slam, but we did OK."
Pyrch said he appreciated the work group efforts. Bonneville officials are considering these recommendations, and plan to issue their own proposal soon. A second post-2006 conservation development phase involving more detailed work will follow. BPA wants to have its post-2006 conservation plans determined well before the Oct. 1, 2006 launch.--Mark Ohrenschall
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PacifiCorp plans to soon launch a remote power curtailment system for commercial, industrial and government customers in its fast-growing and peak-constrained Utah service territory.
PacifiCorp in December announced a 10-year contract with Illinois-based Electric City for the company's Virtual "Negawatt" Power Plan, which enables remote control of lighting systems over a managed and secure Internet Protocol network, with minimal impact on participating customers. VNPP will provide an estimated 27 MW of curtailment to PacifiCorp's Utah Power service area, particularly the Salt Lake City region.
Jeff Bumgarner, PacifiCorp's director of demand-side management, said that within the IOU's territory in six Western states, Utah has the highest state load growth. Peak demand in PacifiCorp territory in the state is also rising at two to three times average growth, or about 5 percent, he noted. The utility forecasts 4.5 percent average annual coincident peak load growth in Utah from 2006 through 2015. "What that's dictating is that we pay attention to ways to more effectively manage our peak loads and load growth in that market," he said.
PacifiCorp assessed the Electric City VNPP program in the context of other potential resources within the utility's integrated resource planning process, and it was found to be cost-effective, according to Bumgarner.
The $25 million system is scheduled to start this spring, although full deployment could take up to two years.
Virtual 'Negawatts' Power Plan
Electric City's VNPP program incorporates the company's EnergySaver voltage control units, designed for ballasted lighting systems, along with its GlobalCommander software, which operates the units in aggregate. The company said the system not only provides "instantaneous control, measurement and verification of load reduction," but because it reduces the energy draw of lights without noticeable dimming, there is minimal to no visible impact on participating customers.
For their involvement in the new program, customers receive 3-percent steady-state savings in their lighting usage, Bumgarner added. Through its contract with PacifiCorp, Electric City will own the lighting network and be responsible for all aspects of implementation, including marketing and sales. It will guarantee delivery of lowered demand, and PacifiCorp will purchase the capacity made available by the program as it would other resources. Electric City estimates 27 MW is an achievable figure for the Utah market, Bumgarner said.
Bumgarner said PacifiCorp decided to sign up for VNPP only after it "thoroughly evaluated" the program while developing its 2003 Integrated Resource Plan; the system was found to provide economical help in assisting to reduce peak demand. Megawatts saved by the system, along with savings achieved through other DSM initiatives by the utility, "when put together start to build a case that over time could add up to deferment of a [power] plant," he said. "Although DSM alone can't address all the resource needs in the fast-growing Utah market, it does help us balance our approach by meeting those needs in the most cost-effective manner possible," he added.
In its 2004 revised IRP, PacifiCorp targets 200 MW of what it calls Class 1 ("fully dispatchable resources") DSM throughout its six-state territory by its fiscal year 2009 (April 2008-March 2009). VNPP is one initiative contributing toward that target.
Since 2003, Bumgarner said, PacifiCorp has signed up nearly 38,000 Utah residential/small commercial customers for an air conditioner cycling program marketed under the name Cool Keeper. By 2007, the utility projects 90,000 participants, which would result in 90 MW of load-shedding capabilities in afternoon and early evening hours of hot weekdays. Meanwhile, in Idaho, an irrigation load control program last summer delivered 35 MW of average load reduction.
Bumgarner said the Utah Electric City initiative is expected to be deployed by spring 2005, assuming program approval by the Utah Public Service Commission.
Electric City reported that as part of its contract with PacifiCorp, the utility can opt to expand its VNPP system by extending the program to some of its other jurisdictions, including those in Oregon and Washington, should it choose to do so.
But that's unlikely to occur anytime soon. This is a new venture for which PacifiCorp has limited experience, and the utility's resource planning indicates peak-load controls won't be needed in its western service areas until 2009, Bumgarner said. "It's probably premature to speculate how we might meet that need and through which programs."
John Mitola, Electric City's chief executive officer, said in a news release that the Utah VNPP project will provide the company with a "very important beachhead in the Western U.S." Anna Baluyot, vice president of utility development, told Con.WEB that Electric City is "actively working in the West" to further deploy its VNPP technology.
Baluyot said Electric City is well on its way to completing a 50-MW VNPP system in Commonwealth Edison's territory in Illinois, where half of that load reduction has been enrolled. Electric City's 2-MW VNPP project in Xcel Energy's service area in Denver, CO also is expected to soon be ready, she said; Xcel has already signed on the sum of customer hosts required to participate in that program.
For utilities, Electric City contends that its VNPP system is "competitive with all forms of power generation," and that its deployment can also help defer capital investments in transmission and distribution infrastructure, along with peaking plants that "go unused 90 percent of the time."
The Northwest Power and Conservation Council also is bullish on demand- response opportunities such as this; its latest regional power plan calls for development of 500 MW of demand response capability in the region.--Joel Puglisi (Mark Ohrenschall also contributed to this article)
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NorthWestern Energy's mid-January announcement of a wind-power purchase agreement could herald Montana's first large-scale wind farm, after several years of thwarted efforts.
Montana's largest utility has completed a deal to buy electricity from Invenergy Wind's planned 135-megawatt-capacity to 150-MW-capacity wind project near Judith Gap, in the state's midsection. The 20-year contract--priced at 3.1 cents per kilowatt-hour for the energy component--still needs Montana Public Service Commission endorsement. NorthWestern filed for PSC advanced approval on Feb. 7.
Invenergy, which recently acquired full interest in the project from Windpark Solutions Arcadia, plans to finish construction by year's end to qualify for the 1.8 cents/KWh federal wind energy production tax credit.
Judith Gap wind power would furnish about 8 percent of NorthWestern's resource supply for default customers--those who haven't chosen the open market under Montana's electric industry restructuring. It would fulfill part of NorthWestern's default supply resource acquisition plan unveiled a year ago, which called for 150 MW of wind capacity as part of a favored portfolio.
"We have worked very hard to obtain a cost-competitive renewable resource for our customers, while providing an important incentive for the development of a large-scale renewable energy project in Montana," NorthWestern chief operating officer Mike Hanson said in a news release.
NorthWestern spokeswoman Claudia Rapkoch told Con.WEB that Judith Gap wind emerged from a 2004 all-source request for proposals as "the project that met all the criteria we were looking for in terms of inclusion in the [default supply] portfolio," based on such criteria as cost, benefit and risk.
The utility earlier tabbed Judith Gap from a 2002 wind power solicitation, but that process became entangled in NorthWestern's financial woes and 2003 bankruptcy, from which it officially emerged Nov. 1. NorthWestern also issued a wind RFP in 2001, but that resulted in a canceled power purchase agreement with another developer after the PSC questioned how the utility made its selection.
Judith Gap Wind Project, Power Deal
The proposed Judith Gap wind farm has germinated for close to five years, said Bob Quinn, a partner in Windpark Solutions Arcadia.
Windpark sold its project interest at the end of 2004 to Invenergy Wind, a wholly owned affiliate of Chicago-based Invenergy. Windpark, which has technical and logistical expertise, had been seeking a financially sound American firm with wind farm construction experience, according to Quinn. He characterized Invenergy Wind as "a smaller, innovative, but very dynamic and successful company."
Quinn described the project sale as "thrilling ... It's like having one of your kids graduate from high school, who you helped and nurtured and worked with for years." He also thinks Judith Gap could set a precedent for others to develop Montana wind power.
Invenergy Wind has more than 25 wind projects under active development and construction in North America, totaling more than 2,500 MW of capacity.
"All around it's a very desirable project," said Invenergy project manager Andrew Flanagan, of the Judith Gap venture. He praised the bountiful wind resource, suitable terrain and easy transmission access (a 230-kilovolt NorthWestern line runs through the site).
Spread over 8,000 acres in Wheatland County roughly between Great Falls and Billings, the wind farm would host 75 to 100 turbines, each with a capacity of 1.5 MW to 1.8 MW. "We're currently planning for 150 megawatts, but that could change" to a slightly lower figure, Flanagan told Con.WEB.
He described the site as rolling hills near a mountain gap, containing private and state-owned land, primarily in agricultural use. "The substantial permitting requirements have been satisfied," he said, including a state environmental assessment that found no major potential impacts from the project. Landowner arrangements are in place.
Flanagan said he expects a transmission interconnection agreement soon with NorthWestern; a new substation would be built adjacent to the lines.
NorthWestern's 3.1 cents/KWh contract price reflects the wind energy with the PTC, but not transmission or ancillary services, Rapkoch noted. " ... the price paid by the consumer will be somewhat higher [than 3.1 cents/KWh] depending on the cost to purchase a firming resource to back up the renewable generation source," said the news release.
The utility didn't consider acquiring the wind farm, according to Rapkoch. "We've been pretty clear in that our strategic objective right now is to be a distribution utility right here in Montana."
Invenergy plans to build, own and operate the $150 million project. "Our strengths are in ... development, financing, construction and operation for wind and for gas-fired projects," said Flanagan.
Third Time a Charm?
The power purchase deal's presentation to the Montana PSC harkens to the utility's first attempt to buy wind power.
In 2001, the utility (then known as Montana Power) issued a solicitation for 150 MW of wind power to serve default supply customers. A three-site proposal from Montana Wind Harness was selected the winner--ironically, also at an announced 3.1 cents/KWh over 20 years--but NorthWestern cancelled the proposed contract in July 2002 after the PSC concluded the utility hadn't adequately explained how it made its choice. The PSC also turned down four other proposed resources for rate-based cost recovery (see Con.WEB, Aug. 29, 2002).
NorthWestern tried again in late 2002, issuing another wind RFP. The Judith Gap project and a 50-MW proposal from developer Navitas Energy emerged from this solicitation. However, NorthWestern stopped negotiations with Navitas in early 2004 after the company sought to increase its original bid price; a Navitas official told Con.WEB the proposal had lain dormant for more than a year, and changes were needed (see Con.WEB, June 30, 2004, for more details).
In January 2004, NorthWestern unveiled its resource acquisition plan for default supply customers. The favored portfolios all included 150 MW of wind capacity, along with 5 average megawatts annually of demand-side management resources. Most of the preferred power would come from other baseload and variable resources, as the IOU seeks to lower its exposure to short-term electricity markets.
Rapkoch believes the circumstances are much more favorable now for wind power to find its way into NorthWestern's system.
The first wind solicitation came "real early in the default supply procurement process," she said, amid much uncertainty over how the utility would acquire new resources. "It's really taken a couple of years to work through and get some feedback from all interested parties" on "how should the utility go about procuring this power, and then making sure it's a very transparent, very well-thought-out plan."
The second wind RFP was marred by NorthWestern's deteriorating finances from excessive debt and eventual bankruptcy, which also posed problems for wind developers concerned about the utility's ability to make long-term payments.
Now, with a default supply blueprint in place and an improving financial condition, "Hopefully we have all of this stuff behind us now and can work on getting these projects in the works and getting them built, and not only have good quality, stable renewable energy for our customers, but also contribute to the local economic benefits this project brings in the state," Rapkoch said.
Among those lauding the power purchase pact was Renewable Northwest Project senior policy associate Ann Gravatt, who in a news release called it "great news for Montana. Montana has the best wind resource in the Northwest, and with today's announcement, consumers will finally reap the benefits of that resource in the form of a low-cost, clean wind project."--Mark Ohrenschall
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The first large-scale geothermal power generated in the Northwest is likely to flow from southeastern Idaho starting in 2006.
A 20-year power purchase agreement signed in late December is a crucial milestone for the planned Raft River geothermal project. Idaho Power will buy electricity produced at the 10-megawatt-capacity plant--under a federal mandatory energy purchasing law--at a price starting at 5.1 cents per kilowatt-hour in 2006 and rising to 8.1 cents/KWh in 2026. Developer U.S. Geothermal anticipates 20-year revenues of $110 million.
"We think it represents hopefully the first new plant of a new wave of geothermal development over the next 10 years," said Doug Glaspey, U.S. Geothermal chief operating officer.
He said his company still needs county and state permits, and a transmission arrangement with Bonneville Power Administration, but Glaspey expects those to proceed smoothly. U.S. Geothermal also sees potential expansion up to 90 MW at the 5.8-square-mile project site in Cassia County, near the Idaho-Nevada-Utah border.
The power-sales pact-- approved Jan. 24 by the Idaho Public Utilities Commission--was reached little more than a month after a key IPUC decision regarding Idaho Power's purchase of electricity from small-scale producers under the federal Public Utility Regulatory Policies Act. The commission made predictable energy deliveries a prerequisite for developers such as U.S. Geothermal to receive favorable payments.
"We're fairly happy with" the Idaho Power deal, Glaspey told Con.WEB. "It's a pretty good contract, and a decent price."
Raft River Power Sale
The agreement signed Dec. 29 by Idaho Power and U.S. Geothermal officials resembles other PURPA deals approved by the IPUC in 2004. It also takes into account the commission's November ruling for PURPA qualifying facilities, which in key respects balanced the investor-owned utility's interest in stable QF power deliveries and the QF position that small generators are already motivated to churn out power consistently because they are paid for production.
Raft River generation will be limited to 10 average megawatts per month, to earn the IPUC-approved PURPA rates. Idaho Power will accept power deliveries beyond that threshold, but won't pay for those. If Raft River sends more than 110 percent or less than 90 percent of its estimated monthly generation to the utility, it will be paid 85 percent of the contract rate or the Dow Jones Mid-Columbia Index non-firm weighted average prices (whichever is lower) for energy outside this 90/110 band. These production forecasts will be adjustable every three months, starting late in the first operating year.
Glaspey said U.S. Geothermal expects to meet this provision, by adjusting the standard air-cooled geothermal plant design that would produce more power in winter (typically 12 MW for a 10-MW-capacity plant) than summer (8 MW).
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"We have to do some additional design work to maximize the efficiency of the power plant, to match this contract profile," said Glaspey. "Otherwise, we're confident we can operate within the 90 to 110 band."
In another contract feature reflecting a separate IPUC ruling, U.S. Geothermal will own the environmental attributes (also known as green tags, renewable energy credits or tradable renewable credits) from Raft River. U.S. Geothermal hasn't yet made any specific green tags arrangements, Glaspey said, but those could produce added revenue at minimal expense.
Another potential financial boon would be the new federal production tax credit for geothermal energy, currently at 1.8 cents/KWh generated over five years, but only available for projects operating by year-end 2005. "Our hope is that [PTC] will be extended," said Glaspey.
U.S. Geothermal also is banking on a transmission accord. The company is seeking interconnection to the Bonneville system, via local Raft River Electric Cooperative lines, and Glaspey sees no apparent problems. Idaho Power will take the power at its Minidoka Dam substation.
U.S. Geothermal anticipates starting commercial production at Raft River in mid-2006. The power sales agreement said the company plans to employ an air-cooled facility using geothermal fluid in a closed-loop Rankine cycle. On Jan. 28, the company announced it had been awarded a $2.2 million federal grant if it used an ammonia adsorption power cycle; U.S. Geothermal is evaluating this technology, and plans to decide by late March whether to deploy it at Raft River.
A Northwest First
If that schedule holds, and no other planned regional projects beat it to the punch, Raft River would become the first operating Northwest geothermal power project.
BPA has agreed to buy all power generated at the proposed 49-MW Fourmile Hill geothermal venture in Northern California, but that project is mired in contractual and legal disputes (see Con.WEB, Dec. 22, 2004). Portland-based PacifiCorp owns and operates the 26-MW-capacity Blundell geothermal project in Utah. Another Idaho project is under active development southeast of Idaho Falls by Idatherm, which as of late 2004 had leased land and acquired drilling permits. A number of Oregon geothermal proposals have bubbled up over the years, but none have ever reached fruition.
This latest venture is somewhat of a geothermal renaissance at Raft River. The site hosted a federal geothermal demonstration project in the late 1970s and early 1980s, generating 7 MW in 1981-1982, according to an Idaho Department of Water Resources history. But oil prices dropped and federal funding disappeared, Glaspey told Con.WEB in early 2003. "What it lacked more than anything was a market for the power at a price that was economic," said Glaspey, whose company is acquiring the venture from Vulcan Power.
Geothermal's market situation in Idaho improved considerably in 2002 when the IPUC adopted more generous terms for PURPA QFs, following the energy crisis and subsequent calls for more Idaho-generated power. Commissioners decided to allow 20-year contracts for projects up to 10 MW, at levelized prices of 5.1 cents/KWh for non-fueled projects starting operations in 2005. Glaspey said Raft River's initial 10-MW size was based on PURPA qualifying; the existing wells also enabled this project to move ahead.
Flow testing found the wells to be in "excellent condition," U.S. Geothermal reported in August, with stabilized "down hole" temperatures approaching 300 degrees and stabilized artesian flows ranging from 71 gallons per minute to 542 gallons per minute. "We're in good shape for 10 megawatts," Glaspey said.
Consultant GeothermEx estimates the company's leased/owned lands at Raft River could produce 90 MW of geothermal capacity. "Once the first 10 megawatts is under way, we'll definitely be looking at an expansion," Glaspey said.
Raft River at 10 MW is predicted to have a substantial annual economic impact on Cassia County, according to a 2004 report from the University of Idaho College of Agricultural and Life Sciences: $6.3 million in sales, $1.4 million in earnings, $718,000 in indirect business taxes and 26 jobs.--Mark Ohrenschall
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Idaho Power is soliciting about 200 megawatts of wind power capacity, acting on its plan for more diversified energy resources to serve its expanding customer base.
A Jan. 13 request for wind proposals signifies Idaho Power's biggest foray into non-hydro renewable energy. The investor-owned utility expects renewables to play a much larger role in its new resource mix over the next decade, along with fossil-fueled power and energy savings, as outlined in its 2004 integrated resource plan.
Idaho hosts no large-scale operating wind farms, although the 10.5-MW-capacity Fossil Gulch project was reportedly nearing completion near Hagerman as of early February, and numerous smaller wind turbines dot the state. At least three major wind farms are known to be in developmental stages in the Gem State. Representatives of more than 20 firms attended a wind RFP pre-bid conference Jan. 27.
Idaho Power's RFP seeks wind power from one or more projects in or near its service territory, with energy deliveries possibly starting this year or in 2006/2007. The IOU is open to a power purchase agreement and/or eventual utility ownership.
Integrated Resource Plan
This wind RFP fulfills one of the first action items in Idaho Power's 2004 IRP.
That planning document, unveiled in final form in August, called for a broadened resource portfolio for the utility in meeting an anticipated 2.2-percent annual load growth over the coming decade.
Now dominated by hydropower and coal-fired electricity, Idaho Power's resource mix would be expanded with 500 MW of coal, 450 MW of non-hydro renewables, 198 MW from natural gas-fired power/combined heat and power/market purchases/distributed generation, and 124 MW of demand response and energy efficiency, under the IRP's favored acquisition scenario through 2013.
The plan described this "blended approach" as "the most cost-effective and least-risk method to address the increasing energy demands of our customers." If the preferred plan is followed, Idaho Power would still derive the great majority of its power from hydro and fossil-fueled resources, although non-hydro renewables would grow to about 9 percent of the total. (See Con.WEB, August 2004, for more details on the then-draft IRP.)
Wind RFP Preferences, Details
Idaho Power's wind RFP specifies some details and preferences.
It wants power from one or more wind resources "inside, or in close proximity to" its Southern Idaho and Eastern Oregon service territory. Minimum bid is 30 MW capacity.
Although the utility seeks 100 MW of wind power starting in 2006 and 200 MW by 2007, it holds open the possibility of deliveries beginning this year, for projects that meet the year-end 2005 operating deadline for the 1.8 cents per kilowatt-hour federal wind energy production tax credit. Such 2005 proposals were due Feb. 1, and will evaluated on a quicker schedule, according to the RFP.
Idaho Power is mainly interested in two potential structures for wind energy.
One is a power purchase deal, ranging from 10 to 30 years. The second also involves a power-buying agreement, but would add an option for Idaho Power eventually to acquire some or all of a wind project, although not likely until at least 10 years of operation.
This second option is most appealing to the utility, according to Karl Bokenkamp, general manager of power supply planning. "Based on our analysis, and our assumptions for future natural gas prices, we expect the 30-year levelized costs of wind and geothermal projects to come in under the 30-year levelized cost of new [gas-fired] combustion turbine projects," he told Con.WEB. Wind and geothermal would still cost more than hydropower, on a levelized basis.
Bokenkamp noted that the wind PTC is good for 10 years, which "might allow us to step into the ownership" of a project after that point.
RFP respondents are invited "to bid other arrangements that may provide exceptional value to Idaho Power Company and its customers," the solicitation stated, but the utility prefers the first two alternatives.
The solicitation cautions that transmission access is limited for wind delivered to Idaho's populous Boise area. Bokenkamp said the utility plans transmission upgrades that would ease constraints from the east side of its system, but wind developers still need to connect to the Idaho Power grid.
Idaho Power would own all environmental attributes (also known as green tags or renewable energy credits) associated with its share of wind generation; it wants those included in the proposed price.
The utility also is interested in performance assurances for intermittent and non-dispatchable wind power, and, according to the solicitation, "will favorably view proposals containing detailed and legally enforceable availability commitments."
Idaho Power plans to consider price and non-price factors in its selection process--Bokenkamp declined to elaborate on those factors--and will look for "the most value" offered to the utility and its customers, not necessarily the lowest price. The utility reserves the right to change the amount of wind power sought during the RFP process, and to abandon the quest for any wind power.
Bids are due March 10 for non-2005 projects. The RFP schedule calls for identifying the successful bidder by June, finishing negotiations by August and submitting filings to the Idaho Public Utilities Commission in September.
In addition to the wind RFP, Idaho Power's IRP calls for a 100-MW geothermal solicitation this year.
On the demand side, Idaho Power recently proposed a sizable increase in its DSM rate surcharge, from 0.5 percent of base revenues now to 2.4 percent in 2007, to fund greatly expanded conservation efforts in the next five years (see Con.WEB, Dec. 22, 2004, for more details).--Mark Ohrenschall (Rick Adair contributed to this article)
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The Rose City may one day sport a new nickname: the Renewables City.
Portland city government is considering renewable power for its entire electric load, which now totals about 16 average megawatts annually.
This goal, which the city tentatively hopes to reach by 2007, is part of the city's 2001 action plan against global warming. If realized, Portland would join select company as a non-hydro renewably powered city government.
"We truly believe that what we are doing is a reflection of values that our residents and our businesses hold," said senior energy specialist David Tooze of the city's Office of Sustainable Development. "Livability, clean air, responsible local government supporting sustainable actions and businesses are all themes that our constituents support. We're looking for a win-win outcome that gives us an affordable, clean renewable energy resource and one that supports Oregon businesses."
In December, Portland issued a request for information "to help define the most appropriate methods" to get to 100-percent renewables. These could include city-owned or privately owned renewables projects, third-party or utility supplies, power purchasing, special contracts or some other approach. From RFI responses, which were due Feb. 2, the city plans to fashion a request for proposals, tentatively scheduled for release in March. Contract negotiations could be finished by late spring.
Price will be the biggest consideration for the city, which is currently served almost wholly by Portland General Electric at an average rate of about 4.4 cents per kilowatt-hour, according to Tooze. "Our objective is to get a product that has a very modest premium, or none, over our cost-of-service rate," he said.
City Seeks Renewables
A renewably powered city government is advocated in Portland/Multnomah County's 2001 Local Action Plan on Global Warming. At the moment, according to a December report to the City Council, coal accounts for 47 percent of power consumed in Multnomah County (which includes Portland), hydropower represents 26 percent and natural gas-fired power is 24 percent. Non-hydro renewables are 1 percent.
In addition to lowering carbon dioxide emissions, the city's renewables pursuit is intended to gain stable long-term power prices, contribute to economic growth in the state, and push the market for renewables, according to the RFI.
Other potential benefits outlined in the Council report include competitive prices for renewables, independence from fossil fuels, and government leadership toward a sustainable future. Tooze said this effort could burnish Portland's image.
City officials decided to seek renewables through a two-step process, starting with the request for information. "We are keenly interested in the responses we get from the RFI, including indicative pricing," said Tooze. "It will help us to narrow down the models or the methods we will consider when we get to the RFP phase. Right now the door is wide open. We don't know what the least-cost approach is going to be."
In addition to outlining prospective means by which city government could go renewables, the RFI indicates some parameters for Portland's search.
One is new renewables, defined as starting operations on or after July 1, 2005. "One of our objectives is to help push the market," said Tooze. "We're not interested in a resource that is already constructed." An Oregon location is required, as is a "proven technology from an established manufacturer."
Portland wants wind to furnish at least 70 percent of the power, and for the remainder it will consider solar photovoltaics and solar thermal; geothermal; digester and landfill gas; biomass (except municipal solid waste); fuel cells (renewably fueled); ocean energy technologies; and hydroelectric facilities no larger than 30 MW. A 15- to 20-year arrangement is anticipated. Meanwhile, the city and/or its partners would own environmental attributes (also known as green tags or renewable energy credits).
In evaluating submitted projects from the planned RFP, Portland plans to first screen them for basic credentials, such as sufficient resource data, site control and proposer qualifications and creditworthiness.
The next phase would involve a 100-point scoring system, with 20-year life-cycle costs accounting for 40 potential points. "The price that we pay for the generated kilowatt-hours is going to be the overriding decision factor," said Tooze. A maximum of 10 points would be available in six other categories: technology, project development status, proposer demonstrated experience, transmission capabilities, shielding the city from risks and environmental attributes.
Retail Customer
In contrast to a utility seeking renewables, the city is essentially an aggregated retail customer. This affects how renewable power would be delivered to the city, particularly for intermittent resources such as wind, Tooze noted. Load storage, shaping and ancillary services would be needed, creating what he called "a significant layer of complication." He described the city as "trying to acquire power as a retail customer at wholesale prices."
The city's load profile resembles a large commercial business, Tooze said, although it has substantial off-peak baseload needs for the likes of streetlighting (more than a quarter of overall city power consumption--4.5 aMW from July 2002 to June 2003) and water/wastewater treatment.
As of 2002-2003, the city had 813 separate PGE accounts, with total annual consumption of 14.6 aMW and bills of $11.3 million. Pacific Power & Light accounts totalled 130, with consumption of about 1.2 aMW. Portland forecasts 2.5 aMW in new city loads by 2008. But the RFI acknowledges load variability from growth, efficiency measures, weather and other circumstances, and asks respondents about their flexibility to meet future city power demands.
Reactions
Both Tooze and Jeff Cogen, an aide to city commissioner Dan Saltzman, described initial response to Portland's renewables quest as highly favorable. However, both recognized the lingering issue of cost.
"Local reaction's been incredibly positive," said Cogen. "People here want to do this. They're very supportive of this, and believe it's the right thing to do."
Still, Portland has experienced city budget cuts five straight years, and more are predicted in the coming five years, he said. "The context there is this has got to work economically," which he defined as "pretty darned close to what we're currently paying" for PGE and PP&L power. Economic development benefits and long-term price stability could counterbalance a renewables price premium, to a degree, he indicated.
PGE is "excited" about Portland's interest in new renewables, and intends to make a proposal to the city, said renewables program manager Thor Hinckley. "Our goal is to put together a product that's cost-effective for us to offer and meets all their pricing needs," he said. "We're looking at this strictly as a power purchase agreement ... We want to be the facilitator, if possible, to make this happen."
PGE recently announced a 30-year deal to buy the power from PPM Energy's planned 75-megawatt-capacity Klondike II wind project in north-central Oregon, which is scheduled to begin commercial production by year-end 2005. That fulfills nearly 40 percent of the utility's 200-MW renewables target from its current integrated resource plan; Hinckley said PGE is seeking more renewables.
The city's load represents slightly less than 1 percent of PGE's entire system, which sold 2,103 aMW in 2003.
"I feel very optimistic this is going to happen," said Cogen, assuming the financial benefits from federal renewable energy production tax credits (which are set to expire at year's end) and the Energy Trust of Oregon. The RFI lists the federal Renewable Energy Production Incentive and Oregon's Business Energy Tax Credit program as other potential deal-sweeteners.
If Portland does become all-renewables, Cogen suggested, it would set a precedent for other cities to follow.
Portland is one of nine green cities to watch in the world, according to the March-April 2004 issue of Renewable Energy World, which mentioned the city's renewables pursuit.--Mark Ohrenschall
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Solar electricity is very diffuse.
Power from the sun typically comes not from big central plants, but originates on homes, businesses, public structures, highway signs, boats, communications facilities and many other installations around the globe; these are measured generally in kilowatts, not megawatts.
From a large-scale power generation perspective, solar remains a miniscule contributor. Solar accounted for well under one-tenth of 1 percent of U.S. energy consumption in 2003, according to federal government figures. Washington state, meanwhile, hosts an estimated 380 kilowatts of installed solar-electric capacity--slightly more than half the capacity of one turbine at the Stateline Wind Energy Center.
Solar remains very expensive compared to other generating resources, even other renewables. The Northwest Power and Conservation Council's new regional power plan sets a benchmark cost of 25 cents per kilowatt-hour for solar electricity; other sources put it as low as slightly below 20 cents/KWh for the best commercial applications, and at the high end above 50 cents/KWh in certain cloudy climes. Solar, too, is intermittent and relatively inefficient in energy production.
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Nevertheless, solar offers many compelling advantages as a clean, distributed energy resource tapping free fuel from the sun. It embodies the beguiling idea of energy independence.
Solar continues to expand around the globe--estimated 2004 growth is 40 percent--and this growth occurs, fittingly for the resource, on a diffuse scale.
The Northwest is advancing solar electricity in a dispersed way, as well, from training solar installers in Oregon and Washington to a proposed Central Washington demonstration project to Washington State University's participation in the upcoming Solar Decathlon to assorted utility programs.
In this story, Con.WEB profiles some regional examples of solar progress.
Solar Installer Training
In both Washington and Oregon, electricians are receiving training in solar-electric installations. This gathering trend addresses a lingering barrier to solar's growth in the region, while expanding professional opportunities for electricians.
In late September, a 9-kilowatt-capacity solar photovoltaic system was dedicated at the Puget Sound Electrical Joint Apprenticeship and Training Committee's Training Center in Renton, WA, just south of Seattle. This new addition to regional solar capacity--welcomed by a sizable crowd with representatives from labor, energy, environmental, utility and government entities--is noteworthy also for its teaching function. "The project, which is set to expand by five to 10 kilowatts ... each year, up to 50 KW, provides an opportunity for apprentice and journeyman electricians to gain valuable, hands-on solar electricity design and installation experience as part of their training," according to a press release.
This enhances PSEJATC's continuing education class in solar, which has already trained about 150 apprentice and journey-level electricians
Speakers at the Sept. 27 dedication touted economic opportunities and the benefits of clean, independent, fossil-fuel-free energy opportunities from the emerging solar industry.
Denis Hayes, Earth Day founder and now Bullitt Foundation president/chief executive officer, noted photovoltaics were originally developed in the United States, but Germany and Japan have solar-eclipsed the U.S. solar industry through policies favorable to sun power, such as Germany's substantial 64 cents/KWh payments for solar electricity fed into the grid. Looking ahead, he sees problems and limits for coal, nuclear, hydro, wind and biomass energy resources. "What's left is what you've got on this roof," Hayes said. He acknowledged concerns about solar's intermittency, but played up its homegrown and job-producing nature.
In addition to PSEJATC (operated by International Brotherhood of Electrical Workers, Local 46, and the Puget Sound Chapter of the National Electrical Contractors Association), this collaborative solar project involved Puget Sound Energy (which provided half the installation costs and net-metering arrangements); Bonneville Environmental Foundation; Worker Center, AFL-CIO; National Photovoltaic Construction Partnership; Apollo Alliance; and Burke Electric.
Meanwhile, in Oregon, the Energy Trust has provided free solar-electric systems for instructional use at seven electrical training centers, in Salem, Medford, Eugene, Portland, Klamath Falls, Redmond and Tangent. "The equipment was provided as a way for the students to see the equipment, work with it, install it," said Trust solar program manager Kacia Brockman. It has generated a "very enthusiastic" response at participating centers, she added.
As the Trust developed its solar electric program, "Industry training was identified as a need for helping to build and sustain an industry that would be viable in the long term, a growing industry," she said. Oregon also has set electrical licensing requirements for PV system installations, she added.
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The Trust wants to expand solar electricity use in the Beaver State--it has helped fund 895 KW--while also pursuing market transformation. "Our program has really focused on ... supporting the growth of the industry into one that is fully able to support the demand of the market and to acquire the confidence of the consumer," Brockman said.
Ellensburg PV Demonstration Project
The Central Washington community of Ellensburg is renowned for wind--three major wind farms are proposed in the surrounding area--but it also gets more than 300 sunny days a year.
Ellensburg's municipal electric utility is initiating a novel solar-electric demonstration project that promises considerable visibility and an opportunity for local investment.
Initially figured at 24 kilowatts capacity with potential expansion up to 165 KW, this solar farm would be situated right next to Interstate 90 and its approximately 30,000 passing vehicles per day, Ellensburg resource manager Gary Nystedt told the Northwest Solar Summit in Seattle in mid-November.
Another notable feature is the chance for city electric customers to invest in the solar system; Nystedt likened this to buying stock. Investor/participants would receive a proportional share of the solar-generated electricity--possibly, but not yet certain, at retail rates. Payroll deductions and home loans are two potential investment avenues for the solar project, according to Nystedt.
Nystedt said he has found community support and interest for this solar venture, from utility and city officials as well as faculty in technical fields at Central Washington University. Educational possibilities include school curricula, a kiosk at the site, Web-based solar energy-production monitoring and just plain sightseeing. Solar teaching could reach CWU, local kindergarten through 12th-grade schools, Ellensburg-area residents, I-90 travelers and other communities.
"The two main emphases will be giving the technology a lot of exposure to the general public, and to use it as a tool to educate college students and high school kids so that it becomes more standard in the way they think of energy," he told Con.WEB. He also hopes to inspire solar interest in other communities, and to help expand the solar market.
Nystedt said the first phase is planned for 2005. Exact costs, funding sources and timing are still being determined.
WSU Solar Decathlon Team
Washington State University is one of 19 colleges, and the only Northwest school, entered in the 2005 Solar Decathlon.
This is a U.S. Department of Energy-sponsored event in which student teams design and build 800-square-foot homes powered exclusively by the sun. These residences will be displayed and judged in September on the National Mall in Washington, D.C. The contest involves 10 categories "encompassing all the ways we use energy in our daily lives," and, according to a DOE brochure, "The winner of the Solar Decathlon will be the team that best blends aesthetics and modern conveniences with maximum energy production and optimal efficiency."
The ultimate goal, though, is solar education, as the brochure explains: "Today's students are tomorrow's engineers, architects, entrepreneurs, and homeowners--and the Solar Decathlon will encourage them to incorporate solar energy into their future careers and personal lives."
The Cougar squad consists of 23 students from the departments of construction management, architecture and electrical engineering, said team member Earl Eastman at the Solar Summit. Professor Mat Taylor is the team's "inspirational" leader, he noted.
Design work is done. The Solar Cougars have received commitments for solar panels, wiring and some other features, but continue to solicit materials and funds (for more details visit http://solardec.wsu.edu).
Eastman described the WSU team as a small, modestly funded, all-undergraduate "underdog" from the Palouse--but, he added, "We're confident we can compete and do well" in the competition among universities from the U.S. and abroad.
In another example of expanding solar education, board president Pam Burton of Solar Washington told the Solar Summiteers that the Evergreen State tallied 105 host sites in the annual National Solar Tour in October. That's double the number from 2003, which itself was doubled from 2002, she reported.
Utility Programs
Many Northwest utilities actively support solar electricity, including several with representatives at the Solar Summit.
One of the most talked-about ventures is Chelan County PUD's Sustainable Natural Alternative Power (SNAP) program, in which voluntary contributions from PUD customers support local renewables systems. Under SNAP, 52 KW of solar-electric systems (22 KW more are scheduled this spring at local schools) have been installed, along with three 10-KW-capacity wind turbines and a 3-KW hydro facility.
Chelan is now the largest solar-producing county in Washington, according to PUD energy services engineer Jim White.
He told the Solar Summit that SNAP payments to renewables producers, which are apportioned from customer funding, have dropped from $1.50 per kilowatt-hour the first year to 77 cents/KWh last year. This reflects a flattening of customer contributions, in the range of $25,000 to $30,000 a year, and the growth of SNAP production amounts, White later told Con.WEB.
SNAP's influence has extended well beyond Chelan County. Neighboring Okanogan County PUD has started its own version of SNAP, after considering other green power approaches, reported the PUD's Debbie Peters. SNAP-like programs also are being launched by utilities in Minnesota and Alaska, said Ellen Lamiman of Washington State University Energy Extension Program.
Another innovative venture is under way in northeastern Washington, in which Ferry County PUD offers either solar electricity or line extensions to off-grid homes (see Con.WEB, June 30, 2004 for story on this program). The PUD has installed several photovoltaic arrays under this program, as well as some line extensions. "In our situation, solar pencils out" with cost and maintenance benefits compared to line extensions in some circumstances, the PUD's John Friederichs told the Solar Summit.
Utility solar programs are also progressing in urban Western Washington. Seattle City Light's green power program, funded by voluntary customer payments, has led to 13 operating solar electric installations totaling 38 KW capacity, said City Light's Jack Brautigam. He touched on the values of collaborating with other local institutions, leveraging funds, involving stakeholders at host sites, using good technical resources and pursuing solar educational opportunities.--Mark Ohrenschall (Garrett Hering also contributed to this article)
Build an energy cluster and more energy technology companies will come, create wealth and increase jobs--so goes the hopeful thinking in Northwest communities attracted by the buzz around emerging technologies for energy efficiency, power systems controls and renewable generation.
Washington's Kitsap County and the Central Oregon area around Bend are two Northwest regions laying groundwork to develop local clusters of energy technology manufacturers and service companies as an economic development strategy.
Both areas see large growth potential. "This will be a huge industry," said Mark Frost of Sustainable Synergy, which is spearheading the Kitsap SEED project to develop an energy industrial park near Bremerton National Airport.
"Why not here in the U.S.? With the end of cheap oil, Middle East problems, natural gas prices, grid problems and China's growth, this is the time we should approach renewable energy development from a business point of view," Frost said.
"I liken new energy technology to where biotech was 25 years ago," observed David Porter, executive director of the Kitsap Regional Economic Development Council, who is advising Sustainable Synergy on fleshing out its proposal. "There are pockets of companies here and there. It's not yet a fully evolved sector."
This clustering concept, already evident in the Puget Sound region in aerospace and information technology, is seen as a way to foster growth and generate wealth.
The Northwest has a number of advantages in pursuing energy technology clusters, with its many existing firms, technological prowess, intellectual capital and quality of life.
But it also faces many obstacles, including competition from other regions, government energy policy uncertainties, difficulties in understanding the industry, and communications gaps.
Kitsap County Plans
Sustainable Synergy plans the energy park on 40 to 50 acres of industrial property that the Port of Bremerton is keeping available while the firm prepares a master plan, due to be finished by April , Frost said. The port has put up $25,000 for planning and Kitsap County has chipped in $10,000. Studies to determine the park's economic growth and jobs potential should be completed in April or May, Frost said.
Alternative energy and environmental technology is one of five industrial clusters with promising growth prospects in the greater Puget Sound region, which includes Kitsap County, said Bill McSherry, a regional economic strategy adviser with the Prosperity Partnership, an economic development initiative begun last year by the Puget Sound Regional Council. The initiative's goal is to add 100,000 jobs to the four-county region by 2010, beyond the 290,000 new jobs already forecast.
The Puget Sound region's alternative energy and environment cluster is small, with an estimated 2,845 jobs, according to a backgrounder report from Economic Competitiveness Group presented to a recent Prosperity Partnership conference in Seattle. This sector is projected to grow by nearly 4 percent nationwide from 2003 to 2008, the report said, and it has 30 percent more jobs per capita in Puget Sound than the U.S. average, McSherry added.
Central Oregon
In Central Oregon, the makings of a renewable energy cluster were in place before economic development agencies began targeting it for growth, said Scott Aycock, program administrator of the Central Oregon Intergovernmental Council.
The conference report of an October 2003 renewable energy forum in Redmond, OR estimated that about 65 solar, wind, geothermal, biomass, hydro and fuel cell companies were located in the area, generating about $20 million in annual sales and 200 jobs. Central Oregon covers nine counties--Wasco, Sherman, Gilliam, Wheeler, Deschutes, Jefferson, Crook, Klamath and Lake.
"Some have moved here and some are homegrown," Aycock said. "The main factor is our incredible resource potential. We have wind, lengthy sunlight hours, industrial and direct-use geothermal, and irrigation canals suited for small-scale hydro. On our agriculture lands, we have wind and biomass, with a lot of small-diameter timber."
Participants in the 2003 forum described a 10-year vision of 100 energy technology companies in Central Oregon generating $635 million per year in annual sales and more than 3,800 jobs.
The Central Oregon Intergovernmental Council joined with 3E Strategies, a Bend non-profit organization, to create the Business Alliance for Sustainable Energy to grow a renewable energy cluster in Central Oregon. BASE will seek to build public and governmental awareness about energy technology industries, foster communication among businesses and help companies pursue funding, said 3E Strategies executive director Cylvia Hayes.
Clustering Concepts
The clustering that Central Oregon and Kitsap County are attempting to promote is not a new concept. The working definition of a cluster is a group of companies, including specialized suppliers, service providers and supportive institutions, such as universities and government research labs, that are in the same geographic area, according to Prosperity Partnership's Web site.
Existing clusters in the Puget Sound region include aerospace and information technology. Examples elsewhere include the entertainment industry in Los Angeles, high finance in New York and auto manufacturing in Detroit.
Clustering is important for fostering growth because geographic proximity enables manufacturers in the same industry and their service providers to communicate, trade ideas and innovate more efficiently, said Lee Cheatham, executive director of the Washington Technology Center, a state economic development agency. Cheatham also chairs the board of the Northwest Energy Technology Collaborative, a public/private organization seeking to accelerate the growth of energy technology industries in the Northwest.
Clustering can help an industry sector generate wealth that can be exported out of region, a key to economic growth, Cheatham explained. "With clustering, you have a better chance of building wealth rather than just trading dollars back and forth" within a region, he said.
Frost hopes the Bremerton energy park will create a "virtual lab" atmosphere that will encourage technology companies to work together and generate ideas collaboratively. "The potential is to create whole combinations of new technologies no one had thought of on their own," he said. Companies that have shown interest in locating at the park include a micro-wind developer and energy software vendors.
Clustering can give brand recognition to a region and attract talented professionals that technology companies need, Cheatham added.
Northwest Energy Cluster Potential, Advantages
The Northwest's potential to develop energy technology clusters is high, research has shown. Energy technology industries could double in size and produce more than 12,000 new jobs in Washington, Oregon and British Columbia by 2020, even without supportive public policies, according to the 2001 "Poised for Profit" report from Climate Solutions.
Globally, investments in "clean technologies" such as fuel cells, renewables, efficiency and power system control technologies could total $3.5 trillion in the first two decades of the 21st century, or $180 billion per year, the report said. The Northwest's average annual investment in clean technologies over that time period is forecast to total $2.5 billion, with 85 percent going to efficiency, the report added.
With electric system reliability concerns mounting, the Northwest has a near-term opportunity to grow a regional "smart energy" cluster from an existing base of 225 companies generating $2 billion in revenues selling information technologies and software to optimize power systems control, according to the second "Poised for Profit" report, published in 2003.
The report noted that advanced metering, utility software and power system electronics markets are growing at double-digit rates. The report also said "smart energy" technologies can play off the region's existing strengths in software, electronics and wireless technologies.
Washington has a diverse suite of existing strong energy technology companies, according to a draft report to the state Legislature prepared by the Washington Technology Center and state Department of Community, Trade and Economic Development. They include fuel cell development in Spokane, grid control software in Bellevue, solar materials in Vancouver and energy efficiency firms in Seattle.
According to the Prosperity Partnership backgrounder, the Puget Sound ranks fourth of 125 metropolitan regions around the world in a "knowledge competitiveness" index, based on 19 benchmarks, including employment in the knowledge economy, patent registrations, research and development investment, and information technology infrastructure.
Investors, meanwhile, are picking up the scent of profit opportunities. Venture capital investment in energy technology has grown dramatically in recent years, Rodrigo Prudencio, a principal with the San Francisco venture capital firm Nth Power, said at a Seattle City Club energy forum Jan. 28. The percentage of U.S. venture capital going to energy technologies has risen from less than 0.5 percent in the mid-1990s to more than 2 percent today, Prudencio said.
Less tangible but still important are social factors, Aycock said. "Socially and culturally, we have a pretty strong entrepreneurial ethic. We have a lot of self-made types and venture capital types. You put them together and you have a natural opportunity," he said.
Making it in Central Oregon is not easy, so entrepreneurs must "be flexible, be innovative, and be creative," Hayes said, recounting her own experience cleaning recreational cabins and working other odd jobs while building 3E Strategies.
High quality of life is seen as another Northwest advantage.
Businesses are attracted to Central Oregon because their leaders find the region appealing, Hayes said. "There's a statistic we have that 70 percent of the companies that relocated here did so after the CEO visited on vacation," she noted.
As for Kitsap County, Porter said "people want to live here. We have a high level of an environmental stewardship ethic and a lot of smart people," he observed.
Clustering Obstacles
But Northwest communities also must deal with significant obstacles to growing energy technology clusters, research has shown.
One obstacle is competition from regions outside the Northwest that also see the economic potential in energy technologies. California's renewable energy public benefits fund is luring Northwest companies to relocate to the Golden State and tap its huge market, according to the draft Washington Technology Center/CTED report.
Eighteen states (including California) and the District of Columbia have renewables portfolio standards, but Washington and Oregon do not.
Another barrier is difficulty in understanding the current state of technology industries and their economic impacts. The categories governments use to identify industries and track business activity "don't align with clean energy industries," Hayes said. "We have a lot of legwork to do to figure that out."
Gathering better data on jobs, wages and sales for energy technology companies is a prerequisite to setting hard growth targets in Central Oregon, Aycock said.
In Puget Sound, McSherry said Prosperity Partnership is convening an industry work group this spring to identify opportunities and barriers, and to set growth goals.
Uncertainty in government energy policy is another reported problem. At the 2003 Central Oregon forum, the leading policy recommendation made by industry representatives was for Oregon to adopt a renewables portfolio standard, Aycock said.
The on-and-off federal production tax credit for wind power creates great uncertainty, Vic Fryling, chief executive officer of Renewable Energy Systems, said at the Jan. 28 Seattle City Club forum. His company is developing the 150-megawatt-capacity Hopkins Ridge wind farm in Washington's Columbia County. If the project is not completed by Dec. 31--when the 1.8 cents per kilowatt-hour PTC is now scheduled to expire--its value will fall from $170 million to $97 million, Fryling said.
Even with supportive policies in place, companies need assistance navigating the halls of government, Hayes said. "These guys need help in discussing their needs with elected officials and agencies. They need help in identifying funding opportunities," she said.
A key factor in building clusters is creating local markets for their products and services, Cheatham said. "Local markets may not be big enough for long-term success, but they're a great launching pad to try stuff out."
A trained work force will be crucial in Central Oregon, Aycock said. "Local educational institutions don't have energy programs to train the interns and workers these companies will need." Hayes said BASE is working with Central Oregon Community College and Oregon State University-Cascades Campus to create work force training programs.
Improving communications within the industries and with the public and policymakers is essential, experts said. "One of the great frustrations is that there is little communication between the various industry sectors. Wind people don't talk to geothermal people, and vice versa," Hayes said.
She further noted that many technologically savvy entrepreneurs don't have the marketing and public relations skills that are essential for creating successful business models. Hayes said she has spent much of her time educating community leaders and getting them past initial skepticism about renewable energy prospects.
Local support is essential, Frost said: "In my opinion, the (Kitsap energy project) won't work without buy-off from the local community."
Cheatham said that "when people in communities get behind this development, that's where success lies."--Jim DiPeso
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