CWEB.093/September.29.2003
| Correction Renewable Northwest Project's utility green power survey--reported in the Aug. 28 issue of Con.WEB--contained some inaccurate information about Seattle City Light's green power program. City Light's corrected information slightly changes regionwide figures in the original survey; a revised version is available on the RNP Web site, at http://www.rnp.org/Resources_PC4_report_v2.pdf. |
Oregon public-purposes funding for energy conservation and renewable energy has survived intact the budget crisis-ridden 2003 state legislative session.
Oregon lawmakers adjourned in late August after considering, but ultimately rejecting, a proposed shifting of public-purposes dollars into the state's general fund. Another legislative idea would have required Oregon Office (now Department) of Energy approval for payments to the Energy Trust of Oregon, which administers most of the state's conservation/renewables public-purposes spending. It included a provision for OOE to determine whether the Trust should continue its role. That bill narrowly failed in the House of Representatives shortly before legislators called it quits.
"We'll take the fact that the last work on public purposes for this session was a defeated bill, but I don't think that necessarily means this issue is off the table for the next session" in 2005, said Jeff Bissonnette of the Fair and Clean Energy Coalition, a leading public-purposes funding supporter.
The fight over public-purposes funding came as Oregon lawmakers grappled with a multibillion-dollar budget shortfall. Bissonnette said anti-tax Republican legislators "were looking for any pot of money that had not yet been raided, funded or otherwise yanked onto the table to pay for ... keeping the state's doors open."
However, the status quo was bolstered by legal analysis that public-purposes funding as constituted couldn't be tapped for the state's general fund, as it is collected only from Portland General Electric and PacifiCorp customers. Bissonnette also praised some "very supportive legislators" who view public-purposes programs as a means to lower energy bills and create jobs.
Separately, Oregon lawmakers and Gov. Ted Kulongoski approved a bill easing the way for public agencies to pursue energy savings performance contracting.
Budget Backdrop
Oregon's biennial legislative session unfolded against the backdrop of a gaping state general fund budget shortfall--initially about $1.7 billion for the 2001-2003 biennium, and later another $1.2 billion for the 2003-2005 budget period, according to Ken Rocco of the Legislative Fiscal Office. Lawmakers raised taxes, reduced state spending and made changes to the Public Employees Retirement System, among actions to address the fiscal problems, according to a summary.
"All throughout the session, the public-purposes funding was always ... on lists for redirection into general purpose stuff," Bissonnette said.
That money, equivalent to 3 percent of revenues collected from PGE and PacifiCorp customers around the state, generates about $50 million annually, or about $100 million over the state's two-year budgeting cycle. "When you're dealing with a billion to $2 billion shortfall, a hundred million [dollars] doesn't take you all the way there," said Bissonnette, but "it can be a sizable piece of the puzzle if that's what you want to do."
Public-Purposes Proposals
One proposed piece of legislation, House Bill 3528, as introduced would have moved public-purposes dollars into the state's general fund, and eliminated them altogether as of January 2008.
The introduced bill stated its purpose to offset lost general fund revenues from state tax credits for pollution control facilities, pollution-eliminating production technologies or processes, energy conservation, alternative energy devices and alternative-fuel-vehicle fueling stations.
But the nature of public-purposes funding, as created in the state's electric industry restructuring, prevents its general use by the state, according to Bissonnette. "It never actually becomes public money. It's ratepayer money managed under the auspices of the [Public Utility Commission]. That money never goes through state coffers," he said. "Beyond that, it's not a tax to be rerouted to the general fund for general purposes. It's not a charge or a tax that's levied on all Oregonians. Only a subset of Oregonians pay the public-purposes charge."
Legislators could alter the structure of public-purposes funding, he said, but that would entail revisiting the restructuring law, creating "an absolute brouhaha of a political fight within the Legislature."
Another proposed bill, House Bill 3170, as initially written would have required OOE approval for payments to the Energy Trust, which administers about three-fourths of the state's total public-purposes dollars. It also would have ended public-purposes funding in January 2005 unless 20 percent of eligible Oregonians had chosen direct access for their electricity supplies (although that provision was later removed). Public purposes as originally approved have a 10-year funding period.
HB 3170 passed the House on a 35-20 vote in May, but died in the Senate.
HB 3528, meanwhile, was considered in House committees in the spring, and resurrected in the summer in a different form--absent the general fund and elimination date provisions, but transferring public-purposes spending oversight to OOE and requiring the state energy agency to determine whether the Trust should continue as administrator. That version was voted down 30-28 by the full House.
Public-purposes funding generated interest as the Legislature engaged in an ongoing debate between raising taxes and cutting spending, according to Bissonnette. The House's Republican majority counts many anti-tax members, he added.
Republican Rep. Rob Patridge, who co-sponsored both HB 3825 and HB 3170, wrote a communication headlined: "Public Purpose Charge-Who Needs It??" He called public-purposes funding "the real sore spot" in electric restructuring, and "nothing more than a tax!" Patridge also criticized the Energy Trust as an expensive new bureaucracy.
"Is this program really necessary?" he wrote. "Shouldn't this 3% charge be returned to customers and let them voluntarily pay for energy efficiency programs through current utility offers? Aren't customers paying enough for their power during this economic crisis? Shouldn't we give them back their 3% rather than let the OPUC and the ETO waste it?" Patridge could not be reached by Con.WEB for further comment.
Although not referring specifically to that missive, Bissonnette decried "a level of misinformation, disinformation and simply being uninformed by a lot of people" in the Legislature on the nature of Oregon's public-purposes funding and what it accomplishes. Many legislators oppose it "for ideological reasons as opposed to sound policy reasons," he said.
An April 2003 report by ECONorthwest found that the Energy Trust's 2002 spending of $19.5 million increased Oregon's economic output by nearly $24 million (compared to PGE/PacifiCorp ratepayers keeping the public-purposes dollars), created 203 new jobs, boosted wages by $7.9 million and led to a small rise in state and local tax revenues.
ECONorthwest forecasts the 2003 Trust budget of $41 million-plus will boost the state's economic output by $36 million, create 327 new jobs and increase total wages by $12 million. By 2007, the report said, cumulative impacts (if present trends continue) from Trust energy-saving programs would amount to $277 million in added economic outputs and 2,741 new jobs.
 |
| (Courtesy of Energy Trust of Oregon) |
An ETO document listed as agency highlights the launching of commercial, residential and industrial energy efficiency programs, maintaining of utility transition programs, and 14 average megawatts of total energy savings from March 2002 through June 2003. The Trust also has initiated ventures in large-scale wind, solar electric, solar water-heating and other renewables, with 2002 commitments for 18.1 aMW. Nearly 200 trade allies are working with the Trust statewide, along with many institutional partners, the document reported.
The non-profit agency collected $55 million from March 2002 through June 2003 and spent about $33 million, the document said.
"There started to be a basic understanding [in the Legislature] of what these funds are doing, actually doing, the work they were supporting," Bissonnette said. Continuing communications on public purposes will be "a top priority of folks involved in the Fair and Clean Energy Coalition" leading up to the 2005 legislative session.
Energy Savings Performance Contracting
Another Oregon energy efficiency-related bill, House Bill 3476, easily passed both the House and Senate, and Kulongoski signed it into law July 8.
HB 3476 is designed to promote in public facilities energy savings performance contracting, which essentially allows efficiency projects to be paid for through energy savings. Specifically, the bill exempts ESPC from competitive bidding requirements and calls for the Attorney General's Office, in consultation with other agencies, to set up model rules and potentially standard contract forms for public agency ESPC.
"There have been a few ESPCs in Oregon before, but the agencies that used them had to go through a fairly long, labor-intensive and quite costly process to get the go-ahead," Bissonnette told Con.WEB in an e-mail.
"These ESPC agreements will save on energy operating costs and modernize building systems to improve comfort and employee productivity," said Stan Price, executive director of the Northwest Energy Efficiency Council, in another e-mail. "All of these benefits accrue to the public sector without the burden of up-front capital costs. The great advantage of ESPC is that energy savings completely pay for the project costs." He praised Bissonnette for his "expert help in navigating this legislation through the twists and turns of the legislative process."--Mark Ohrenschall
More Information:
NorthWestern Corp.'s recent bankruptcy filing won't directly affect energy conservation and renewable energy programs in its Montana service territory, according to utility officials.
NorthWestern Energy will continue to offer energy-saving and renewables initiatives in Montana with Universal System Benefits public-purposes funding, as NorthWestern Corp. reorganizes under Chapter 11 bankruptcy proceedings.
However, NorthWestern Energy's intent to buy power from two proposed Montana wind projects remains problematic. Utility credit issues had already slowed power purchase discussions with Whitehall Wind and WindPark Solutions Arcadia, selected by NorthWestern through a recent solicitation for wind power to help serve default supply customers.
"We're still proceeding with the project, but we need to know what's going to happen, who's going to be the successor to NorthWestern, how to assess the credit quality of the people behind it," said Greg Jaunich, president of Navitas Energy, parent of Whitehall Wind. Minnesota-based Navitas plans a 50-megawatt-capacity wind farm near Whitehall in southwestern Montana.
"We're just waiting for them to shuffle through their bankruptcy," said Bob Quinn, a partner in WindPark Solutions Arcadia, which is proposing a phased wind development ultimately totaling 180-MW capacity in central Montana.
The bankruptcy filing doesn't prevent NorthWestern from signing power purchase agreements, said utility spokeswoman Claudia Rapkoch, although she acknowledged would-be power suppliers have been concerned about the utility's credit.
She also said the wind procurement "hasn't been at the height of priorities" for NorthWestern.
Bankruptcy Filing
NorthWestern Corp. filed for Chapter 11 bankruptcy protection on Sept. 14. This followed unsuccessful efforts to reach an out-of-court restructuring by obtaining more financing, selling non-utility assets and gaining shareholder approval to isssue more stock to help pare its multibillion dollar debt, according to the utility's Web site.
The South Dakota-based corporation--which purchased the former Montana Power Co.'s transmission and distribution business in 2002--said the bankruptcy resulted from "financial challenges primarily stemming from the implementation of a diversification strategy and the significant amount of debt we accrued as a result." NorthWestern's two main money-losing subsidiaries are Blue Dot, which provides HVAC, plumbing and related services, and Expanets, a communications services firm--both of which NorthWestern is trying to sell. But the corporation's $1.76 billion debt is primarily related to its $1.09 billion purchase of Montana Power's utility holdings.
In an open letter to customers, NorthWestern president and chief executive officer Gary Drook said bankruptcy reorganization "should help us to significantly reduce debt, improve our capital structure and ensure the long-term financial health of our core utility operations. We expect no changes to our utility operations in Montana during this restructuring, and you should see no changes in the level of service you receive ... Our Chapter 11 filing does not mean we are going out of business nor are we looking to sell our utility operations," he continued. "The objective of our financial reorganization is to emerge as a financially stable energy company that is focused on serving its customers." (For more details, visit NorthWestern's financial restructuring Web site.)
Universal System Benefits Programs Continue
Since 1999 the investor-owned utility has collected revenues from customers to fund programs under its Universal System Benefits umbrella, established as part of Montana's electric industry restructuring. The restructuring law set USB funding at 2.4 percent of 1995 electric revenues (along with a separate natural gas program). In 2002, NorthWestern collected $8.2 million in electric USB funding for assorted ventures in conservation/market transformation, renewables and low-income energy programs.
USB programs will continue unaffected by the bankruptcy, according to Rapkoch and a letter from NorthWestern's Dennis Lopach to the Montana Public Service Commission and a state legislative interim committee.
The utility is "merely a conduit" for USB dollars, and these monies are not part of the bankruptcy estate, Lopach wrote. Having received bankruptcy court authorization, "NorthWestern will continue to collect USB funds, account for such collection, and pay expenditures to the USB Programs as it has historically done."
There was talk of setting up a separate account for USB dollars, but Lopach described that option as "difficult and not practical," in part because of month-to-month imbalances in USB revenues and spending. In any case, NorthWestern "already maintains a separate, detailed account for all USB funds collected and expenditures made," he wrote.
Proposed Wind Power Purchases
Earlier this year, NorthWestern selected two proposals from a wind power solicitation issued in late December. Whitehall Wind and WindPark Solutions were chosen to supply energy from 75 MW to 100 MW of wind capacity (those amounts according to the Great Falls Tribune) to help serve utility customers who have not chosen other electricity suppliers under restructuring.
However, "credit issues have bogged down the process" of procuring wind energy, NorthWestern power supply executive director Mark Thompson told Con.WEB in late spring. Wind developers were reportedly nervous about signing long-term contracts with a company heading toward bankruptcy.
Now that bankruptcy has arrived, financial concerns remain for potential power suppliers.
"You need a creditworthy entity on the other side of the contract," Jaunich told Con.WEB. Otherwise, "You don't know if you're going to get paid. That's ... the big question." He described his firm as a "very strong company and financially sound. NorthWestern's the one that's financially weak. So it's a problem."
Whitehall Wind plans a 50-MW wind project on a site encompassing reclaimed land at the Golden Sunlight Mine and adjacent U.S. Bureau of Land Management property. "We're not building the project" at the moment, Jaunich said. "We wouldn't make the investment until we know [NorthWestern's financial situation is] being sorted out." Other power buyers are a possibility, he said, but not in the near future.
Jaunich estimated a 2005 construction start, "if we sort out the financial issues" with NorthWestern.
WindPark Solutions, meanwhile, is also awaiting NorthWestern's reorganization. "Then we'll be ready to start negotiations on a power purchase agreement again," said Quinn. Preparations had been in progress to announce a deal, he said, until "the bankruptcy thing came to a head and everything shut down."
WindPark publicly unveiled its project at a January news conference in Helena, according to the Billings Gazette.
"We've been working on it almost three years now," Quinn told Con.WEB. Plans call for a 180-MW-capacity wind farm, built in phases, south of Judith Gap in central Montana's Wheatland County. Quinn said WindPark is in "the final stages of putting together the whole thing," pending the bankruptcy proceedings. NorthWestern is the project's lone potential power purchaser, "at least initially," Quinn said.
Latest Twist in Montana Wind Saga
Bankruptcy is the latest twist in the ongoing saga of Montana's largest utility pursuing wind power.
In mid-2001, Montana Power issued a request for proposals for energy from 150 MW of wind power. Late that year the utility announced its selection of Montana Wind Harness for a power purchase agreement from three separate sites, at price of 3.1 cents per kilowatt-hour over 20 years. However, state regulators in June 2002 decided the utility had not sufficiently explained how it selected Montana Wind Harness, and thus they could not conclude the choice was reasonable. NorthWestern shortly thereafter cancelled its contract with Montana Wind Harness.
In December 2002 the IOU issued another wind RFP, though for an unspecified amount. This process led to the selection of Whitehall Wind and WindPark Solutions.
Meanwhile, Whitehall Wind's appeal of a PSC ruling on a mandatory utility power purchase is pending in Jefferson County District Court, 5th Judicial District. Whitehall claims the 1 cent/KWh rate set by the PSC in December violates federal and state laws governing qualifying facilities under the Public Utility Regulatory Policies Act (PURPA).--Mark Ohrenschall (Steve Ernst and Cassandra Sweet contributed to this story)
More Information:
Puget Sound Energy customers participating in the utility's time-of-use pricing program showed 5-percent average monthly load-shifting away from peak periods and a 1-percent overall reduction in energy use, but the program was not considered cost-effective, according to a final report on the landmark initiative.
The report from PSE and its time-of-use collaborative also reiterated that the vast majority of TOU participants paid slightly higher bills in a 2002 quarterly reporting period than they would have under standard flat rates. Puget subsequently abandoned the program in November 2002, nearly a year ahead of its scheduled end.
Although Washington's largest utility has no immediate plans to revive TOU pricing, Puget official and TOU collaborative member Eric Englert told Con.WEB the program achieved measurable results in changing residential energy consumption, with "very modest price signals" to approximately 300,000 participating customers. He said the program could have proven cost-effective under certain different conditions. And, he said, "Demand response programs are still viable options for utilities, especially in the case [as with Puget] where an automated meter-reading infrastructure is in place."
Despite the peak-shifting and load-reduction numbers, the final TOU report showed that only one of 12 different cost-effective analyses for the program revealed more benefits than costs.
This "confirmed our suspicions and our early information that the program was ultimately not cost-effective for consumers," said Simon ffitch of the Public Counsel Section of the Washington State Attorney General's Office.
TOU Background
Puget launched its time-of-use program in spring 2001, amidst the energy crisis, as a means to shift power use to off-peak periods and lower overall electricity consumption. The investor-owned utility also touted TOU rates as part of the "next generation" of energy conservation, informing and empowering customers on their power use with advanced metering and communications technologies.
Puget later narrowed the price difference between peak and off-peak time blocks to 1.4 cents per kilowatt-hour, reflecting settled-down wholesale energy markets. A $1 monthly administrative fee was instituted for participants.
Some 24,000 customers, nearly 10 percent of total participants, left the program after figures for July-September 2002 showed the average household paid an additional 80 cents per month on TOU rates compared to flat rates, while the average small commercial customer forked over an additional $1.16. About 94 percent of all participants received higher bills.
"The program isn't working the way customers want it to work or the way we want it to work," PSE chief operating officer and senior vice president Gary Swofford told Con.WEB.
TOU Effects
The TOU final report, filed July 1 with the Washington Utilities and Transportation Commission, outlined some of the program's effects.
Puget documented a 1-percent average decline in total monthly energy use by TOU pricing participants, compared to customers who only received TOU information and all other residential customers. The utility also found an overall average 5-percent monthly load shift away from peak times for residential TOU participants.
Puget discovered slightly more load-shifting among TOU participants during winter and in the morning, Englert said--a "pretty useful" finding, in that it matches the utility's system peak.
"Some customers told us they installed energy efficiency measures, some customers curtailed, some may have done some sort of fuel-switching," Englert said, adding that the relative influence of those factors is unknown.
Puget hasn't researched how former TOU customers are using energy after the program's end, he said.
In the final TOU report, Washington Department of Community, Trade and Economic Development's Energy Policy Group took issue with Puget's load-reduction calculation and the persistence of energy savings. Measure installations or ongoing education, training and maintenance are needed to ensure longevity, and these cost money, but Puget assumes up to two-thirds of the savings will last 10 years at no cost, CTED wrote in the report. "This analysis should either indicate zero load reduction or should assign representative costs for the load reductions that have been estimated."
Puget responded that a monthly electric bill is "a highly effective tool for the continuing education requirement necessary to have sustaining conservation and load reductions."
Public Counsel, meanwhile, suggested the program's reported energy savings were influenced by the highly publicized energy crisis. The office added a concern that the lowered differentials between TOU rate blocks would tend to lessen customer response and "may tend to overstate the effect that should be expected from a long-term program."
Puget noted that all customers were exposed to energy crisis news, and that the overall energy consumption numbers for TOU participant numbers were compared to a "statistically valid control group of customers who received information about their TOU usage, but were never charged the TOU rate." However, Puget acknowledged, the difference in average daily consumption between TOU participants and TOU-informed customers was only 0.3 percent.
"It seems clear that TOU customers shifted and reduced their energy use, and for reasons other than weather or widespread general awareness of an 'energy crisis,'" Puget said.
Cost Issues
Collaborative members also diverged on the costs of TOU-related load reductions.
Puget weighed in at 0.6 cents/KWh, WUTC staff came in at 1.5 cents/KWh and Public Counsel and CTED argued for about 3 cents/KWh. For its estimate Puget cited "real results" from TOU customer surveys, conservation program experience and economic principles. CTED described its number as "an approximately and possibly conservative cost," accounting for some combination of energy efficiency measure installation, electric use curtailment or fuel-switching.
There was less discrepancy in cost-effectiveness analyses. The report summarized four different scenarios--two from PSE, one apiece from WUTC staff and Public Counsel--each of which were applied to total resource cost, participant cost and ratepayer impact cost tests. Eleven of the 12 outcomes showed costs exceeding present value net benefits over 10 years, ranging from less than $1 million to more than $17 million.
Still, Englert listed four ways program cost-effectiveness could be improved. One is reduced costs; this TOU effort cost Puget $1.05 per customer per month in incremental expenses, and under a future scenario 92 cents would have brought the program into a reasonably cost-effective range, he said. Another is applying TOU in specific places with higher transmission and distribution system costs. Higher peak prices in wholesale power markets--16 percent higher, according to Englert--would have made TOU cost-effective. Generating additional customer response through more price elasticity also could help the cost-effectiveness equation.
Demand Response
The TOU report also discussed other potential demand-response options, including time-of-use pricing for larger commercial customers, higher energy rates a few days a year during highest power-cost times, and extreme day pricing to encourage load-shedding and/or load-shifting when market prices skyrocket.
The collaborative recommended these possibilities be assessed in Puget's least cost planning process.
An August update to the plan had a chapter on demand response, including a preliminary analysis that more than 200 MW of demand response resources could be available on Puget's system to trim peak loads on cold winter days. A comparably reduced reliance on natural gas-fired peaking power could save the utility $7 million to $9 million annually.
Demand response poses many questions for Puget, Englert said. How would customers react to various specific programs? Could demand response be linked with conservation and fuel-switching initiatives? Are there specific Puget transmission/distribution locations that would benefit from demand response efforts? Can low-income customers, and natural gas customers, participate in demand response?
These all remain under discussion, according to Puget officials. "We don't have any specific plans for additional demand response programs," Englert said.
Ffitch said his office is open to examining demand response options for Puget, although, "Based on this experience with TOU, our feeling is it's better to put your resources into the general demand-side management approach that's offered by Puget's new energy efficiency and conservation programs." He praised Puget's expanded commitment to these programs (see Con.WEB, June 28, 2002).
"We felt we had an opportunity during the energy crisis … to get customers to think about energy efficiency and conservation. We really were concerned that [TOU] was a misdirection," said ffitch, especially since Puget had substantially cut back its conservation programs in the late 1990s.
He found some "fundamental flaws in the premise" behind time-of-use rates. "Just shifting usage around isn't going to be very valuable if what you need to do is more of an energy efficiency approach."--Mark Ohrenschall
More Information:
Washington's largest utility is eyeing wind power.
Puget Sound Energy issued a draft request for proposals Aug. 25 for approximately 150 megawatts of wind energy capacity, as a power purchase and/or utility ownership. The investor-owned utility plans to issue the final wind RFP in early December. It hopes to have wind-generated electrons delivered by mid-2004.
This solicitation stems from Puget's least-cost plan, which identified the utility's need for an additional 436 average megawatts of electric resources in 2004, rising to more than 1,000 aMW by 2011 and nearly 2,500 aMW by 2023.
"We have the need for resources and our strategy is to meet that need through a balanced and diversified portfolio, as well as being aggressive with conservation and renewables," Puget resource planning manager Charlie Black told Con.WEB.
In addition to the wind RFP, Puget proposes to issue solicitations over the next year for thermal resources (including coal), other renewables, cogeneration and seasonally shaped power. Another wind RFP is possible in 2004 or 2005. Puget also plans to acquire 203 aMW of energy conservation from 2004 through 2013.
The IOU wants renewables to comprise 10 percent of its electricity supply by 2013.
Least Cost Planning
Puget's draft RFP outlines the context for the wind solicitation.
"The overall strategy for least cost resource planning at PSE is to develop a diversified, balanced electric resource portfolio that meets customer needs, results in reasonable energy supply costs and protects against market risks, such as those recently experienced in the region," it states. Puget's quest for added resources is driven by growing customer loads, reduced hydropower and gas-fired combustion turbine generation, and expiring power purchase contracts.
The utility's preferred resource blend for 2004-2013 is predominantly fossil-fueled--primarily combined-cycle gas-fired power (both year-round and seasonal), but also including coal. Those sources comprise almost 1,200 MW of the nearly 1,600 MW of new resources envisioned by Puget over the next decade. About 400 MW of renewables and conservation make up the remainder.
"This diversified approach provides an important means to avoid the concentration of risks that could result from relying exclusively on a single resource technology to meet all of the need," according to a summary of Puget's resource acquisition program.
In addition to diversity, Puget's strategy takes into account the utility's seasonal needs, namely the imperative for new resources to meet winter demands.
Puget also considers it better to acquire new resources in a series instead of simultaneously, to help spread risks and incorporate updated information.
First up is the wind RFP.
Black told Con.WEB several factors are pushing the wind solicitation timing, including bonus tax depreciation available for wind project capital spending by 2004, the marketplace presence of several other potential Northwest wind purchasers, and Puget's ambitious renewables goals, which equal about 270 aMW of energy, or 900 MW of nameplate wind capacity, in the next decade. "We really need to get going" to meet that target, Black said.
Wind RFP Particulars
Puget's draft RFP identifies the utility's interest in "approximately 150 MW of nameplate capacity from wind power resources." Minimum proposal size is 25 MW.
Potential projects must be located in Washington, Oregon, Idaho or Montana, "with preference given to sites within PSE's service territory that contribute to economic development of the host community consistent with local community preferences." Puget's primary service territory lies in Western Washington, but it also has customers in Central Washington's Kittitas County, site of three proposed large wind projects (see Con.WEB, July 16, 2003). Black said wind projects directly interconnecting to Puget's system could avoid added wheeling costs and some ancillary services expenses, while showcasing to customers a tangible renewable resource.
The IOU also expresses a preference for new wind projects beginning commercial operation by year-end 2004. Other utilities or their subsidiaries are welcome to bid.
Proposers can offer power purchase agreements and/or arrangments for Puget project ownership. "All other factors being equal, ownership is of significant interest to PSE and long-term power purchase agreements (up to 20 years or longer) are preferred over short-term," the RFP states.
Utility ownership possibilities include PSE buying and operating the project as it enters commercial production (or leaving operations to the proposer), PSE purchasing development rights and handling design, procurement and construction, or joint development/ownership. Black said utility ownership could offer more control over the resource, along with potential financial and contractual advantages.
Puget's draft RFP lists an estimated 20-year levelized cost of 4.28 cents per kilowatt-hour under Puget ownership, and 4.43 cents/KWh under a power purchase agreement. Black called this "our starting generic assessment" of potential wind costs.
The wind energy can be delivered to Puget as produced; firmed and delivered at a later date; or seasonally shaped to match the utility's needs, according to the RFP. The utility wants the wind-associated environmental attributes to "accrue to [its] ownership and beneficial use."
Puget's solicitation outlines a two-phase evaluation process.
"In the first stage, proposals will be screened to identify the most desirable wind resources on a stand-alone basis as measured against criteria such as cost, location and other thresholds," the RFP states. "In the second stage, the most beneficial projects identified in the first stage will be further evaluated as part of PSE's overall portfolio to identify those which perform best (from a cost-effectiveness, environmental, technical intergration, risk and other bases) in relation to PSE's existing and future resource mix." Selected project(s) would then be further discussed and negotiated for agreement(s), although Puget retains the right to choose no proposals for negotiations or contracts.
The RFP schedule calls for a 60-day comment period on the draft solicitation (ending Oct. 24), Washington Utilities and Transportation Commission approval by Nov. 4, final RFP issuance on Dec. 3, a response deadline of Jan. 9, selection of short-listed proposals by Feb. 2 and letter[s] of intent to move toward a final contract executed by March 19.--Mark Ohrenschall (Steve Ernst contributed to this story)
More Information:
A new wind farm is proposed in northeastern Oregon.
Alpine Power has submitted a permit application with Union County to build a 91.8-megawatt-capacity wind farm on more than 1,500 acres of rangeland about 15 miles southeast of La Grande.
The Union County Planning Commission has granted tentative conditional-use approval for the project, which the Oregon-based company plans to build in three phases of 17 turbines apiece, starting in 2004.
Alpine needs to furnish more information on the site's wildlife and bird habitat, as well as fire protection plans, before earning final approval, said county associate planner Scott Hartell. "Basically we had no opposition to this application at all," he told Con.WEB. Oregon's Department of Fish and Wildlife had concerns about the wind farm's potential effects on habitat, he said, but lacked detailed knowledge for an adequate review.
Alpine requested the tentative conditional-use approval so it could begin lining up financing for the project and soliciting contracts for the power output. "There's definitely a market" for this prospective wind energy, said Alpine consultant Patti Pointer.
Wind Plans
Alpine has arranged a 55-year lease agreement with a single property owner, William Ricker, to build a wind farm on 1,544 acres about two miles southeast of Union. An Alpine report prepared by Pointer described the terrain as "mostly steep and rocky with sparse vegetation and ... generally unsuitable for the production of farm crops." Livestock grazing and feed crop production are the predominant land uses. The site is primarily rolling rangeland, with a few small hay meadows, according to Hartell.
Three single-family homes and two manufactured homes lie within a mile of the site's boundary, but because of the topography, "the wind turbines will not be readily visible to the residences in the vicinity," the Alpine report said. Nearby property owners support the proposed wind farm, according to the company, and no agriculturally productive land would be rendered unusable. "The turbine sites are far removed from any areas that are traversed by the public or impacted by farming practices," the report said.
 |
| (Courtesy of OGI) |
The site features estimated average wind speeds of 16 mph to 20 mph and transmission lines less than a mile distant, the company report said.
Alpine anticipates a three-phase construction, each phase covering 17 turbines, ranging in capacity from 660 kilowatts to 1.8 megawatts apiece, and placed according to specific wind resources on the site. Turbines would stand a maximum of 120 feet high. Power generated would flow through buried cables to nearby overhead transmission lines.
Phase one would cost an estimated $23 million, Pointer said, including six miles of new roads and upgrades on nearly two miles of an existing county road.
Alpine hopes to start building roads next spring and begin generating power from the first 17 turbines by late 2004, Pointer said.
Local Reaction, Issues
Alpine's wind farm proposal has generated local interest but no noticeable opposition, Hartell said--"There's no red flags flying up." Pointer described local reaction as "pretty good ... I think people are pretty much in favor of this green energy. This has been a good area. [The site] is so isolated. You just can't see it anywhere."
Union County planning staff will review Alpine's submittals on wildlife, birds and fire protection, Hartell said. "If staff deems they met their burden of tentative approval, we can go ahead and grant them final approval ... basically give them the go-ahead to begin their project." Otherwise, staff can send the case back to the planning commission, he said. Any appeals of the planning-level decision would be considered by the county commissioners.
Hartell said several other wind developers have shown interest in Union County, but none have filed project applications.--Mark Ohrenschall (Cassandra Sweet contributed to this article)
A proposed Seattle initiative measure to raise residential electric rates 1 percent to pay for local renewably generated power has failed to gain sufficient citizen support.
Initiative 81 needed at least 17,229 valid signatures of registered voters for submittal to the Seattle City Council, which would have had the option to enact it or set a citywide vote. But supporters gathered only 5,000-plus signatures by the Aug. 20 deadline.
Still, initiative proponents have not abandoned the idea.
"At this point we're just appealing to the City Council to see if we can get them to take some kind of action, adopt it themselves or adopt some version of it, or possibly to put it on the ballot next year," said Jeremy Smithson of Puget Sound Solar, who is involved with the proposed initiative.
As proposed, Initiative 81 would have initially produced an estimated $1.5 million annually for a Seattle City Light-administered fund that would have paid owners of small solar and wind installations up to $1.50 per kilowatt-hour generated. The average Seattle residential customer would have paid an additional $5 annually under the proposal, based on current rates.
Campaign to Fund Seattle Small-Scale Renewables
Smithson said the Initiative 81 campaign was conducted by "a pretty small group of volunteers. The response we got was really quite excellent. If we had conducted a campaign better with more volunteers and been better prepared earlier in the campaign, we probably could have gotten our [required] signatures."
Sign-up boards placed around town proved effective, but they were too few and too late to achieve the threshold for City Council consideration, Smithson said. "If we had known about the sign-up board method earlier, had known how successful it could have been, we probably could have used that to a much greater extent."
Initiative backers also set up at several major local outdoor events, which "gave us lots of opportunities to talk about solar energy, and listen to those with interest," wrote Solar Washington president Chris Herman in the group's Sept. 10 newsletter.
Supporters now are looking to the Seattle City Council, several of whose members have made "favorable responses" to renewable energy, according to Smithson. "We're just hoping we can really get the interest of the Council, and also to get City Light's interest. It's a program they would be administering; we'd really like to sell them on the idea, too."
No Council members have yet given "affirmative nods specifically for our initiative," Smithson said. Council members Heidi Wills and Richard Conlin could not be reached for comment before Con.WEB deadline.
City Light spokesman Dan Williams told Con.WEB in July the utility hadn't taken a position on Initiative 81. "It's fairly new and we're thinking about it internally," he said. Rate decisions, he added, are "really the domain of elected officials."
More on Initiative 81
Modeled after a German solar-electric program, Initiative 81 would have imposed a 1-percent rate increase for City Light residential customers (with an exemption for low-income households). Accumulated funds would have been earmarked for local solar and wind producers with systems up to 5 kilowatts in capacity. Renewables generators would have received up to $1.50 per KWh sent into City Light's distribution system; excess monies beyond each year's energy production payments would have carried over into future years.
This idea is similar to Chelan County PUD's Sustainable Natural Alternative Power (SNAP) program, although SNAP funding comes from voluntary customer green power payments and not a mandatory utility rate increase.--Mark Ohrenschall
More Information:
Stateline Wind Energy Center has killed an estimated 1.7 birds per turbine annually, a slightly lower fatality rate than for other U.S. wind projects, according to recently published preliminary findings.
Stateline's first avian and bat monitoring program report documented 106 bird deaths and 54 bat deaths on standard search plots around representative turbine groups between July 2001 and December 2002. Those numbers were extrapolated to come up with fatality estimates for the entire 399-turbine wind farm, which straddles the Oregon-Washington border southwest of Walla Walla.
Horned larks were the predominant victims, accounting for 43 percent of found bird fatalities. No threatened, endangered or candidate bird or bat species--at the federal or state levels--were discovered as casualties of the world's largest land-based wind farm.
"It generally confirmed what [Stateline developer] FPL [Energy] has been asserting all along, that it is a relatively low-use area for avian species," said John White of the Oregon Department of Energy.
The report said Stateline's fatality estimates could actually be high, as they include many birds with an undetermined cause of death. FPL believes the fatalities represent a tiny fraction of the total birds in the Stateline vicinity.
"We were pleased the number was below the average estimated for other projects," said FPL Energy's Anne Walsh, noting this report is part of an ongoing bird and bat monitoring study through 2003. "We'll continue to work closely with the agencies and the local Audubon Society to review the final results," she said.
Careful turbine siting is the biggest factor in limiting bird deaths at wind farms, according to the American Wind Energy Association. An AWEA publication lists other and far greater causes of bird deaths: house cats, which kill an estimated 100 million birds annually in the U.S.; collisions with plate glass, which cause an estimated 97.5 million bird deaths each year; and collisions with vehicles, which lead to 57 million dead birds annually. AWEA also cited a study estimating 3,000 bird deaths at a Florida coal-fired power plant one night during fall migration.
Monitoring Stateline
As part of the monitoring program, WEST Inc. and Northwest Wildlife Consultants personnel searched for carcasses around 41 representative turbine plots effectively consisting of 146 total turbines. More than 2,200 separate searches were conducted between July 2001 and December 2002, the report said.
Trained searchers recorded the number of intact and scavenged bird carcasses, along with sitings of 10 or more feathers in one spot. "All bird casualties observed within the search plots were included in the fatality estimates, unless cause of death could be determined, and this cause was not related to the wind facility," the report said. "True cause of death is unknown for most of the fatalities." Other potential causes likely include vehicles, raptors and weasels.
The report also used statistical methods to gauge searcher efficiency and carcass removal rates, in deriving estimates of bird deaths.
WEST Inc. concluded that the 399 Stateline turbines caused an estimated 1.68 bird deaths apiece on an annual basis, slightly less than the 1.82 average estimate for other U.S. wind projects listed in a 2001 report.
Overwhelmingly the most common bird victim, by species, was the horned lark, described in the report as "a common resident songbird" and later by FPL as the most abundant local species. The report documented 46 horned lark deaths, 43 percent of the bird total. "I don't think I've had a satisfactory explanation" for that finding, said Shirley Muse of Blue Mountain Audubon Society, although she noted horned larks find "ideal habitat" in the area.
None of the other 26 bird species found as casualties exceeded six recorded deaths. Six raptors were discovered dead, including four red-tailed hawks. Small birds accounted for an estimated 1.52 deaths per turbine per year, and large birds an estimated 0.16 deaths per turbine per year.
Turbines in the middle of rows had "statistically significant[ly]" more bird deaths than turbines at the end of rows, the report said. Lit turbines had more dead birds around them than unlit turbines, although the difference was minimal. Bird carcasses were found an average of about 100 feet from the nearest turbine.
The report also documented 54 bat deaths around turbines, slightly less than one fatality per turbine per year--lower than found in other new wind projects, but higher than neighboring Vansycle Ridge Wind Farm.
In addition to searching for carcasses, field observers also recorded living birds in the vicinity. Horned larks accounted for more than half of 2,262 recorded birds, while Western meadowlarks and Canada geese also were commonly seen. Given the relatively brief periods for these observations, said FPL, "It is a reasonable conclusion that the estimated number of fatalities at the project comprised an extremely small percentage of the number of birds that spend time in and near the project area."
Siting Importance
Extensive wildlife studies before Stateline's construction helped determine where to put turbines, according to FPL's Walsh. "We worked with the government officials and we had consultants, specialists and we worked also with the local Audubon Society to look at the siting locations," she said.
AWEA also stresses the importance of siting. "Studies to date indicate that the most important action to take in reducing bird deaths at wind energy plants is to carefully evaluate proposed sites before wind turbines are installed," the trade group said. For example, turbines at a Wyoming wind farm were placed away from a mesa rim where raptors were found to be frequent fliers.
Muse, of the local Audubon Society, said her organization supported Stateline's local governmental approval, although it had a few specific concerns. One was the proposed location of a turbine string near McNary National Wildlife Refuge, which is popular with migrating waterfowl; FPL left out the string, she said, and further research, including nighttime radar studies, showed bird deaths would not be a huge problem. Auduboners also worried about a ferruginous hawk nest, which Muse said has since been abandoned, though for unclear reasons. Ferruginous hawks are listed as a threatened species in Washington.
She said she doesn't like the fact birds are killed by wind farms, but she noted her car sometimes accidentally hits birds, and her now-deceased cat ate birds.
Muse said she prefers renewable wind to fossil-fueled and nuclear-powered energy, and southeastern Washington/northeastern Oregon is a windy place. "The birds and the turbines need the same habitat," she said. "To me, what you have to work on is to do the best job you can and not go into places where there are clear dangers to birds."
Wind developments have improved in coexisting with birds, she said, with, for example, the advent of tubular towers that minimize perching opportunities and spread-out turbine strings that allow birds to fly more easily between wind machines.--Mark Ohrenschall
More Information:
More Northwest homes and businesses have the option of buying green power, either directly from their utilities or via green tags marketed through Bonneville Environmental Foundation.
Renewable Northwest Project's recent "Powerful Choices IV: A Survey of Retail Green Power Programs in the Pacific Northwest" showed that 35 of the region's utilities now offer green power products.
Such products are fulfilling a "pent-up demand" that has long existed in the Northwest, said Rob Harmon, BEF's director of renewable energy programs.
"What's changed is the availability of green power offerings," Harmon said. "If you look back at the market four to five years ago, consumers had no ability to buy green power. There was a pent-up demand. What you see is the pent-up demand being supplied."
Meanwhile, the business case for renewable energy is becoming stronger, said PacifiCorp spokesman Deston Nokes. "From a practical standpoint, there is more diversity and less potential for power disruptions," he said. Pacific's integrated resource plan calls for adding 1,400 megawatts of renewables, primarily wind, to the utility's resource portfolio in the next 10 years.
Green Power Customers
Green power programs attract customers motivated to act on their environmental concerns, utility representatives said. "They are concerned about the environment and willing to walk the talk," said EWEB spokesman John Mitchell. EWEB is selling 2,200 customers 11.6 million kilowatt-hours per year through the EWEB Windpower program.
"People who tend to make their homes here are very environmentally conscious to a great extent," said Martha Warachowski, energy services coordinator of Orcas Power & Light Cooperative in Washington's San Juan Islands. A total of 4.9 percent of Orcas residential customers buy green power products, the highest percentage of residential customer participation in the Northwest.
Customers are asking for more renewable energy, said Jim White, senior engineer at Chelan County PUD. "During the (2000-01) energy crisis, we put in diesel generators, and customers asked us, 'Why not install solar and wind power?'" White said. Chelan's Sustainable Natural Alternative Power (SNAP) program pays for locally generated wind and solar power.
Harmon said utilities have become more customer-focused since deregulation and restructuring became an industry issue. "There is a general trend toward sustainability. Utilities are not unaware of this. They see another reason to give customers what they want," he said.
Green power buyers are people who believe their purchases will make a difference in "changing the way energy is produced," said Jane Peters, a Portland researcher who spoke last year at the seventh annual Green Power Marketing Conference in Washington, D.C.
Peters, a customer research and energy program evaluation specialist, said her research shows customers attracted to green power programs tend toward a high degree of "self-efficacy," a perception that their actions will achieve expected results. Program marketing can take advantage of that by reinforcing a message that participation will make a difference in reducing pollution and expanding availability of green power, she told the green power marketing conference last year.
Mitchell said green power buyers include environmental "true believers." EWEB, which serves a community noted for its environmental awareness, "has an audience that is muy simpatico to green energy," Mitchell said.
Norton said green power customers "generally" have more discretionary income and live in "communities with a little more of a progressive orientation and environmental ethic." Olympia (with nearly 1,100 participants), Bellingham and Bellevue are the top three communities in Puget's service territory for number of citizens signed up for the utility's green power program, she said.
PacifiCorp's green power demographics are similar, Nokes said. "A key demographic characteristic of residential renewable power purchases is high education levels. Participants also tend to live in urban areas, have lower monthly energy bills and live in smaller households," he said.
Green Power Programs
Green power programs vary in the types of renewable generation projects that the price premiums support, and in product design.
In Oregon, where the two major investor-owned utilities are required by state law to offer customers green power options, both PacifiCorp and Portland General Electric offer three programs.
Each utility has a wind-only program, Clean Wind at PGE and Blue Sky at PacifiCorp, which pay for energy from projects such as Foote Creek Rim in Wyoming. Power is sold in 100 kilowatt-hour blocks. PGE charges $3.50 each, while Pacific charges $1.95 per block. Of each $3.50 PGE customers pay, $1 buys energy from existing wind projects and the remaining $2.50 funds new renewable projects.
Wind energy is delivered to customers beyond green power programs; wind is sold both as a separate product and melded into utility resource portfolios, utility officials noted.
Pacific Power currently has about 70 MW of wind in its rate base. According to the utility's most recent figures, Pacific sells 10.2 million KWh of renewable energy per month, including 4.2 million KWh of wind, through green power programs, Nokes said.
Two additional programs are available to PGE and Pacific customers through Green Mountain Energy, a national renewable power retailer that sells a blend of geothermal power from northern California facilities and wind from the 299-megawatt-capacity Stateline Wind Energy Center.
Customers of the Green Mountain programs pay per-KWh surcharges, ranging from 0.78 cents/KWh to 0.9 cents/KWh. Subscribers to Green Mountain's Salmon-Friendly program pay an additional $2.50 per month designated for salmon habitat restoration projects. For example, PGE customers contributed $22,920 to help pay for replacing culverts blocking two creeks in the Scappoose Bay watershed, PGE said.
Washington utilities with more than 25,000 customer meters are required by state law to offer green power options to customers. Customers of the state's largest utility, Puget Sound Energy, can buy a minimum of two 100-KWh blocks for $2 per block. Proceeds pay for BEF green tags. More than 7,000 Puget customers subscribe, paying an average of about $6 per month and buying more than 2 million KWh each month, according to Puget spokesman Tim Bader.
The 1,800 subscribing customers to Avista Utilities' Buck-A-Block program pay for 55-KWh blocks from Stateline; the average participants buys about five blocks, said Chris Drake, marketing program manager.
Differing price structures reflect the differing marketing strategies by utilities. Avista went with Buck-A-Block to offer customers maximum flexibility, spokeswoman Catherine Markson said. "It doesn't have to be all or nothing. Customers can buy as little or as much as they want," she added.
In addition, Drake said Buck-A-Block is tailored to eastern Washington and northern Idaho household incomes, which are generally lower than in Western Washington.
Vigilante Electric Cooperative in southwestern Montana has signed up more than 40 customers, predominantly residential, since the co-op began offering a renewable power option this summer. Customers can buy 100-KWh blocks of Bonneville's Environmentally Preferred Power product for $1.10 each. "The cost of the product is tremendously well-priced and is available in a block format we could handle," said Rod Siring, who runs Vigilante's member services and marketing. Vigilante passes the costs through directly to customers without an additional local charge, he added.
Vigilante looks at renewable power programs as a long-term investment in diversifying the region's resource portfolio, according to Siring. "With five to six years of drought we've seen, we need to support non-hydro resources," he said.
Orcas Power & Light sells 100-KWh blocks for $3.50 each, Warachowski said. For each $3.50 paid, $1.92 goes to the EPP product Orcas buys from BPA, and $1.58 funds local renewable projects, including solar, wind, and micro-hydro, she said.
Rather than selling blocks, EWEB asks green power customers to specify the percentage of their load that they want supplied by the Foote Creek Rim wind project of which EWEB is a minority owner (PacifiCorp owns most of the project). Adopting this method wasn't a marketing call, however. "The reason at the time was our billing system's inability to handle blocks," Mitchell said.
EWEB is thinking of switching to blocks because it's an easier concept to explain, Mitchell said. "Percentages take more time to explain and a little longer to figure out. The amount of green energy you're using [under percentages] depends on your household consumption," he said.
A few utilities ask green power customers to make dollar contributions rather than pay for kilowatt-hour blocks. Idaho Power customers, for example, can contribute any amount they wish; proceeds are used to buy green tags.
Green Tags
Harmon said green tags represent the environmental attributes of renewable power, such as avoiding carbon dioxide emissions released when electricity is generated in fossil-fuel plants. Each tag represents 1,000 KWh generated by renewable energy projects placed into service after May 1, 1999, according to BEF. Tags cost $20 each, with customers required to purchase a minimum of two. BEF green tags are supplied by a number of Northwest wind and solar projects.
Harmon said green tags are a way of selling renewable power's environmental attributes as a separate product, unbundled from the electricity itself. Power from renewable generating plants can be sold at a premium as green electricity. Or, the power can be sold at the regular rate as grid electricity and the environmental attributes unbundled and sold separately as a green tag. But utilities can't sell renewable power at a premium and green tags from the same facility, since that would be double-counting, he said.
Using the swimming pool analogy commonly employed to describe the workings of the electric grid, Harmon said green tags enable electricity buyers to direct their dollars to power plants filling the pool "from clean streams rather than dirty streams."
BEF has sold green tags to customers across the country. "Green tags get around the difficulties some renewables have with transmission paths," Harmon said. For example, a Georgia power customer will not be able to buy much wind energy locally, since the Southeast has relatively poor wind potential. Much more wind is available in North Dakota. "But you wouldn't want to string a transmission line from North Dakota to Georgia. There would be no benefit to that. A green tag adds liquidity to the market by enabling the Georgia customer to buy the attributes of North Dakota wind and pump capital into the market for developing more renewables," Harmon explained.
In addition to green tags, BEF markets Bonneville's EPP--a blend of wind, solar and low-impact hydro--to 29 publicly owned utilities in the Northwest and Wyoming.
Green Power Benefits
Utilities have found through marketing surveys that customers want green power programs that provide specific information, according to RNP's 2002 "Powerful Choices" report.
"Because green power can be intangible, we do try to relate the benefits to something specific, that your green power purchase is equivalent to planting a specific number of trees or avoiding a specific amount of emissions," said Liz Norton, Puget Sound Energy marketing manager.
Idaho Power's Web site includes a green power "calculator" enabling customers to see what specific dollar contributions will buy in green kilowatt-hours and CO2 emissions reductions, with a comparison showing how the CO2 reductions equate to cars taken off the road. For example, the site shows a $5 monthly contribution will buy 400 KWh, which prevents 3.4 tons of CO2 emissions per year, equal to taking two-thirds of a car off the road.
RNP reports many customers want their utilities to invest in locally generated renewable power. Chelan County PUD invests all proceeds of green power premiums in six local projects connected to Chelan's grid, including a 10-KW-capacity solar-electric array at Wenatchee Valley College. RNP credited Orcas' local green power projects for the utility's high customer participation rate.
Norton said locally produced renewable power is "definitely" important to Puget Sound Energy's customers. "We are continuing to get more localized," she said. "We're talking to people about small wind, solar and low-head hydro within our service territory."
Commercial Green Power Customers
Green power is attractive to commercial customers that place high value on being good neighbors and responsible corporate citizens, said RNP's Diane Zipper.
Kinko's buys green power for more than 150 branches in 13 states, including Washington and Oregon. Nationwide, Kinko's buys an estimated 11.2 million KWh of green power per year, according to figures supplied by the company.
Northwest companies that have purchased green tags include the law firm Stoel Rives, CH2M Hill, Nike, Mount Hood Meadows ski area and Xantrex.
Norton said green power is marketed to commercial customers by noting that purchases will help companies "communicate their core values." Participating businesses get free publicity courtesy of Puget, including press releases and window decals, she said.
Looking Ahead
The future of green power overall depends on continuing cost reductions and technology improvements, utility representatives said. More rate-basing of wind energy "is where things are headed," Nokes said.
"Wind power growth will be a function of costs. As more turbines are built and as prices fall, we hope wind will continue to grow," said Avista regulatory compliance manager Bruce Folsom.--Jim DiPeso
More Information:
OFFICES: Mail-P.O. Box 900928, Seattle, WA 98109-9228. EXPRESS: 117 West Mercer, Seattle, WA 98119.
TELEPHONE-(206) 285-4848. FAX-(206) 281-8035. E-MAIL-newsdata@newsdata.com.
Con.WEB was created by the Energy NewsData Web team, including: Publisher-Cyrus Noë; Editor-Mark Ohrenschall;
Contributing Editors-Jude Noland; Cassandra Sweet
Contributing Writers-Jim DiPeso; Steve Ernst; Lynn Francisco; Ben Gilbert; Garrett Hering; Amber Schwanke; Ben Tansey
Web Production-Michelle Noë
General Manager-Brooke Dickinson.
Please contact Mark Ohrenschall,
marko@newsdata.com,
with questions or comments on this site.
Copyright ©2003 Energy NewsData Corporation
Return to Contents