CWEB.108/December.22.2004

Expanded Energy Efficiency

Idaho Power Proposes Big Boost in DSM
Rate Surcharge, Programs; Issues Draft Wind RFP

Idaho Power has proposed an exponential increase in its demand-side management rate surcharge, to fund much-expanded energy conservation efforts over the next five years.

This big energy-saving push arises from the investor-owned utility's 2004 integrated resource plan, which included six DSM programs in a favored resource blend for Idaho's largest utility as it faces anticipated sizable load growth in the coming years.

Idaho Power wants to increase its DSM rate surcharge, also known as a tariff rider, from 0.5 percent of base revenues to 1.5 percent starting in June, and then to 2.4 percent in June 2007, according to a Dec. 6 filing to the Idaho Public Utilities Commission.

This plan would generate about $53 million for utility demand-side initiatives from 2005 through 2009, primarily for initiatives targeting new commercial and residential construction, industrial and irrigation efficiencies, residential air conditioner cycling and irrigation peak reductions. It also would support Idaho Power's role in the Northwest Energy Efficiency Alliance and various other demand-side activities, including limited residential and commercial retrofit programs.

Estimated energy savings from the IRP-identified DSM ventures are at least 10 average megawatts, and 103 MW of peak demand reduction.

Idaho Power currently collects about $2.6 million annually from its DSM rate surcharge established in mid-2002. Residential customers now pay 30 cents a month; this would rise, for the average household customer, to 85 cents a month next year and $1.36 monthly in 2007.

The utility's proposal also includes an option for large industrial customers to internally spend their share of the DSM charge on efficiency measures.

Idaho Power has asked for an IPUC ruling by early spring. Although no action had been taken as of mid-December, IPUC spokesman Gene Fadness told Con.WEB, "The commission's view on this demand-side management has always been that if [Idaho Power] can demonstrate to us that the costs of the rider save customers money in the long run and it's cost-efficient, then we will probably support it. If they can demonstrate that it will actually save or delay the construction of peak power plants or more transmission lines, we're always looking for ways to not have to put those huge projects in rate bases."

Meanwhile, Idaho Power also has released a draft request for proposals for 200 MW of wind capacity; it plans to issue the RFP in January.

Idaho Power Conservation

From 1978 to 2002, Idaho Power energy savings totaled 49 aMW, tallied in the familiar historical roller coaster pattern for regional energy conservation, according to figures reported by the Northwest Power and Conservation Council.

In May 2001, as the 2000-01 Western energy crisis generated renewed motivation for utilities and customers to reduce energy consumption, the IPUC ordered Idaho Power to create a comprehensive DSM program. The DSM rate surcharge was enacted in 2002, and has funded such ventures as compact fluorescent lighting for residential and small commercial customers, industrial and irrigation programs, pilots for residential air conditioner cycling and irrigation peak clipping, and assorted other initiatives. An advisory group has helped Idaho Power develop its demand-side portfolio.

Idaho Power reports it saved 4.6 million kilowatt-hours in 2002 and 5.9 million KWh in 2003.

In its 2004 IRP, issued in August, Idaho Power envisioned a much bigger role for renewable energy and energy-saving programs as part of a more diverse energy future to meet an anticipated 2.2-percent annual load growth over the coming decade.

The plan's favored acquisition scenario through 2013 calls for 500 megawatts of coal power, but also 450 MW of non-hydro renewables (primarily wind and some geothermal) and 124 MW from demand response and energy efficiency ventures. Another 198 MW would come from gas-fired power, combined heat and power at industrial facilities, market purchases or distributed generation.

Idaho Power "believes that a blended approach based on a portfolio of diverse resources is the most cost-effective and least-risk method to address the increasing energy demands of our customers," the IRP said.

Idaho Power DSM

Through the utility's IRP process, six DSM programs rose to the fore. All six have elements of seeking to lower summer peak demand, according to IPUC-filed testimony from Idaho Power pricing analyst Timothy Tatum.

Two of the programs would promote energy efficiencies in the design and construction of buildings. A residential venture, modeled after the Energy Star Homes Northwest programs, would offer financial incentives to builders and potentially home-buyers, according to Tatum's testimony. The commercial endeavor would provide incentives and education, targeted to building owners and developers, architects and engineers.

Idaho Power also would furnish energy-saving incentives to industrial and large commercial customers (and assist with audit expenses), and to irrigation customers for more energy-efficient new or existing watering systems.

The other two ventures fall under demand response, as a strategy to help shrink the utility's highest summertime loads: residential air conditioner cycling and irrigation peak clipping (see related story for details).

These six would cost a projected $44 million over five years, according to Idaho Power's filing. Annual costs would rise from $5.5 million in 2005 to $10.8 million in 2009, averaging $8.8 million a year ( see more details on program costs, savings and descriptions).

The remaining $9 million Idaho Power wants to spend on DSM in the next five years would be roughly split between Alliance funding (about $4.4 million) and limited commercial/residential retrofits (starting in 2006), lowering distribution system voltages, small projects, education, DSM-related research and studies, and administrative costs.

DSM Rate Surcharge Increase

To pay for the burgeoning demand side of its resource future, Idaho Power wants to gather more money from its retail customers.

The present DSM rate surcharge collects about 0.5 percent of base utility revenues. Residential customers shell out 30 cents per month, while other customers pay on a cents-per-kilowatt-hour basis; irrigators are capped at $15 per meter, according to testimony from Idaho Power pricing director Maggie Brilz.

This DSM surcharge would grow to 1.5 percent of base revenues as of June 1, and then to 2.4 percent on June 1, 2007, under Idaho Power's proposal. The utility considered but rejected a 2 percent DSM surcharge starting next year; that would have created "a significant funding surplus through 2008," and a deficit in 2009 when programs should be fully operating, according to Brilz' testimony. The surcharge level may need to change again, based on results of the 2006 IRP, her testimony noted.

In addition, Idaho Power wants to switch the DSM surcharge structure from a kilowatt-hour basis to a base revenue percentage. Brilz' testimony explained why: "Because of the capacity component of these programs, and because the IRP-related DSM programs comprise such a large percentage of the total DSM programs targeted for implementation, I believe it is appropriate to recover program costs based on the customers' total base revenue rather than only on the energy component of customers' bills. A Rider based on the total base revenue recognizes both the capacity and energy utilized by a customer and more equitably recovers the DSM program costs."

For large industrial customers, Idaho Power has suggested a so-called "self-direct" alternative in which these companies could set up individual accounts with their portion of DSM surcharges, and tap those funds for approved energy-saving ventures. This approach--agreed to by stakeholders--also includes elimination of minimum payback requirements and expanded facility energy auditing.

Any such self-directed dollars not used by 2008 would go into the general DSM surcharge fund. Eligible customers not choosing self-direction could access the utility's industrial DSM monies.

This proposal follows from a recent IPUC directive to Idaho Power to develop a conservation program for large industrials, preferably with matching funds from their contributions to the DSM surcharge.

Idaho industrial customers have previously sought self-direction, for their share of Idaho Power Alliance funding, but that idea was nixed at the time by the IPUC (see Con.WEB, April 25, 2000).--Mark Ohrenschall

More Information:

• Idaho Power DSM proposal

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Demand Response

Idaho Power Asks IPUC to Approve
Peak Demand Reduction Programs

Idaho Power is bringing its search for solutions to reduce peak demand directly to the people.

In November, the investor-owned utility asked the Idaho Public Utilities Commission for permissions on residential air conditioner cycling and irrigation peak clipping programs, both of which have been piloted by Idaho Power.

Both ventures would rely on voluntary customer participation, and are designed to curtail power demand when energy is most desired in Idaho Power's service territory: hot summer afternoons when air conditioning and irrigation pumping loads coincide.

Stepped up demand-response efforts are needed, and soon, Idaho Power contends, as it expects to serve more than 10,000 new customers each year through 2013. Over this period, the utility anticipates its peak load requirements will grow by more than 60 megawatts each year. The two proposed demand-response ventures could save 76 MW collectively by 2009, according to Idaho Power.

Cutting Residential AC, Irrigation Peak Demand

Rather than meeting load growth solely with new generation, Idaho Power declares in its 2004 Integrated Resource Plan that it intends "to give equal and balanced treatment to both supply-side resources and demand-side measures."

Karl Bokenkamp, general manager of power supply planning for Idaho Power, said demand-response and energy efficiency programs together provide a "significant contribution to the plan."

According to the IRP, Idaho Power foresees increasing the capacity of its system by 940 MW through 2013. Demand-response and energy efficiency programs are expected to comprise 76 MW and 48 MW of this sum, respectively. In 2003, Idaho Power programs resulted in 5.9 million kilowatt-hours and 189 kilowatts of summer peak demand reduction for the utility.

Bokenkamp said Idaho Power's air conditioner cycling and irrigation peak clipping programs are expected to achieve savings of 45 MW and 30 MW, respectively, by 2009. The IRP said both programs' capacity costs were also found to be economical compared to supply-side peaking resources. "Both demand-response options were determined to be cost-effective based on their dispatchability and peak benefits," the IRP said.

If approved by the IPUC, Idaho Power's irrigation peak clipping program would be implemented throughout its Idaho service area in June, July and August.

Participating customers would have power turned off to irrigation pumps up to three times per week, from 4 p.m. to 8 p.m. each episode, by utility-installed timers on electrical panels. Participants would receive a monthly demand credit ranging from $2.01 to $2.76 per kilowatt of demand.

For a 2004 irrigation peak clipping pilot initiative, an evaluation found "observable load reduction impacts over the three-month summer period," and found that customer monthly billing demand shrank by 50 percent--less than the 80 percent assumed for the pilot.

Idaho Power estimates the proposed program would cost $1.5 million annually--almost two-thirds for incentive payments--and yield more benefits than costs from the start, from a utility cost test perspective.

It wants to start signing up customers early next year, for the 2005 irrigation season.

The utility's AC cycling program would be available to residential customers in Ada and Canyon counties and the city of Emmett whose homes have advanced meter-reading capability.

Idaho Power would send signals to a direct load control device inside each participating home to cycle on and off central air conditioners, for up to four hours any weekday during June, July and August. These cycling episodes would be limited to 40 hours each month and 120 hours per season. Participants would get a $7 monthly credit on their July through September electric bills.

A two-year pilot residential air conditioner cycling program in Boise and Meridian found an average daily load reduction of 1.1 KW per customer when the temperature rose to 95 degrees or higher.

This program would cost about $1.5 million annually, similar to the irrigation peak clipping venture, but wouldn't reach a benefit-cost ratio above 1 until the 10th year.

Idaho Power spokesman Dennis Lopez said the utility has faced little difficulty in recruiting volunteers for the demand-response programs.

According to the utility's IRP, 74 percent of the 204 volunteers in its AC cycling pilot program reported experiencing "little or no discomfort from cycling," and overall average home temperatures increased by only 1 to 2 degrees over the program's four-hour cycling periods. The IRP said surveys taken before and after the cycling season also revealed "high levels of customer satisfaction" for the program.

Energy Star Homes

Among its other continued efforts to reduce demand, Idaho Power in conjunction with the Idaho Energy Division and the Northwest Energy Efficiency Alliance in October announced the opening of 76 homes in reportedly the first Idaho housing community built entirely to the Northwest Energy Star standard.

Celeste Becia, Idaho Power's program manager for the Energy Star Homes program, said each of the 76 homes in the Stevens Springs development will reduce peak demand by 2.8 KW or 2,078 KWh per year. The entire development will curtail 15.7 MWh of annual demand.

Reducing power demand is an imperative, Becia said. The utility's IRP projects the number of households in its territory is expected to grow from 320,000 today to 380,000 by 2013. In southern Idaho alone, peak demand is expected to increase by 80 MW each year.

Idaho Power concluded that, over the 10-year lifetime of its current IRP, the Energy Star Homes program will save it money. In a utility analysis for the IRP, power supply costs were cut when demand-side management options such as energy-efficient new home construction was added into the portfolio.

The Energy Star Homes program will also help utility customers lower their electric bills. Although the monthly mortgage payment on a $160,000 home built to Energy Star specifications might be higher by about $35 a month, the immediate savings on a homeowner's energy bill would be about $50 a month from the first month of ownership, according to Becia.

Idaho Power's goals for the program are contingent on getting many more builders involved, Becia said.

"The ones that are interested and doing it now are the early adopters," she said. "They tend to build fewer homes and more expensive, unique homes anyway. Getting the high-volume builders who are most affected by the bottom-line costs involved is the most difficult. These types of small builders need to know how to build energy-efficient homes for less cost."

Similarly, home-buyers are not necessarily aware of the benefit-cost ratio of energy-efficient construction, and will wince at the added initial cost, Becia said. To counter these perceptions, Idaho Power offers builders a $750 incentive for each Energy Star-certified home constructed.

An Energy Star certified home features high efficiency windows, lights, appliances, water heaters, insulation, heating and cooling equipment that will collectively save an average of 1,000 to 1,500 KWh per year for gas-heated homes and 3,700 KWh per year for electric-heated homes. Northwest homes built to this voluntary construction standard are at least 15-percent more energy efficient than homes built to Washington and Oregon state energy codes. The Energy Star Homes Northwest project aims to capture 20 percent of the new home market by 2008.--Joel Puglisi and Charles Redell (Mark Ohrenschall also contributed to this article)

More information:

• Idaho Public Utilities Commission (includes Idaho Power program applications: cases IPC-E-04-26 [irrigation peak clipping] and IPC-E-04-27 [air conditioner cycling])
• Idaho Power
• Northwest Energy Star

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Lamp Disposal

Local CFL Recycling Program Starts in Oregon;
Puget Sound Venture Launching in January

When millions of compact fluorescent lamps flew off Northwest shelves during the West Coast energy crisis of 2000-2001, some consumers already were thinking about keeping the speck of mercury in each lamp out of landfills after the bulbs expired.

"We got customer comments about keeping them out of landfills. I'd get the calls and it heightened my awareness that we should start thinking about recycling sooner rather than later," said Bob Lorenzen, demand-side management program manager for Eugene Water & Electric Board.

CFL recycling now has arrived in the Northwest.

In October, a one-year pilot retail collection program for spent fluorescent lamps got under way in Oregon's Lane County, said officials from local utilities and waste management agencies.

Lane County residential customers can drop off burned-out CFLs and fluorescent tubes up to 4 feet long at 10 cooperating retailers in the greater Eugene area. Commercial customers are not eligible, utility officials said.

Meanwhile, in January, a six-month recycling pilot will kick off in four Puget Sound counties--King, Snohomish, Thurston and Kitsap. Residential customers of Puget Sound Energy, Seattle City Light and Snohomish County PUD will be able to drop off spent CFLs and tubes at 68 participating hardware, lighting and drug stores, according to Lauren Cole, project manager with the Local Hazardous Waste Management Program in King County.

Recycling CFLs

The recycling programs originated in discussions among utilities, government agencies and waste haulers that the Zero Waste Alliance, a Portland-based non-profit organization, initiated in 2002. At the group's first meeting, Zero Waste Alliance projected that all the 8.3 million CFLs sold or given away in Oregon, Washington and Idaho during 2001 would be burned out by 2009.

Out of those discussions, the Northwest Energy Efficiency Alliance proposed a pilot recycling program in Lane County, Lorenzen said.

After examining the Zero Waste Alliance's research on CFL recycling in other areas, Lane County program leaders concluded that retail drop-off would be the most practical way of collecting spent lamps, he added.

Minnesota provided a good retail program model, Lorenzen said. Following a state ban on landfill disposal of fluorescent lamps, Minnesota has worked with a local recycling company, Mercury Technologies, to collect burnt lamps from drop-off boxes at retailers, according to a Zero Waste Alliance case study.

Educating consumers about fluorescent lamp disposal can be tricky, said Vicki Fulbright, communications manager for Ecos Consulting, which runs the Alliance's residential lighting program.

While it's important to educate consumers that fluorescent lamps contain mercury and must be recycled, it's equally important not to scare consumers away from fluorescents and their energy-saving benefits, she said. "It's a very fine line," Fulbright pointed out. "You want to inform, but not alarm."

The balancing point in the message is to tell consumers that each CFL contains only a tiny amount of mercury, and there is no risk of exposure as long as lamps are properly handled and disposed of, Fulbright said.

Lane County, Puget Sound CFL Recycling

Lane County's fledgling collection program has "worked really well so far," said Joe Savage, lead residential program manager for Emerald PUD, one of five Lane County utilities sponsoring the program.

Following a kickoff at the Lane County Home Improvement Show in October, about 500 CFLs and 6,000 feet of fluorescent tubes had been gathered through the fall, according to Larry Gibbs, a special waste analyst with the Lane County Waste Management Divison.

In addition to Emerald, other utility sponsors are EWEB, Lane Electric Cooperative, Blachly-Lane Electric Cooperative and Springfield Utility Board. Other sponsors include Lane County and the Oregon Department of Environmental Quality.

"Our interest is to try to reduce mercury hauled to landfills by offering the public a convenient way to handle it properly," said Brian Fuller, a DEQ waste reduction specialist. While CFLs contain an average of only 5 milligrams of mercury apiece, a sizable number of fluorescent lamps burn out each year. According to the U.S. Environmental Protection Agency, 600 million fluorescent lamps are disposed of annually nationwide.

Broken fluorescent and high-intensity discharge lamps account for 1 percent of the estimated 158 tons of mercury emitted into the environment each year from human activities, according to EPA's 1997 mercury report to Congress.

Utilities that promoted CFL sales to cut demand during the energy crisis were aware early that disposing spent CFLs would be an issue, said EWEB spokesman John Mitchell. "The concern among utility staffs was that since we promoted the use of fluorescent lamps, we should be proactive in getting them recycled," Mitchell said.

During the West Coast energy crunch, EWEB sent out 320,000 coupons for CFLs. Mitchell estimated 770,000 CFLs were sold in Lane County between the middle of 2000 and the end of 2002.

Before the recycling program began, Lane County residents could take their spent fluorescent lamps to the county's household hazardous waste collection center (they still can). However, the facility is open only one day a week and one Saturday a month.

"You have to make an appointment. It isn't convenient for people," Lorenzen said. "As lamps burn out, we felt we needed to look at making recycling more convenient."

Now, Lane County consumers can take spent lamps to seven retailers in Eugene, two in Springfield or one in Junction City. These are lighting merchants, hardware stores, energy product outlets run by Emerald PUD and Lane Electric, and Jerry's, a local home improvement chain.

The county waste management division picks up the dropped-off lamps, then sends them to EcoLights in Seattle for recycling, Gibbs explained. EcoLights crushes the lamps and separates the mercury, phosphors, metals and glass. Recovered mercury and phosphors are sent to a retorter, where the mercury is separated.

Through the end of 2004, Oregon DEQ paid for recycling lamps, at a cost of 50 cents each for CFLs and 12 cents per foot for tubes, Gibbs said. Starting in 2005, Lane County will pay for disposing lamps dropped off at all retailers, except Jerry's, which will cover the costs of fluorescents dropped off at its two participating outlets, he added.

What's in it for the retailers? Mitchell said utility promotion of the recycling program will draw people into stores to drop off lamps and buy replacements. Increasing foot traffic is "part of the allure for the retailers," he said.

The five utilities, with the help of a $15,000 grant from DEQ, are marketing the program through a brochure, bill inserts, newsletters, newspaper and broadcast advertising, posters and "aisle wobblers," which are retail shelf extensions designed to grab shoppers' attention.

Gibbs estimated the total cost of the program, excluding disposal, is about $45,000.

The Puget Sound program will operate somewhat differently, Cole said. Consumers at 66 of the 68 participating retailers will be charged 50 cents for each lamp they drop off for recycling. Utilities will offer 50-cent coupons toward purchase of replacement lamps, she added.--Jim DiPeso

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Key Financing Option

Energy Savings Performance Contracting
Returns for Federal Facilities

A key financing option for federal government energy conservation has returned after a one-year hiatus from the national scene.

Energy savings performance contracts are once again available for federal facilities, including those in the Northwest, which should lead to more efficiency project opportunities for the country's biggest single energy consumer--the federal government.

ESPCs allow federal agencies to undertake energy-saving improvements with no initial capital costs. Private firms arrange financing for developing and completing such projects, and are paid through guaranteed energy bill savings.

However, congressional authority for federal ESPCs lapsed in September 2003, under a legislative sunset provision. And, despite widespread support for this energy-saving avenue, ESPC reauthorization languished for a time in various pieces of energy legislation, according to Alliance to Save Energy policy director Kara Rinaldi.

"This [ESPC] program is a very well-liked program," she told Con.WEB. "It's really public policy at its best," a public-private partnership benefiting the federal government and its facilities, taxpayers, businesses and the environment.

However, ESPC continuation was held up by a Congressional Budget Office ruling that said it would cost the government $3 billion over 10 years--a conclusion Rinaldi and others said misinterpreted the funding source and failed to account for the guaranteed federal energy bill savings.

ESPCs eventually gained renewed life through September 2006, in the fiscal year 2005 defense spending bill signed by President Bush Oct. 28. This legislative vehicle was very appropriate, Rinaldi noted, since more than two-thirds of federal ESPC work is conducted with the Department of Defense.

A June ASE news release called ESPCs "the premier tool for promoting energy efficiency within the federal government," and lamented that their absence stopped more than $300 million of projects around the country.

Northwesterners interviewed by Con.WEB expressed gratitude at ESPC's re-emergence, and called for a more lasting authorization.

Energy Savings Performance Contracting for The Feds

ESPCs were first approved for the federal government in 1986, and further amended in the Energy Policy Act of 1992, according to the U.S. Department of Energy's Office of Energy Efficiency and Renewable Energy.

They can enable federal agencies to hurdle the capital funding barrier for energy-saving projects. According to ASE, ESPCs accounted for $298 million of energy upgrades to federal facilities in 2001--more than 40 percent of all funding earmarked to reduce federal energy consumption, based on DOE figures.

DOE's Federal Energy Management Program reports that ESPC projects valued at $1.7 billion have been completed by 18 separate agencies and departments in 46 states. These annually save 13.6 trillion British thermal units, equal to the energy used by a city of 500,000 residents (slightly smaller than Seattle). And they reduce energy bills by $4.7 billion, of which $3.2 billion will pay back the private funding, creating $1.5 billion in net governmental savings.

"The program has consistently received strong bipartisan support, and strong industry and environmental support," Rinaldi said.

ESPC reauthorization went into several proposed federal energy bills starting in 2001, she said, but none passed before the program's Sept. 30, 2003 expiration.

The only specific hindrance was the CBO's interpretation of a $3 billion budget impact over 10 years. "There are two reasons for this paradoxical [budget] score," according to ASE's Web site. The "payments under the contract are considered mandatory obligations on the government, but the savings are realized in energy bills, which are paid out of discretionary spending, which does not score."

In an April 2004 letter to congressional budget leaders, business, utility, labor, public interest and clean energy group officials noted the CBO counted private investment as federal spending, and didn't factor in the energy bill savings.

One of the signatories to that letter was Craig Williamson, president and chief executive officer of Seattle-based Abacus Engineered Systems, who also serves on the board of the National Association of Energy Service Companies.

Williamson called ESPCs "an important tool in allowing performance contracting to take place in federal buildings," and the reauthorization "very positive" and "very important."

Although Williamson said Abacus' work focuses more on municipal and institutional clients than on the federal government, he said he had been involved in a "huge" ESPC project at the Hanford Site in Eastern Washington with his former company, Johnson Controls (see Con.WEB, April 25, 1997). He knows of "quite a bit" of other ESPC activities in Northwest military facilities in particular.

Stan Price, executive director of the Northwest Energy Efficiency Council, said he was "pleased" about the federal ESPC reathorization. "Performance contracting has proven to be an excellent consideration for public facilities, be it schools, universities, state facilities or federal government buildings. We're hopeful that the federal government will see fit to provide a permanent reauthorization for performance contracting in the federal sector, as a start-stop cycle is always injurious to good business conditions."

Williamson also called for more lasting federal ESPC authority.

Another Northwesterner glad for the federal ESPC reauthorization is Pat Clark, property development director for the Northwest/Arctic Region of the U.S. General Services Administration, which owns about 10 million square feet of property in Washington, Oregon, Idaho and Alaska, primarily in office and court buildings.

Clark recalled at least three ESPC projects in recent years involving Northwest GSA properties, two in the Seattle area and one in Portland.

He called ESPCs "another form to leverage your ability to get energy conservation work done if capital dollars are not available. Our preferred method is not to do a project on a payment stream. We prefer the capital up front." In considering ESPCs, he generally tries to stay within a 10-year payback--much beyond that period, he told Con.WEB, equipment tends to start degrading along with energy efficiencies.

ESPCs are best suited for large HVAC and controls projects, particularly in building renovations, Clark believes. Performance contracting can help achieve energy savings, and associated financial and environmental benefits (such as from cleaner refrigerants and more efficient gas-fired boilers), that would otherwise be delayed or missed.

Although private contractors must guarantee ESPC energy savings and thus bear considerable risk, government officials also need to play an active role, Clark said. For example, he cited a conflict between ESPC and general contractors over work assignments on a Seattle building project, which created some management issues for GSA. He also mentioned the importance of good operations and maintenance practices. Any additional energy efficiencies beyond the ESPC guarantee accrue 80 percent to the feds, which Clark said offers an incentive to "squeeze as much energy conservation as you can."

Super ESPCs

The nature of federal sector performance contracting has changed markedly in recent years, with the advent of so-called "Super" ESPCs created by FEMP. Under this option, federal agencies can work with prequalified energy service companies on ESPC projects, rather than pursue individual such contracts.

A FEMP handout described Super ESPCs as a simpler, quicker and more flexible method of performance contracting, and an accompanying graph illustrated their popularity: stand-alone federal ESPCs peaked in about 1998 with nearly $100 million worth of private-sector investments, while Super ESPCs rose from virtually nothing in 1998 to more than $300 million in 2002.

This also has the practical marketplace effect of limiting the number of companies engaged in federal performance contracting. In the Western region (which includes Idaho, Oregon and Washington), the four prequalified Super ESPC firms are Sempra Energy, Johnson Controls, Honeywell and Noresco.--Mark Ohrenschall

More Information:

• Federal Energy Management Program
• Alliance to Save Energy

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PTC, IRP Fruits

Recent Wind Project Development Announcements Could
Lead to Big Increase in Northwest Wind Capacity in 2005

Major developments for three proposed Northwest wind energy projects have been announced in recent weeks, and these trio of wind ventures could lead to a nearly two-thirds increase in regional wind energy capacity by the end of 2005.

These announcements also bear some renewables fruits of utility integrated resource planning and the October extension of the federal wind energy production tax credit.

Puget Sound Energy has signed a non-binding letter of intent to acquire the proposed 150-megawatt-capacity Hopkins Ridge wind farm in southeastern Washington. Announced Dec. 1, this is Puget's second planned wind project acquisition, following the September news of its intention to own a 230-MW-capacity wind project in Central Washington. Both stem from Puget's IRP process and its goal of 10-percent renewables for the utility by 2013.

On Dec. 9, Portland General Electric made public a 30-year agreement to buy all the power from PPM Energy's planned 75-MW-capacity Klondike II wind project in north-central Oregon. This is PGE's biggest wind power purchase, and a sizable step toward reaching the investor-owned utility's 200-MW renewables goal described in its latest IRP.

Also in early December, Columbia Energy Partners and the Confederated Tribes of the Umatilla Indian Reservation revealed their joint effort toward a 104-MW-capacity wind project, also in north-central Oregon. The Umatillas would invest in and gain an ownership share of this wind farm scheduled for a 2005 completion; if built, this apparently would be the first Northwest wind project with substantial Indian involvement. This wind proposal is on PacifiCorp's shortlist for new renewable resources, but no power purchase agreement had been reached as of Dec. 20.

Puget Sound Energy/Hopkins Ridge

Hopkins Ridge was one of three wind projects short-listed by Puget earlier this year in its quest for new resources, and now it's one of two for which Washington's largest utility has inked a letter of intent for acquisition.

As with the proposed Wild Horse Wind Power Project in Kittitas County, Puget concluded project acquisition offered the best deal.

"It really came down to a large extent to be a matter of economics," Puget resource acquisition director Roger Garratt told Con.WEB. Wind farm ownership, compared to power purchasing, would save the utility roughly 10 percent to 15 percent over the project life. That owes primarily to Puget's "significantly lower ... cost of capital than you're seeing under the alternative types of structure," and lower imputed debt, he said. Puget estimates a $200 million cost to build the project.

The planned 150-MW wind farm in Columbia County, proposed by developer RES North America, brings several "attractive attributes," Garratt said.

One is a relatively level wind resource year-round. Puget forecasts generating slightly more than 50 average megawatts from Hopkins Ridge over a year, with the lowest month projected at 42 aMW and the second-highest at 59 aMW (a higher month was likely an anomaly, Garratt said).

Hopkins Ridge also has been met by an "extremely receptive" community, Garratt said. He quoted a top RES official as saying he had never experienced such a local "love-fest" in 30-plus years of energy development. The wind project should produce $1.3 million in yearly property tax revenues, and between 15 and 20 permanent jobs, direct and indirect. Columbia County approved a conditional-use permit for the project in mid-December.

Klondike wind farm in north-central Oregon. (Courtesy of PPM Energy)

With 80 1.8-MW-capacity Vestas turbines, Hopkins Ridge would occupy small portions of 11,000 acres of wheat fields about 15 miles northeast of Dayton. Wind-generated electrons would flow to BPA's transmission system, interconnecting with the 115-kilovolt North Lewiston-Walla Walla line. Puget doesn't intend to use Bonneville's firming and shaping services for wind, at least initially, Garratt said. "We would essentially be integrating on an hourly basis, simply through the transmission system, and on a day-ahead basis, use our own resources to provide that firming." As for imbalance charges levied on unscheduled power, "We've satisifed ourselves that that cost is a manageable cost, especially with the forecasting technology that exists for these projects, which is improving all the time."

Puget wants to conclude final agreements with RES by the first quarter of 2005. The utility would acquire the development assets, and then contract with the company for wind farm construction, Garratt said. If the planned timetable holds, a nine-month building schedule would get the project commercially operating by year-end 2005, in time to qualify for the 1.8 cents per kilowatt-hour federal wind PTC.

Garratt noted that Hopkins Ridge and Wild Horse were the two least-cost resources identified in Puget's solicitation. "These things didn't win because they're renewables ... You could pretty much throw the rest of the stuff out and they still would have won on economics." Wind projects proposed to Puget showed 20-year levelized costs in the range of 4.5 cents/KWh to 6.5 cents/KWh, factoring in the PTC and integration expenses, and the selected ventures were "obviously in the lower portion" of that band, he said.

Puget is still evaluating the third wind project on its short-list, the proposed 180-MW Desert Claim Wind Power Project, also in Kittitas County.

Klondike II Wind Farm/PPM Energy/Portland General Electric

Portland-based PPM Energy announced in October its plans to build the 75-MW-capacity Klondike II wind project in north-central Oregon. Now it has a power buyer: Portland General Electric.

The investor-owned utility will purchase all the energy spun out by Klondike II, under a 30-year agreement made public Dec. 9.

This represents PGE's largest wind energy deal--it also purchases energy from the 24.9-MW Vansycle Ridge Wind Farm in northeastern Oregon.

And, it fulfills some of the 200-MW renewables target set in PGE's current IRP.

"We are pleased to be delivering more renewable energy to our customers at an affordable price and we trust PPM Energy's record as a reliable and responsible power supplier," said Jim Lobdell, PGE's power operations/resource strategy vice president, in a news release. "Increasing supply diversity and adding more renewable energy to our supply portfolio were two of the goals in our Integrated Resource Plan."

PGE spokesman Scott Simms described Klondike II as a "competitively priced" resource fairly close to the utility's service territory. He also touted PPM's firming, shaping and delivery services for Klondike II, which he said will "really help solidify that [intermittent wind] power into blocks and make it easier to integrate with the rest of our power supply portfolio."

PPM spokeswoman Jan Johnson said PPM utility customers want reliability, and her company's wind integration services "customize the product to make sure it fits the customers' needs." As for the lengthy three-decade sale (PPM's longest), Johnson said customers are interested in stable contracts for long durations, and fuel-free wind power offers more price predictability than fossil-fueled resources.

Long-range power buys are appealing to PGE as an alternative to short-term market purchases, especially since the 2000-2001 energy crisis, Simms said.

He also noted the federal PTC extension was essential for Portland General to strike a deal for Klondike II.

PPM's 24-MW-capacity Klondike wind farm began operating in late 2001, about five miles east of Wasco. BPA buys the output.

For Klondike II, PPM plans to install 50 General Electric 1.5-MW-capacity turbines (the same size used in the 16-turbine first phase) and upgrade a substation. The firm expects to take advantage of some of the initial wind farm's human and physical infrastructure, Johnson said.

She described the existing Klondike as "a magnificent wind power plant in every imaginable way," from its "extremely" good energy production in a "modest" wind resource area to its support from the local community. A new Renewable Northwest Project report found that Klondike contributed an additional 10 percent to Sherman County's overall tax revenues in 2002-2003, and will pump an expected $250,000 into county coffers each year for the next two to three decades, funding a variety of public services. Meanwhile, farmers get annual royalties of $2,000 to $4,000 for each turbine on their land, and other Oregon businesses have benefited from related services, such as surveying, road-building and concrete supply.

Johnson said PPM expects Klondike II to begin commercial operation by year-end 2005, in time to qualify for the PTC.

PGE, meanwhile, remains in the market for another 125 MW of renewables, for which it is "still evaluating options," Simms said.

Columbia Energy Partners/Umatilla Tribe

Another proposed wind energy project in north-central Oregon, this one west of Arlington, is progressing toward development by Columbia Energy Partners and a newly announced partner: the Confederated Tribes of the Umatilla Indian Reservation.

This wind proposal is on PacifiCorp's shortlist in its solicitation for up to 1,100 MW of renewables, CEP president Chris Crowley told Con.WEB Dec. 20. Beyond the shortlist, the investor-owned utility has made no public announcements of any renewables decisions as of Dec. 21.

A Dec. 2 news release brought word that the Umatillas will invest in the planned 104-MW-capacity wind farm and become an equity owner.

If the project is built, the Umatillas would be the first tribe with a major role in a completed Northwest wind-energy project.

Umatilla communications director/deputy executive director Debra Croswell told Con.WEB Crowley contacted the tribe about participating in the Arlington wind farm. The Umatillas have an emerging energy interest, as partners in the proposed natural gas-fired Wanapa Energy Center near Umatilla. The tribe also is interested in "other kinds of energy that would help relieve some of the pressure on hydropower, and that stems, of course, from our interest in salmon recovery," she said.

The tribe is open to bringing wind power to its reservation, and/or selling it elsewhere, Croswell said. She declined to share detail's on the tribe's financial role in the planned $130 million wind project, other than to say it represents "a considerable investment for us."

A news release quoted tribal treasurer Les Minthorn as expecting higher returns on the wind farm investment, which in turn would generate more money for tribal programs and operations. Also in the news release, tribal executive director Don Sampson said the Umatillas have long advocated power diversity and renewables in the Northwest, and the Arlington wind project promises economic, environmental and tribal benefits.

The 104-MW wind farm would go up on private grazing land in Gilliam County; the county approved a conditional-use permit in February.

CEP plans to erect 63 turbines of 1.65-MW-capacity apiece, according to the company's Web site. The project would interconnect to the BPA system; Crowley said five sets of Bonneville transmission lines cross the project site, and a Bonneville substation is less than three miles away.

He described the proposed wind farm as "just about invisible from any inhabited location," and Gilliam County as "an economically distressed community that would really welcome the economic diversification from renewable energy this could provide."

Crowley said his company has had ongoing talks with PacifiCorp for "quite some time" about a power purchase, and also is working on financing that would "take full benefit" of the PTC. He expects the wind farm to begin producing electricity in 2005, which would assure PTC eligibility.--Mark Ohrenschall

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Major Change

IPUC Decision Emphasizes Predictable Energy
Deliveries from Small-Scale Renewables Producers

A split Idaho Public Utilities Commission ruling favoring Idaho Power's approach for buying electricity from small renewable energy producers represents a major change in the way these federally mandated contracts are handled in the Gem State.

The Nov. 22 IPUC ruling in a case pitting geothermal and wind developers against Idaho Power puts energy delivery predictability center stage. It institutes a requirement that energy output from qualifying facilities under the federal Public Utility Regulatory Policies Act falls within a specified contract range, or payments will be lowered.

Idaho Power testified earlier this year that this relatively new approach is needed to "improve the ... predictability of QF energy deliveries because conditions have materially changed"--an assertion the IPUC ruling embraces.

Commissioners Paul Kjellander and Dennis Hansen said it was time to move away from current practice, in which "there is no reciprocal QF requirement other than committing to provide the utility with any energy actually produced, no obligation to deliver estimated amounts."

Instead, the commissioners said they believe "a different approach is now in the public interest for a new generation of QFs. The changes in the electric industry and the constraints, challenges and opportunities now faced by Idaho Power indicate to this Commission that the QF resource portfolio of the [utility] must be managed or administered more efficiently."

An Idaho Power spokesman praised the order, while an official of US Geothermal--which had contested the investor-owned utility's QF contract proposal--expressed hope of reaching accord with the utility under terms of the IPUC decision. "This is a major step forward in our signing a power purchase agreement," said US Geothermal chief operating officer Doug Glaspey.

Two small wind developers in the case, and some other entities not including US Geothermal or Idaho Power, have petitioned the IPUC to reconsider its decision.

QF Complaints

The late November ruling settled complaints brought by three QFs who said the "Cogeneration Small Power Producer" contracts Idaho Power offered them didn't comply with PURPA, which requires utilities to buy power from QFs at rates and conditions set by state commissions.

Idaho limits QF power output eligible for avoided-cost PURPA rates to 10 megawatts or less. QF power above this 10-MW cap must be priced with a specific cost model to determine a rate the utility, the developer and customers find reasonable, as described in a 1996 IPUC order.

US Geothermal, developer of the proposed Raft River geothermal power plant in southeastern Idaho's Cassia County, filed the initial complaint in March. The company alleged as "unjust, unreasonable and contrary to law" Idaho Power's intent to only buy up to 10 MW hourly at posted rates, to penalize energy outputs above or below a specified range, and to put in a contract termination provision should Idaho enact retail electric restructuring and the utility's US Geothermal costs become unrecoverable in rates.

US Geothermal was joined in April by a similar complaint filed by small wind-project developers Bob Lewandowski and Mark Schroeder. IPUC consolidated these cases in June.

QF Performance Provisions, Avoided Cost Eligibility

At the heart of the QF arguments lay the definition of the 10-MW cap for posted rates, and the Idaho Power performance band proposal that, in certain circumstances, would require payments by the developer to the utility, or lowered rates for generating less than 90 percent or more than 110 percent of estimated output.

Idaho Power proposed the performance provision to get more firm, predictable and reliable power from QFs, according to the ruling. The IOU said this is warranted because wholesale firm purchases from the market are now acceptable to meet resource needs and hedge risks; it faces capacity and transmission constraints; and the growth of intermittent renewables merit a new PURPA contracting approach.

QF representatives argued, among other points, that PURPA doesn't provide for payments for non-produced power, and that QFs already only get paid for energy deliveries--"the ultimate incentive for reliable and continuous production," the ruling paraphrased.

Commissioners Kjellander and Hansen backed a "90 percent/110 percent" performance band, but lessened the severity of potential penalties for generation outside the 20-percent-wide strip; when that happens, QFs will receive the lesser of 85 percent of market price or the contract rate. They said performance ranges are necessary because both parties to a contract have "reciprocal" and "enforceable" obligations, so a PURPA contract is "not just a lock-in of avoided cost rates but is also an obligation to deliver." More-than-expected QF power also affects the utility, the commissioners noted, and "[I]f unplanned for and not easily integrated the energy may ... have to be sold in the surplus market or other more economic resources of the [utility] backed down."

This ruling is workable for small-scale renewables producers with fairly predictable output, such as US Geothermal, IPUC staffer Rick Sterling told Con.WEB. They'll get the advantageous avoided-cost PURPA rates from Idaho Power. However, he said, "It'll make it very difficult, probably, for projects that produce on an intermittent basis and have no ability to accurately forecast on a monthly basis their generation." This would most likely apply to some small wind projects, he believes.

In her dissenting opinion, commissioner Marsha Smith "strongly" opposed a performance band provision in the QF contracts. "It is my belief that project developers that sign PURPA contracts have a legally enforceable obligation," she wrote. "The incentive for them is to provide all the power they can. They need to be paid to stay in operation and if they do not produce, they do not get paid. The banding proposal would operate as a penalty, not an incentive."

The majority decision also sharpened the 10-MW limit on QF eligibility for avoided-cost rates. Idaho Power wanted to define the 10-MW threshold based on an hourly reckoning--10 megawatt-hours--while US Geothermal wanted it defined annually because the planned output from its Raft River air-cooled, binary-cycle power plant would vary from 8 MW in summer to 12 MW in winter as a result of temperature variations and in-house loads. The company said it couldn't deliver close to an average 10 MW on the hourly schedule.

Kjellander and Hansen approved the 10-MW cap figured over one month. QF developers also must shows that under average design conditions, their projects will produce no more than 10 average megawatts in any given month.

In her dissenting opinion, Smith wrote that US Geothermal should get avoided-cost rates "as a project designed and capable of generating at 10 aMW under normal conditions. Idaho Power is protected by US Geothermal-proposed contractual provisions that provide a maximum monthly capacity amount and no obligation to purchase excess deliveries. This is nothing more than the status quo that has been available to all other legitimate resources."

Reactions to Ruling

Idaho Power was generally pleased with the IPUC order. "It looks like a pretty good order to us," Idaho Power spokesman Russ Jones told Con.WEB. He noted the utility sought another provision allowing it to end PURPA contracts if retail restucturing in the state leads to less-than-full cost recovery for QF payments. But all three commissioners nixed this proposal; all QF contracts are subject to IPUC approval, and the commission "has always provided Idaho Power with the [cost recovery] assurance it requested."

Doug Glaspey, chief operating officer of US Geothermal, put a pragmatic spin on the ruling. "We hope, and desire, to sit down with Idaho Power and come to an agreement," he said. "It'll depend on the reasonableness of both companies."

He said that new IPUC constraints on QF contracts wouldn't hamper project financing. "We can operate within the [performance] band efficiently," he said. "We're not sure this is a provision under PURPA, but we will work with Idaho Power and the commission to negotiate a contract."

In a Dec. 13 news release, US Geothermal also cited a recent commission order raising the rates for Idaho Power QFs becoming operational in 2006, as the company plans for Raft River. The levelized, 20-year term is now 6.09 cents per kilowat-hour, up from 5.61 cents/KWh. Glaspey described this as "a real bonus for the project."

Lewandowski and Schroeder petitioned the IPUC for reconsideration of its order, and specifically the performance band provision. Among their arguments, they said renewables production is dependent on weather, which is beyond the control of developers, and that the performance band is unreasonable. They suggested project availability factors, not energy production, as the basis for assessing any penalties.--Rick Adair and Mark Ohrenschall

More Information:

• Idaho Public Utilities Commission cases (look for IPC-E-04-08)

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Steamed Up

BPA Planned Geothermal Power Purchase
Muddled by Contractual Dispute

A contractual dispute has further muddled Bonneville Power Administration's long-planned energy purchase from a proposed Northern California geothermal plant, which has already been stalled by another legal challenge.

But despite these ongoing conflicts, the developer of the Fourmile Hill Geothermal Project intends to keep pursuing this controversial energy resource that could be the first geothermal plant directly serving the Pacific Northwest.

Four years ago, BPA announced it would buy the output from the planned 49.9-megawatt-capacity Fourmile Hill, at a levelized cost of about 5.7 cents per kilowatt-hour over 20 years. However, under the contractual terms BPA could opt out if developer Calpine could not demonstrate a commercially viable geothermal resource by year-end 2003.

Calpine has conducted exploratory drilling that turned up promising results, but has yet to prove Fourmile Hill's geothermal prospects.

"We have not terminated the contract, but we did file an arbitration to determine whether Calpine should have been excused from providing the resource report or not," BPA spokesman Bill Murlin told Con.WEB Nov. 30. This private arbitration process had not yet started, he said the next day.

Calpine spokesman Kent Robertson declined comment on the BPA contractual issue.

He said his company didn't further explore Fourmile Hill in 2004 because it wanted to focus on defending a federal lawsuit brought by the Pit River Tribe and two other groups, which contend Fourmile Hill's permitting approval by federal agencies violates numerous federal laws as well as trust obligations. These plaintiffs consider the geothermal proposal an unwanted intrusion on a relatively remote and natural setting, jeopardizing Indian spiritual practices and local environmental qualities.

A California federal district court judge ruled decisively in favor of the federal agencies and Calpine in a February decision. The case is now on appeal, Robertson said.

Fourmile Hill: Long, Sputtering History

The Fourmile Hill geothermal site--located about 30 miles from the Oregon border, in the Medicine Lake Highlands--has a long and sputtering history.

It is part of the Glass Mountain Known Geothermal Resource Area, which Calpine's Web site describes as "the most promising undeveloped geothermal resource in the Western United States." It could produce up to 500 MW, according to the February federal court ruling.

The federal Bureau of Land Management leased two parcels in the Glass Mountain KGRA in 1988. Calpine obtained operating rights in 1994 and got the lease assignments in 1996, according to the court. In 2000 Calpine acquired the other major leaseholder in the KGRA, CalEnergy, which had planned a nearby but separate geothermal project known as Telephone Flat.

At the time BPA announced its power-purchase agreement (see Con.WEB, Dec. 21, 2000), Fourmile Hill had gained approvals from local, state and federal agencies, after environmental reviews and with various mitigation and monitoring conditions. BLM and the U.S. Forest Service issued their endorsements in May 2000.

But the proposal to generate power from subterranean hot water has long generated hostility from some Indians, environmental groups and nearby residents. One opposition group headlined a press release: "Geothermal Industrial Nightmare Threatens Medicine Lake."

The Pit River Tribe administratively appealed the project's approval by BLM and the Forest Service--unsuccessfully--and a civil suit was subsequently filed in U.S. District Court in Sacramento.

The Pit River Tribe, Native Coalition for Medicine Lake Highlands and Mount Shasta Bioregional Ecology Center allege that Fourmile Hill's final environmental impact statement was insufficient, in failing to compare harmful impacts on Indian spiritual practices with the relatively modest power production. The plaintiffs also claim violations of numerous federal laws, along with the federal government's trust obligations to Indians.

In a Feb. 13, 2004 decision, U.S. District Judge David Levi sided wholly with defendants including BLM, Forest Service, Department of Interior and Calpine. He found the Fourmile Hill final EIS adequate under the National Environmental Policy Act. "An EIS need only be sufficient to foster 'both informed decision making and informed public participation,'" Levi wrote. "The 700-page Fourmile Hill FEIS comprehensively discusses all of the impacts from the project, including a significant discussion of its impact on the local Indians."

Levi also ruled against the plaintiffs on other legal issues involving historic preservation requirements, geothermal leasing extensions, BLM's lifting of a moratorium on further geothermal development in the area, forest management and Indian trust obligations. On the latter, Levi wrote, "Because this case does not involve tribal property, the federal agencies' duty to the Tribe is to follow all applicable statutes. As discussed earlier, the agencies did not violate any statutes during the approval process for Fourmile Hill."

Calpine's Robertson said Fourmile Hill has survived all formal challenges to date, and the company is "optimistic" this trend will continue. Calpine also is "seeking a dialogue with the Pit River Tribe to address their concerns." Pit River officials could not be reached for comment.

As for the contract dispute with BPA, Robertson declined comment.

Some geothermal resource exploration has been conducted at the Fourmile Hill site, which lies on the flank of a volcano basin containing Medicine Lake. An independent consultant found "a very high likelihood of a geothermal reservoir capable of producing steam to fuel this power plant for the length of the contract," former BPA renewables official George Darr told Con.WEB in late 2000. "That gave us some comfort."

Calpine's exploratory drilling at Fourmile Hill in summer 2002 yielded "positive results," Robertson told Con.WEB later that year. But the company subsequently stopped major efforts to prove out the prospect, and has yet to give BPA the requisite demonstration of commercial viability.

"We revisit our position on [Fourmile Hill] regularly," said Robertson. "Right now, the timetable is really being determined by the courts."

He acknowledged little chance the project would start operating by year-end 2005, in time to take advantage of the new federal production tax credit for geothermal (see Con.WEB, Nov. 30, 2004). The PTC clearly benefits geothermal, he said, but, "It doesn't address the legal challenges," nor the initial development or construction costs.--Mark Ohrenschall

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Value Proposition

Buying Green Power Can Make Good
Business Sense, Conference Speakers Declare

Buying green power can be a wise business choice as well as a good deed.

The potential benefits to an enterprise can include green image-making, hedging future electric price risks, furthering renewables market development, contributing to corporate environmental goals and generally improving business.

"Buying renewable energy is not a charitable contribution," said energy consultant Kevin Hagen, speaking to the "Better Business Through Green Power Conference" Oct. 19 at Qwest Field & Events Center in Seattle. "Purchasing renewable energy is a business procurement decision."

Yet as Hagen and other conference speakers discussed, green power naturally raises questions for businesses, particularly cost, and also tangibility.

A business considering green power or renewable energy should examine a host of considerations, such as company values and strategies, and the specifics of potential suppliers and products. Several conference speakers mentioned the "value proposition."

Green power tales were shared by representatives of CH2M Hill, Mount Hood Meadows Ski Resort, Bainbridge Graduate Institute and a Seattle-area fire station.

The conference also featured some contextual remarks on green power, notably on the Northwest's promise as a clean energy haven, and the growth of wind power.

Though growing, the retail market for commercial green power remains quite small. In the Pacific Northwest, the percentage of commercial customers participating in 35 available utility green power programs was 0.17 percent as of 2003, according to a mid-2003 Renewable Northwest Project report.

Green Powered Businesses

Several stories were shared Oct. 19 by people whose organizations have bought green power. They illuminated rationales and advantages, along with issues and concerns.

CH2M Hill, an international consulting engineering company, is buying green power equal to about 10 percent of power consumption in its Northwest offices. The firm's environmental values are a "very strong driver" for purchasing green power, said sustainable development program manager Andrea Ramage.

Long-range business development is a factor, too. "We want to lead our industry in promoting sustainable technology. The renewable energy market is a big part of that," she said.

CH2M Hill also appreciates the "good press" received from buying green power, she said.

Ramage also cited the "big picture" benefits of green power such as economic development, energy independence, power system diversity and a hedge against climate change.

But Ramage also noted some barriers, prominently mentioning cost. CH2M Hill bought green power for a three-year term coinciding with a sluggish economy. "I'm not sure we would have invested in green power last year or the year before if the contract was not in place," she acknowledged. The company also experienced a "hassle" in green power arrangements with a landlord.

Mount Hood Meadows Ski Resort has bought BEF green tags equivalent to powering two chairlifts, or about 8 percent of the area's total energy consumption, reported vice president/general manager Dave Riley.

He described this as "a good ski business strategy. We need snow to survive probably more than any business out there. We are concerned about global warming as an industry," and its potential to diminish snowpacks.

Riley also emphasized the resort's ability to reach many tens of thousands of environmentally conscious skiers with the green power message, by advertising its purchase and by selling so-called "mini-green tags" to skiers for $2 apiece. "We want to play an active role to reduce the production of greenhouse gases and to leverage the critical mass of people who visit the resort," he said. Riley is seeking to spread green power to others in his industry; 11 Northwest resorts have agreed to participate in green power programs this season, according to a mid-December BEF news release.

Bainbridge Graduate Institute, which offers a master's degree program focusing on socially and environmentally responsible business, gains from its green power in a number of ways, co-founder Gifford Pinchot III told the conference. The publicity leads to new students, a 10-times return on investment, by Pinchot's reckoning; staff and volunteers are inspired (20 times ROI); donors are inspired (30 times ROI); students are inspired (50 times ROI); and, finally, green power is a measure of integrity, which Pinchot deemed priceless.

He believes the biggest challenge in selling green power (an intangible product) is personalizing the benefits, as organic food has with its health appeal. If green products are comparably priced to non-green items, "A lot of people will buy it," he said, but added, "I don't think green electrons are in that category yet."

For the Issaquah Highlands Fire Station east of Seattle, acquiring BEF green tags equal to 50 percent of total power consumption helped the facility earn enough additional credits to qualify for the Leadership in Energy and Environmental Design (LEED) silver green building standard, said project consultant Amee Quiriconi. This was especially useful, she indicated, because at the time the station design was 90-percent done, greatly limiting ways to rack up more LEED points.

Green Power Varieties

Green power comes in several varieties, Hagen, principal of Shuksan Energy Consulting, told conferees. "There are many really great renewable energy options we have in the Northwest and around the country," he said--and all entail tradeoffs.

One possibility is on-site generation, through solar electricity or hot water, various generating technologies (such as microturbines or fuel cells) and combined heat/power. This can give companies a hedge against future energy prices and can fit into specific power needs, with reliability and marketing benefits. But while the long-term paybacks for self-generation are good, Hagen said capital costs can pose a problem, as can accounting issues. The viability of this alternative depends largely on the specific site and facility.

Green power contracts from a utility or other supplier are another choice. Hagen urged attention to the renewable energy sources for this type of purchase.

Renewable energy certificates (also known as green tags) basically separate environmental attributes of renewables from the electricity, and represent "a revolution in the renewable energy industry, a really powerful tool," with an expanding market, Hagen said. He touted the flexibility and leveraging opportunities of green tags for businesses, but also noted their inevitable price premium and the difficulty in describing them in simple terms.

A fourth alternative for a business is investing in a renewable project elsewhere, such as a wind farm or a landfill gas-to-energy plant. This provides asset-ownership and social/environmental benefits, but also involves questions of capital cost and complexity, Hagen said.

Businesses also can donate money to utility green power programs, but Hagen believes this "charitable contribution" is best suited for residential customers.

In looking at green power, he encouraged businesspeople to consider their company goals and objectives, understand the details of potential options (including benefits and risks), and arrive at a "value proposition."

(Courtesy of Renewable Northwest Project)

Sacramento Municipal Utility District has experienced much success in attracting commercial customers to its Greenergy green power program, with more than 1,000 accounts and enrollment growth of 3,200 percent in the last two years, said SMUD senior product and service coordinator Jim Burke.

He listed 10 main "deal breakers" for commercial green power, starting with cost/benefit justification and also including the challenges inherent with an emerging product, diffuse corporate decision-making and choosing the appropriate product.

Among "deal makers," he urged companies to connect different departments and their budgets for a green power purchase, and to find a green power provider offering different products and non-energy solutions.

From a Northwest angle, Noreen King of Belo Marketing Solutions outlined the Western Washington green power campaign from earlier this year (see Con.WEB, Nov. 30, 2004 for more details on this campaign).

Green Power Opportunity, Growth

Two conference speakers centered their remarks on the larger picture of renewable energy and green power, emphasizing opportunities and growth.

K.C. Golden, policy director of Climate Solutions, sees the world "approaching a moment in which we will fundamentally turn the corner from a fossil fuel energy path to a clean, renewable energy future."

This historic shift is driven by three main factors, he said. One is increasing momentum for the pursuit of U.S. energy independence. Another is rising and volatile fossil-fueled energy prices, spurring advances in clean energy technologies. And a third is climate change, for which one of his slides captioned: "Environmental necessity drives economic opportunity."

The Northwest is "exceptionally qualified" to develop into "a global center of clean energy," he said, with its extensive history of energy efficiency and renewable energy (the hydropower system), abundant opportunities for new renewables and more energy savings, technological expertise, wealth, brainpower and environmental idealism. But, Golden said, this region is "not uniquely qualified," and other states and countries (he mentioned Germany and Japan) are also in the running.

Moving toward clean energy is "the defining challenge of our generation," he concluded.

Wind energy is a major renewables growth industry, and one person very familiar with it is Terry Hudgens, president and chief executive officer of Portland-based PPM Energy, which controls more than 800 megawatts of wind capacity and plans to build another 1,000 MW in 2005.

He sketched the declining costs of wind--now as low as 3 cents per kilowatt-hour to 4 cents KWh with the federal production tax credit, down from 20 cents/KWh two decades ago--and the "very, very high and very, very volatile" prices of oil and natural gas. Even with transmission and siting limitations, about 100,000 MW of additional wind power are economically developable in the U.S., Hudgens said. This renewable resource promises a degree of energy independence along with rural economic development (particularly with the tax base), though it still faces obstacles such as costs to bring to market.

"In conclusion, there's a lot of opportunity," Hudgens said. "I've love to see the Northwest take a strong leadership position" on wind resources and technology manufacturing.--Mark Ohrenschall

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News Bytes

BPA Wins National Energy Efficiency Award;
Northwest's Biggest Solar PV System Installed

Bonneville Power Administration has received a prominent national award as a "Star of Energy Efficiency" recognized by the Alliance to Save Energy.

BPA was officially honored at a Dec. 9 dinner event in Washington, D.C., at which administrator Steve Wright accepted the award for the Northwest wholesale power marketing agency.

BPA officials learned of the ASE honor about three months ago. At that time, BPA energy efficiency vice president Mike Weedall termed these awards "the Oscars for energy efficiency," and said BPA officials were "extremely giddy" about the honor.

"We're extremely proud to stand up and accept this on behalf of the region" and its many energy efficiency players, Weedall told Con.WEB.

The Natural Resources Defense Council nominated BPA for the award, and said in its nomination that BPA's achievements are "based on a broad portfolio of innovative energy efficiency programs, which began in the 1980s and recently helped overcome the extraordinary challenges of the Western electricity crisis and its aftermath." BPA staff "has teamed with regional stakeholders" and "provided strong leadership when some were questioning whether and how utility-sector energy efficiency investment could continue." NRDC said the agency also "has made giant strides toward full mobilization of efficiency options to solve grid reliability and congestion problems," and listed as the first program in support of the nomination BPA's Non-Wires Solutions venture looking at transmission-building alternatives.

BPA administrator Steve Wright (left) and William Keese of the California Energy Commission. (Courtesy of Alliance to Save Energy)

An ASE news release said BPA has "successfully promoted energy efficiency as a cost-effective energy resource that contributes to grid reliability. BPA's energy-efficiency and conservation programs helped save more than 925 average megawatts from 1980 to 2003--about 25 percent of the region's load growth. BPA also was instrumental in creating the Northwest Energy Efficiency Alliance, the nation's most effective regional energy-efficiency consortium."

Other award-winners were Bank of America, Marriott International and Southern California Edison. Tom Kuhn, president of Edison Electric Institute and an ASE board member; David Garman, a top U.S. Department of Energy official; and former Sen. Charles Percy also were honored with ASE awards.

RENEWABLES/GREEN POWER

• A 172-kilowatt-capacity solar-electric system--reportedly the largest in the Northwest--has been installed at three Pepsi Cola of Klamath Falls facilities. It is projected to annually generate all the power used at the three sites. The biggest installation of the three is a 132-KW building-integrated system atop the company's main office/warehouse. Among the organizations contributing to this project, financially and otherwise, are Energy Trust of Oregon, the Oregon Department of Energy, Pacific Power and Advanced Energy Systems. More information: Energy Trust of Oregon news release.
• Seattle City Light has secured transmission rights for the second half of its 20-year contract for energy from 175 megawatts of capacity from the Stateline Wind Energy Center. More information: Seattle news release.
• Fort Lewis in Washington has agreed to buy 1.3 aMW worth of renewable energy certificates, equal to about 5 percent of the base's power needs. BPA is supplying the certificates--sourced from Washington and Oregon wind farms--to the Army base's serving utility, Tacoma Power.
• Fred Hutchinson Cancer Research Center in Seattle will buy 867 megawatt-hours annually of renewable energy certificates from the Puyallup Landfill Energy Recovery Plant, for its Public Health Sciences Building. These certificates--sold in an agreement with Seattle City Light--equal about 25 percent of the power needs for the facility.
• Two new 10-KW-capacity wind turbines were dedicated in October near Goldendale, WA, by two local landowners who belong to Our Wind Co-op, which is working to install small-scale wind projects in the rural Northwest. Meanwhile, Puget Sound Energy has agreed to buy all green tags from Our Wind Co-op wind projects in Washington and Oregon for three years, while Seattle City Light is buying green tags from Bonneville Environmental Foundation to support Our Wind Co-op.

UTILITY PROGRAMS

• Four large Western Washington utilities--Seattle City Light, Puget Sound Energy, Tacoma Power and Snohomish County PUD--are providing cash rebates of $30 to $200 to buyers of qualifying commercial energy-efficient refrigerators and freezers, according to the Northwest Public Power Association Bulletin. Snohomish, meanwhile, has found huge interest in its refrigerator recycling program; nearly 800 customers arranged for the PUD to pick up their old fridges on the program's first day, according to the Seattle Daily Journal of Commerce. The PUD pays $35 for each recycled fridge.
• Idaho Power is offering free duct-sealing services for manufactured homes sited in rural communities, a utility news release reported in November.

GREEN BUILDING

• Recreational Equipment Inc.'s Portland store has become the nation's first retail outlet to earn a Leadership in Energy and Environmental Design (LEED) gold rating for commercial interiors.
• The U.S. Green Building Council has announced two new LEED rating systems, one for existing buildings, the other for commercial interiors.

AWARDS

• Two Washington groups were honored in the recently announced 2004 Federal Energy and Water Management Awards. Energy Efficiency/Energy Program Management Awards to Small Groups went to Phil Beste, Jerry Gray and Mark Halvorsen, U.S. Department of the Navy, Naval Undersea Warfare Center Division Keyport; and, Don Bader, Rubin Carter, Robert Sheldon, Rhonda Stewart and Jim Sura, U.S. Department of the Navy, Puget Sound Naval Shipyard & Intermediate Maintenance Facility, in Bremerton.
• A Northwest company, individual and marketing campaign were honored in the 2004 Green Power Leadership Awards presented in October in New York. PPM Energy won the Renewable Energy Technology Supplier award; Rob Harmon of Bonneville Environmental Foundation earned the Green Power Pioneer Award; and the Western Washington Green Power Campaign received the Green Power Beacon Award.
• Seattle-based Mithun has earned the Local/Regional Leadership Award from the U.S. Green Building Council.
• Several people in Idaho and Portland have been recognized with BetterBricks awards for 2004: Sue Seifert, Idaho Energy Division, Idaho Advocate Award; Doug Cooper, McKibben + Cooper Architects, Idaho Architecture Award; Foad Roghani, Susan Camille, Beckman Roghani, Idaho Developer Award; Bob Tikker, Tikker Engineering, Idaho Engineer Award; Tim Hansen, Alloway Lighting, Idaho Professional Services Award; Jerry Yudelson, Interface Engineering, and Rob Bennett, city of Portland Office of Sustainable Development, Portland Advocate Award; Rob Curry, Yost Grube Hall Architecture, Portland Architect Award; Jim Winkler, Winkler Development Corp., Portland Developer Award; Paul Schwer, PAE Consulting Engineers, Portland Engineer Award; Mike Faha, GreenWorks, Portland Professional Services Award.
• Seattle-based Starbucks Coffee Co. has become the first EnviroStars Recognized Leader, for taking major steps to reduce its environmental footprint in the Puget Sound region and beyond. Those steps include lowering resource consumption, including electricity, in its retail stores.
• The BetterBricks Daylighting Lab and Fairchild Air Force Base were among seven winners of the 2004 Washington Governor's Award for Pollution Prevention and Sustainable Practices; both were honored for energy conservation and/or renewable energy activities.

ENERGY CODES

• The Washington State Building Code Council has approved a package of revisions to the state's non-residential energy code, including building envelope, mechanical system, lighting controls and prescriptive lighting requirements that bring the code in line with ASHRAE/IESNA Standard 90.1-2001, and that should generate additional energy savings in new commercial buildings. These changes are effective July 1, 2005. More information: Washington State Building Code Council.

STATE GOVERNMENT

• Washington, Oregon and California governors in November agreed on 36 recommendations to help reduce greenhouse gas emissions, including efforts to boost use of renewable energy, adopt efficiency standards for certain products and pursue more energy efficiencies in state building code updates. State agencies were directed to continue the West Coast Governors' Global Warming Initiative in 2005.

FEDERAL GOVERNMENT

• Consensus agreement has been reached on proposed federal equipment efficiency standards for commercial air conditioners and heat pumps, which would raise the Energy Efficiency Ratio (EER) of the most common units from 8.9 to 11.2 as of 2010, according to GreenBiz.com. These proposed standards, negotiated by manufacturers and energy efficiency supporters, have gone to the U.S. Department of Energy and Congress; some elements can be adopted by DOE, while others require congressional action.
• The U.S. Department of Agriculture has awarded $22.8 million to renewable energy and energy efficiency projects, under provisions of the 2002 Farm Bill. Some recipients are in the Northwest.

RESIDENTIAL

• Idaho Energy Division now offers low-interest loans to homeowners who convert electric heating systems to high efficiency natural gas or propane heating sources.
• A residential energy efficiency blog has been established by the Residential Energy Services Network, at www.natresnet.org/resblog.htm

MISCELLANEOUS

• Five Montana State University students had winning entries in the Leading Edge Student Design Competition 2003-04 Desert Challenge, in which architecture students incorporate energy efficiency and sustainability into hypothetical designs. MSU students Maisie Sulser, Shannon Peterson, Shawn Ronning, Eric Abrams and Marissa Hatcher earned first-place or second-place honors in their respective divisions, among 226 total entries from 82 universities.
• A southeast Portland farm dating to 1887 has a 6.6-KW-capacity solar photovoltaic system, with funding from Portland General Electric and Energy Trust of Oregon. Zenger Farm is evolving from a dairy farm to a learning center for sustainable practices, including green buidling and renewables.
• Advanced Buildings Benefits Guide has been published by Washington-based New Buildings Institute and the Energy Center of Wisconsin.--Mark Ohrenschall (Cyrus Noë also contributed to this article)

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