CWEB.038/February.26.1999
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The Montana Public Service Commission has established guidelines for how Montana Power should allocate the $8.56 million it will collect for universal systems benefits programs in 1999.
The state's electric restructuring act mandates the investor-owned utility collect this money--equal to 2.4 percent of its 1995 retail sales revenues--for continued financing of its energy conservation, renewable energy and low-income energy assistance programs. However, the law does not spell out exactly how the money should be spent.
The commission, having resolved that allotment of Montana Power's USBP money falls within its jurisdiction (see Con.WEB, Jan. 29, 1999) issued a Feb. 4 order recommending specific funding levels for the utility's public-purposes programs.
The commission earmarked the largest portion of the money--$2.5 million, or 29 percent--for use in a large customer rebate program, in which customers with loads greater than 1 megawatt that administer their own energy efficiency programs would qualify for credits.
MPSC further suggested Montana Power spend 42 percent of 1999 USBP funds, or $1.8 million apiece, on local conservation and low-income programs, including weatherization and bill-payment assistance. The commission reserved 13 percent apiece, or about $1.1 million each, for renewable resource projects and market transformation. The remaining 3 percent, or $225,000, of 1999 USBP funds is targeted for research and development. Should any money remain in the large customer rebate account by Nov. 30, the commission directed MPC to reallocate it to low-income programs.
In its order, MPSC said it derived its allocation scheme by starting with the Regional Review recommendations and making numerous adjustments. For example, the commission said that because "most parties addressing USBC issues agreed that there is an unmet low-income need," it placed priority on funding those programs.
MPSC also said that because Montana's restructuring law gives Montana Power the option of sending its public-purposes funds to the state rather than administering its own programs, the commission cannot technically require the company to meet the funding levels stipulated in its order. But, the commission said, "MPC should make every attempt to achieve this allocation, as directed."
"Generally, I think we're OK with the commission's order," said Pat Corcoran, Montana Power director of regulatory affairs. "They changed our numbers a little bit, but this is in the range of what we were anticipating . . . The next step is to look at how we might go about providing for or administering these programs."
In its original testimony, the utility proposed an independent non-profit corporation to oversee the money's administration. The commission did not rule out this alternative in its Feb. 4 order, but said it would need regulatory authority over such an entity.
"Whether we set up a non-profit or some variation is yet to be decided," Corcoran said. "It could be something as simple as setting up a steering committee to perform the administrative functions. We still need to evaluate that and report back to the commission," he told Con.WEB.
Of specific public-purposes projects MPC might fund with the USBP money, Corcoran added, "we've had problems throughout this whole exercise, starting or stopping new programs because of the uncertainties. So we've basically walked a straight line, continuing projects already under way." He cited as examples Montana Power's energy audit program and its work with state and local organizations in providing low-income discounts and weatherization. "We still need to look at how far we might go on some of those programs and entertain new or different offerings."
Montana Cooperatives and Public Purposes
Montana Power is not the only utility in the state subject to the restructuring law's public-purposes provisions. Publicly owned utilities and cooperatives are not obligated to file restructuring transition plans with the PSC until July 2001 and they are allowed to offer their customers retail choice at a slower pace than Montana Power, but they are still bound by the 2.4- percent USBP funding level the legislation establishes for 1999.
"The co-ops are already voluntarily in excess of that 2.4 percent," said Dave Wheelihan, general manager of the Montana Electric Cooperatives Association. A recent poll put Montana co-ops' average public-purposes spending at 3.5 percent of 1995 retail sales revenues, according to Wheelihan. "So we'll continue as we have in the past. The USBP charge is not a new tax."
Bill Chapman, general manager of Glacier Electric Cooperative, echoed Wheelihan. Chapman said much of Glacier's public-purposes obligation for 1999 will be met by debt-service payments to Bonneville Power Administration--the co-op's sole electricity supplier. "Bonneville provides us with a number we can use to determine in mills per kilowatt-hour how many dollars in our power bill are used for all those things that qualify as USBPs," Chapman explained.
Under the restructuring law, Glacier's total public-purposes obligation for 1999 is $224,349, with a mandatory 17 percent--or $38,139--earmarked for low-income programs. "In 1998 , we spent $215,486 on public purposes in our power bill alone," he said. "That puts us within $9,000 of meeting the 2.4 percent. And since we have programs outside of BPA, we already exceed the minimum requirements."
MECA's Wheelihan added that the major difference in how co-ops administer public-purposes programs will be in "how we demonstrate we are spending the monies." Under the law, public utilities must submit annual reports--detailing programs, funding levels and any payments to the state's universal energy assistance fund--to the PSC and the legislature's Transition Advisory Committee. Co-ops must make similar reports to their respective governing boards and the TAC. However, Montana's restructuring legislation fails to explicitly identify how and by whom these reports will be evaluated.
Moreover, the way in which Montana Power's USBP allocations are handled in the future remains uncertain.
But a bill sponsored by Rep. Ernest Bergsagel, chair of the Montana Legislature's USBP subcommittee, may clear up some of the ambiguity. HB-377 would give the state's Department of Revenue the authority to adopt rules governing USBP expenditures and to review any challenges to public-purposes credits a utility may claim. The bill also charges the Montana Departments of Health and Human Services and Environmental Quality with responsibility for overseeing payments received from utilities that fail to meet annual USBP requirements.
By a vote of 89 to 11, HB-377 was passed by the Montana House Feb. 4. It was sent to the state Senate, and referred to the Senate Business and Industry Committee for hearing.--Angela Becker-Dippmann
At the end of 1996 a blue-ribbon regional panel recommended major changes in the Northwest electric industry, including allowing customer choice of power suppliers and subscription to federal power, forming independent transmission operations, and providing public-purposes funding for energy conservation, renewable energy and low-income energy services.
More than two years later this grand vision of a new and more competitive regional electric structure has yet to materialize--nor is it likely to in the near future.
Only one of the four Northwest states--Montana, the least populous--has officially restructured its electric industry with provisions for customer choice and public-purposes funding (see related story in this issue). Elsewhere restructuring elements have appeared in limited and piecemeal fashion, such as the current federal power subscription process, pilot customer-choice programs and narrow legislation for the likes of utility bill unbundling. Federal restructuring legislation remains a possibility, but is not considered imminent.
And in the non-Montana Northwest no statewide public-purposes funding is in place, although the Regional Review recommended it should be legislatively enacted by July 1999 at the level of 3 percent of electric revenues.
What happened? And what does it mean for Northwest conservation and renewables?
Regional energy industry circumstances have changed markedly since the Review, and momentum for comprehensive electric restructuring has slowed if not halted altogether.
Meanwhile, utility funding for conservation and renewables has continued its sharp regionwide decline from the mid-1990s. Reported energy savings also are dropping. Still, a few utilities avidly pursue public-purposes initiatives, which are popular with customers despite the spending cutbacks. And a number of promising avenues remain for conservation and renewables.
In the absence of public-purposes funding, the regional pattern for efficiency and renewables resembles a patchwork quilt.
Reviewing The Review
The rationale behind public-purposes funding is outlined in the Regional Review's December 1996 final report: "The Northwest electric industry has a long and successful history of developing cost-effective conservation and supporting the development of renewable electricity sources, such as wind, geothermal and biomass energy. In addition, the utilities have played a major role in delivering weatherization to low-income households and helping low-income households with their energy bills. Competitive pressures, however, are expected to make significant changes in the ways utilities carry out these activities in the future. The goal of the Steering Committee's recommendations is to provide for maximum local control in the implementation of conservation, renewables and low-income energy services, while establishing an effective minimum standard that ensures stable funding for these purposes."
During a 10-year transition to a competitive energy industry, the Review suggested the region annually meet the 3-percent public-purposes standard, which equals about 65 percent of 1995 spending, or $210 million. Between two-thirds and five-sixths of those funds should be earmarked for local utility initiatives, with the rest going regional, much of it for market transformation. (Montana opted for a restructuring scenario that sets aside 2.4 percent of annual utility revenues for public purposes, with provisions for large-customer credits, cooperative utility pooling of credits and minimum annual utility spending of 17 percent on low-income energy services.)
The Review's public-purposes recommendations were part of a much larger package fashioned under different regional energy circumstances. "Prices were extremely low in the [wholesale] market, there was the threat of fairly immediate national legislation, and Bonneville was in a crisis," remembers Rachel Shimshak, director of Renewable Northwest Project and a Review steering committee member. "Those three things have changed."
Review steering committee member Ken Canon, executive director of Industrial Customers of Northwest Utilities, also sees changed circumstances in the electric industry. "I think any restructuring of a fundamental industry like this is going to take time," he said. "I don't think it was ever presumed it would happen quickly," even though the Review set various dates.
The Review did identify major issues involved in restructuring: wholesale power, transmission, retail competition and public purposes. "I think its relevance was, at that point in time, trying to give the region a direction," said Canon. "As we move away from that point in time, that direction may change. That's not a surprise to me. Those types of efforts are never forever."
Many industrial customers--47 percent in Washington in 1997, according to a state study--have already gained access to non-traditional (i.e. market-based) rates through their incumbent utilities, diminishing industrial clamor for comprehensive restructuring that includes open retail access and public-purposes funding. (Despite the upturn in market electric prices industrials still want to be able to make their own power-supply choices, said Canon.)
Other factors have contributed to waning interest in restructuring/public-purposes legislation, according to a 1998 paper by Howard Schwartz of the Washington Department of Community, Trade and Economic Development.
For one, he wrote, " . . . opponents of deregulation in Washington and Idaho who fear higher rates, less reliability, loss of union jobs, etc., do not see the loss of public purposes as enough of a reason to support the deregulation and public purposes package." Schwartz also argued that Northwest utilities, with their relatively inexpensive electric resources, are not in as dire need of stranded-cost protection as were utilities in other, restructured states. He also indicated the interests represented on the Review steering committee were not as diverse as those represented at state capitals, and political calculations changed in legislative forums. And, Schwartz wrote, "with almost all of the implementation of the Review's recommendations on public purposes devolved to the states and local utilities, the region lacks a lead institution to carry out its will. As a result, there is no reason to expect that the public purposes recommendations of the Review will be carried out consistently from state to state or at all."
Residential electric consumers in the low-cost Northwest seem generally satisfied with the status quo monopoly electric system. K.C. Golden, another Review steering committee member and assistant director of the Energy Policy Group CTED'S finds among Washington legislators "a real profound resistance to entertain any fundamental changes in an electric system they perceive to be performing well . . . I just think restructuring has been and is a big complicated issue and a potentially disruptive solution to a problem most folks aren't clear they have. It's understandable it's bogged down."
At the same time, however, Golden believes electric markets are already changing and growing more competitive. These trends "are going to challenge our ability to accomplish our policy goals, ranging from ensuring adequate supply to ensuring reliability to ensuring environmental protection to ensuring fair allocation of the tax burden, and including public purposes. I think at a minimum we ought to be at least looking at efforts to ensure our means for achieving our policy goals are relevant and appropriate and effective in a changing market environment."
Utility Spending Decline
The widespread decline in Northwest utility conservation spending since the mid-1990s is documented in at least two recent studies.
Last summer the Northwest Energy Coalition released a report that found a dozen major electric utilities in Washington and Oregon falling short of the Review's public-purposes spending guidelines. NWEC interpreted this finding as a consequence of electric industry restructuring. In the coalition's view, it highlighted the need for a competitively neutral public-benefits charge on electricity sales to fund energy conservation and renewable energy initiatives.
"Utilities are preparing for the significant challenges they will face in a more competitive power market by rushing to cut costs," said coalition director Sara Patton in a news release. "As a result, vital investments in conservation, new renewable energy and low-income weatherization are falling by the wayside."
The NWEC study examined spending on energy conservation, new renewable energy resources and low-income weatherization by 12 Washington and Oregon utilities--publicly owned and investor-owned--from 1995 through 1998. NWEC then compared the utility-supplied data to the Review public-purposes guidelines. None of the 12 utilities have met the Review's prescription in all three public-purposes categories in any year since 1995, although several have spent more than the recommendations for energy conservation.
The 12 utilities are PacifiCorp, Portland General Electric, Puget Sound Energy and Washington Water Power, all investor-owned, and eight publicly owned utilities: Clark Public Utilities, Emerald PUD, Eugene Water & Electric Board, Lewis County PUD, Salem Electric, Seattle City Light, Snohomish PUD and Tacoma Public Utilities.
The NWEC analysis does not account for any Bonneville Power Administration conservation funding, nor does it include utility conservation loan programs, except for their administrative expenses and any utility costs to provide below-market interest rates. In renewables, the report acknowledges but does not credit utility investments in new renewable resources built or committed to before 1996, in keeping with the Review's recommendations.
More recently, a Washington state study released in December provided further evidence of the sharp downward trend in electric utility conservation spending, finding a 72-percent reduction since 1993. Utilities representing 86 percent of Washington's electric sales reported spending $155 million on conservation in 1993, the peak year this decade. That figure includes BPA funding. In 1998 those utilities expected to invest about $44 million in conservation, a total forecast to shrink to $24 million in 2000.
"Competitive pressure to minimize prices, lower wholesale energy prices, uncertainty regarding future market structure, and programmatic changes have contributed to this decline," according to the "Washington State Electricity System Study," prepared by CTED and the Washington Utilitities and Transportation Commission.
"There's some identifiable damage the mere prospect of restructuring has done," said Seattle City Light's Marc Sullivan, who chaired the conservation subcommittee of the Review's conservation, renewables and public-purposes work group. Seattle, in contrast to the prevailing trend, continues to significantly fund public purposes, devoting about 5 percent of revenues to such initiatives, according to Sullivan.
In Oregon, a preliminary Oregon Office of Energy study estimates annual utility conservation spending has plummeted from $79 million in 1994 to $47 million in 1996 to about $30 million in 1997 (all in nominal dollars). This reflects large declines in BPA and IOU spending, according to OOE's Charlie Grist, although some publicly owned utilities have actually increased their own funding. First-year energy-saving levels are down proportionately, too, falling from a high of about 45 average megawatts in 1995 to about 17 aMW in 1997.
Grist has found a diversity of approaches within public power. Some utilities basically stopped doing conservation, except for state-mandated programs, once their BPA funding disappeared. Others have made up the difference with their own funds. And still others have cut back their percentage of revenues spent on public purposes. Many have moved to reduce program costs by using loans instead of rebates or increasing direct customer contributions for measures and programs.
"In the absence of statewide public purposes, it's clearly up to the [public-power utility] boards to make annual decisions about programs and spending levels," Grist said.
Resource, Cost-Effectiveness Issues
While restructuring and its many implications have contributed to the general trend of reduced utility public-purposes spending, resource issues and cost-effectiveness calculations also are at work.
BPA, which slashed its conservation spending from $172 million in 1994 to $42 million in 1997, is no longer acquiring energy resources of any kind, noted energy efficiency vice president Terry Esvelt. "Since 1994 or 1995 it's been clear Bonneville is not expected to be the resource acquirer for the region. That's why we were doing conservation, to a significant measure." The absence of that role "has more dominated why we've changed our functions and support for conservation," he said.
"Clearly nobody knows who's responsible for developing resources of any kind, let alone conservation and renewables," said Golden, noting a shortened investment horizon and an uncertain market structure. And, he said, "Even when energy efficiency is the least-cost resource it isn't necessarily the price-minimizing resource. For utilities facing a more competitive market, the premium on price minimization is even greater than it ever was."
PacifiCorp--which in the NWEC study dropped its conservation/renewables/low-income weatherization spending from 2.4 percent of revenues in 1995 to a projected 0.34 percent in 1998--follows an integrated resource planning process to identify "the appropriate level of investment in demand-side and renewables," said PacifiCorp's Brian Hedman. "We just target our program to achieve that level of demand-side resources." To do more, or less, would be viewed imprudent by PacifiCorp's regulators, according to Hedman.
PacifiCorp's most recent IRP targets 9 average megawatts to 13 aMW annually of DSM resources, a range Hedman said PacifiCorp has been achieving. Those numbers reflect a "very substantial" decline in available cost-effective conservation, which is influenced by wholesale market prices.
"Restructuring per se hasn't influenced the public-purpose programs" of PacifiCorp, Hedman said. "What is has influenced is the ability of the company to accurately forecast things such as demand. If you don't know who your customers are going to be, it's tough to figure out demand and it makes it difficult to implement an IRP."
PacifiCorp generally supports the Regional Review recommendations on public purposes, he noted, although it would like to retain some percentage of utility-run programs.--Mark Ohrenschall
More Information:
Retail access to electric suppliers and public-purposes funding are among the issues addressed in the Oregon Public Utility Commission's long-awaited Jan. 28 decision on Portland General Electric's customer choice plan. Large commercial and industrial customers would be able to directly choose their energy supplier, under the OPUC ruling, while small commercial and residential customers would be able to choose from a portfolio of utility-offered options. The decision also supports a system benefits charge for energy conservation and renewable energy initiatives.
Reaction to the OPUC decision has been generally positive. PGE "has many questions" about the ruling, but the utility recently told the commission it sees areas in the proposal "with which we can work."
Among the areas in which the PUC and PGE agree are the portfolio option for residential customers, and public-purposes charges. In a Feb. 5 letter to the Oregon commissioners, Pamela Lesh, PGE's vice president of rates and regulatory affairs, said the utility supports a portfolio option and cost-of-service rates for residential customers.
Portland General also supports the proposed system benefits charge--and both PGE and the Oregon PUC agree specific legislative action will be needed to implement the charge.
The commissioners suggest such legislation set the SBC at 3 percent of PGE's annual revenues, beginning with fiscal year 1999, and allocated as suggested by the Regional Review among conservation, renewables and low-income weatherization. The charge should be collected via a revenue-based method, not according to usage, and disbursed by a governor-appointed advisory board. Creation of such a board would also require legislative action, as would a number of other elements in the proposal.
Three Critical Elements
The OPUC's Jan. 28 decision accepts portions of PGE's initial customer choice plan, filed in December 1997, but also accommodates suggestions made by other parties in the case, from public-interest groups to industrial customers.
The ruling has three critical parts, according to commission chairman Ron Eachus. It allows direct access for industrial and large commercial customers, prevents the sale of PGE's hydro assets, and offers a portfolio for residential customers, while making sure all customers receive some benefit from PGE's hydro system. The ruling "is a major step but a cautious step," Eachus said. "It lets those who have the most likelihood of benefiting from direct access receive it" and "protects from harm" those least likely to benefit from customer choice.
Customers with more than 30 kilowatts of demand--essentially, large commercial and all industrial customers--will have direct access to energy service providers under the OPUC decision. Smaller commercial and residential customers will have access to a portfolio of options--such as a market-based rate and a renewables rate--offered by PGE, in which the utility "takes title to ESP-provided power and delivers it to customers." And all customers will still have an option of staying with a traditional cost-of-service rate.
"The restructuring we approve thus takes into account the differing needs of different consumer classes," the commissioners said in their order, noting that "when we have more experience with direct access, we will consider broadening the availability of direct access to smaller customers." For example, Eachus said, if customers are responsive, a direct access option could be added to the portfolio plan.
The order also allows PGE to sell its non-hydro generating assets through an auction. The commissioners indicated the hydro relicensing processes under way for some projects could lower their sales price; and an attempt to sell the hydro assets now could also "jeopardize worthwhile environmental initiatives by delaying the relicensing process."
Commissioners also rejected the utility's proposal to create a Hydro Trust to own and operate the hydro facilities. They said the concept needs substantial development before they can endorse it.
In the meantime, the order calls for a mechanism providing all customers with some share of the lower-cost benefits of the hydro assets. The details still have to be worked out, said Lee Sparling, program manager for OPUC's electric rates and planning section. Lesh's letter to the OPUC indicated PGE wants to ensure such a credit does not shift costs or benefits among customer classes.
Another area of great interest--and potential contention--is the order's treatment of BPA's residential exchange credit. While approving "in concept" the sale of the utility's other generation assets, commissioners expressed concern their decision will affect residential customers' access to federal power, as set out in the 1980 Pacific Northwest Electric Power Planning and Conservation Act. So the order directs PGE to obtain a statement from BPA on whether the OPUC proposal will affect access to federal power under the exchange, and how BPA will treat each specific proposed resource sale. The OPUC "will also require PGE to hold customers harmless if the sale of a resource results . . . in a reduction in access to federal power by PGE's customers."
PGE cannot accept the "hold harmless" suggestion, Lesh said, and the utility will ask OPUC on reconsideration to pull that provision. At the same time, PGE will work with BPA to obtain answers to the other exchange-related questions the commission raised.
Cost Recoveries
The OPUC ruling allows PGE 100-percent recovery of its investments in demand-side management projects and 95-percent recovery of other stranded costs--with the potential for recovering the other 5 percent if an asset sells for more than book value. As Sparling explained, if PGE sells a $100 million investment for $80 million, it can collect $19 million of the remaining $20 million stranded costs from customers. If, on the other hand, that resource sells for $120 million, the customers receive an additional $19 million, while PGE gets to keep $1 million. Sparling said the OPUC's formula is an incentive for the utility to get the highest price for its assets.
All transition costs will be recovered over a five-year period, at the utility's embedded cost of debt. The manner in which these costs will be recovered from customers is not decided in the order, which suggested PGE file a revised transition cost recovery proposal. Lesh said PGE may also file a petition with OPUC for reconsideration or clarification of some issues. And some issues can be resolved easily, she said. For example, establishing minimum sign-up and notice periods during which customers can switch between a market rate and cost-of-service portfolio option would reduce PGE's concerns about the adverse effects of switching on risk management and market development.
In her letter, Lesh said PGE must be satisfied that the order's proposal meets "the criteria we applied in designing our plan:" that it serve the best interest of both PGE customers and investors. "That's what we want to figure out," she said. The answer probably involves both traditional and non-traditional means of utility regulation and designing "some things that match what's happening in the competitive world."
The answer could also ultimately rest with the state Legislature. Although Oregon lawmakers have been hesitant to tackle utility restructuring, the OPUC order has prompted more legislative attention. The OPUC is writing a restructuring proposal to accompany its order, and Sen. Gene Derfler is expected to introduce a measure in the near future. Meanwhile, a proposal developed by the Fair and Clean Energy Coalition has already been introduced in the House (see related story). At the same time, Lesh indicated the absence of a restructuring law this session isn't a death knell for the customer choice proposal. The next legislative session, in 2001, is still within "a reasonable time line," she said. "There are systems and resource issues to work through, too."--Jude Noland
More Information:
The first of several anticipated electric industry restructuring proposals has been introduced in the Oregon House of Representatives and is expected to be introduced soon in the state Senate. It includes provisions for customer choice, stranded-cost recovery and public-purposes funding
The proposal--House Bill 3359--was developed by the Fair and Clean Energy Coalition, which also authored legislation considered during Oregon's 1997 session. HB 3359 was introduced by Rep. Jim Hill, said FCEC spokesman and Northwest Energy Coalition representative Steve Weiss. Weiss also expects Sen. Gene Derfler to introduce the proposal in the Senate--although Derfler also is reportedly working on his own version of restructuring legislation. The Oregon Public Utility Commission is developing a restructuring proposal, too, in conjunction with its decision in PGE's customer choice filing (see related story).
The FCEC proposal calls for fairly limited restructuring of Oregon electric utilities, describing it as "relating to the restructuring of electricity generation and protection of electricity consumers." It would place most restructuring burden on the OPUC, which would have authority to develop and implement changes called for in the proposal. Most such changes contain a caveat: "If the commission finds that there is clear and convincing evidence that [such provision] is in the public interest, the commission is authorized to . . . "
For example, if the commission determines retail direct access is in the public interest for non-residential customers, the commission would be authorized to require "any or all electric companies to offer direct access to their customers using greater than 30 kW, to develop the necessary rules and procedures to facilitate a fair and competitive market for these customers, to certify and license marketers to provide the necessary services, and to impose any other appropriate terms and conditions that are consistent with this Act."
Before allowing any direct access, however, the commission would first have to complete needed proceedings for any affected electric utility to offer a portfolio option to "low-usage" customers and ensure such customers are not disadvantaged; set service quality and reliability standards; determine which customer services, such as metering, billing and collection, can be provided by competitive suppliers; establish a default provider of service; determine stranded cost transition charges; and set unbundled rates. The OPUC is also charged with licensing power marketers and developing disclosure requirements for products.
If larger customers are granted direct access, the commission would be authorized to develop a means to offer a limited portfolio of electric supply options to customers "of that electric company who are not eligible for direct access." The incumbent utility would initially offer the portfolio, while the PUC would pick the portfolio options and set their rates, terms and conditions. The portfolio would have to include a "basic product," which would also serve as the default rate; and one or more options with, "to the extent practicable, significant new renewable resource content obtained through competitive bid. "
The commission could also require an "electric company or portfolio manager serving qualified residential exchange loads to purchase a commission-determined amount of federal power and/or other products from the Bonneville Power Administration."
The commission would also have the authority to require stranded-cost recovery or benefit sharing, determine if a utility should retain some generation assets, and establish a hydro trust.
Public-Purposes Provisions
The FCEC proposal also includes a detailed section on public-purposes charges, collections and disbursements. The bill would give the Oregon Office of Energy administrator authority to determine "a minimum annual statewide expenditure standard for electric utilities and direct service customers that is equal to three percent of the total revenues from the sale of electricity services in the state . . . for the purpose of funding energy conservation, new renewable energy resources and low-income energy services. "
The OPUC would decide how these funds would be collected from customers, while the proposal outlines how the money would be allocated: 13 percent for low-income energy services; 54 percent for local cost-effective energy conservation services; 14 percent for other energy conservation and related services, including market transformation and consumer education; 16 percent for "the above-market costs of the development and commercialization of new renewable energy resources"; and 3 percent for "development and demonstration of new distributed renewable energy sources and regional renewable energy research and development."
An Energy Efficiency and Renewable Energy Resources Board, with five governor-appointed members, would advise the OOE administrator on disbursement of the funds, which utilities would deposit in an "Oregon Energy Efficiency and Renewable Energy Resources Account."
Electric utilities could receive credits for the renewables portion of the public-purposes requirement if they're involved in a certified new renewable energy resources project. Customers that used more than 10 average megawatts per site in the previous calendar year could receive energy conservation credits for qualifying conservation expenditures.
The proposal also would establish a Universal Service Fund to provide qualified low-income households with bill-paying and crisis assistance. The fund would start with $20 million--which would include federal money and charitable contributions in addition to utility deposits. The OOE administrator would determine how much each utility and direct service customer would be required to contribute to the fund, "based on the number of meters and graduated for capacity or any other factor or combination of factors in a manner determined to be in the public interest by the administrator."
And finally, nothing in the proposal "is intended to impair the rights of community-owned utilities to sole authority in their territories to grant or not grant direct or portfolio access; and to set conditions, determine economic or uneconomic utility investments, set transition charges or credits, set fees to retain franchise fees and privilege taxes, unbundle services, determine which currently provided exclusive services such as metering, billing and collections may be provided by alternative competitive providers, and make any other determinations regarding the provision of direct access and/or portfolio choices to their customers."
Other Restructuring Proposals
Other proposals are also moving through the legislative process. Sen. Derfler is expected to soon introduce his long-awaited restructuring bill--although a Feb. 19 draft met with some initial negative reaction. The OPUC legislation, meanwhile, is awaiting Gov. John Kizhaber's sign-off, according to OPUC's Lee Sparling.
The OPUC proposal differs from the other two in that it is enabling legislation, prompted specifically by the PUC's ruling in PGE's customer choice case. In that decision, commissioners indicated they would need specific legislative authority to carry out some aspects of the proposed restructuring plan. The proposal covers only those items. "Our bill would give us the authority [even] if the Legislature doesn't act" on restructuring, Sparling said. Rather than dealing with restructuring on a statewide level, therefore, the commission would have authority to approve specific restructuring proposals filed by individual investor-owned utilities. As now drafted, it amends state statutes to clarify the OPUC's authority. Among the changes are the addition of the term "energy service provider," along with an appropriate definition; an amendment allowing a public utility to file rates for distribution service only; and another specifying OPUC's authority to determine transition costs or benefits and recovery or return of those costs or benefits.
The proposal also states, "Notwithstanding any other provision of law, the commission may, in its discretion, assess" a system benefits charge on public utilities that have direct service programs, "on energy service providers or on end users of electricity." The assessment is set at 3 percent of gross revenues from the sale of electricity in service territories of public utilities with direct access programs.
The OPUC measure also provides more detail on the System Benefits Board the commission designated in its PGE order to oversee funds collected through the system benefits charges. The independent non-profit corporation would be governed by a seven-member board of directors. Members would be appointed by the governor, with at least one member representing each of the following: public utilities with direct access programs, residential customers, commercial customers, industrial customers, and energy service providers selling electricity in the service territories of public utilities.
The Feb. 19 draft of Derfler's proposal establishes a system benefits charge, but there was some confusion on the amount of the charge and on whom it would be levied. But the proposal "is not [Derfler's] final take on the matter," said Brian Smith, administrator for the Senate Public Affairs Committee, which Derfler chairs. Smith said the senator has agreed to make some amendments after the bill is introduced.
The proposal as now written sets the "statewide expenditure standard" for electric utilities and direct service industrial consumers as 3 percent of total revenues "from the sale of electricity in the state." If electricity in this case refers to the commodity only, pointed out Jason Eisdorfer of the Oregon Citizens' Utility Board, the total amount collected would be significantly less than intended under the recommendations of the Regional Review.
The proposal separately stipulates that electric utilities collect a public-purposes charge from its direct access retail electricity consumers, once the utility begins offering direct access services to those customers. Set at 3 percent of the utility's total revenue from the sale of electricity services to the retail electricity consumer, the charge would be assessed until Dec. 31, 2006.
Eisdorfer also disagreed with the proposal's mandate that all residential electric customers have direct access by Jan. 1, 2006. "We can't support direct access for residentials, even five years from now." Non-residential customers have access by Jan. 1, 2001, under Derfler's draft.
An issue for public utilities is the bill's treatment of exemptions for electric utilities that are not electric companies. Such public utilities can opt out of direct access if a majority of its retail consumers vote in favor of such a move--but the utility can only hold one such election.
Derfler's proposal also calls for establishing a portfolio option for residential customers, permits aggregation of retail electricity customers, establishes reciprocity requirements and directs the Oregon PUC to determine transition cost recovery and to establish certification standards for electric service providers.
Derfler's proposal is expected to be introduced in early March in the Senate Rules and Elections Committee. Meanwhile, OPUC's Sparling doesn't expect the PUC proposal to move very quickly. Sen. Derfler reportedly wants to start by working on his proposal.--Jude Noland
A restructured Regional Technical Forum is proposed by the Northwest Power Planning Council to account for the RTF's expanded role supporting Bonneville Power Administration's conservation/renewables rate discount.
A new Council draft proposal outlines the prospective RTF role in BPA's rate discount, along with a potential institutional structure and governance for the proposed regional conservation/renewables evaluative body. It emphasizes the importance of RTF credibility in providing solid and objective technical information, as well as RTF independence from both the Council and BPA.
The forum would retain its primary envisioned functions of establishing standardized protocols to verify and evaluate energy savings; tracking and assessing regional progress towards conservation and renewables goals; and suggesting improvements for more effective conservation and renewables development in the region.
Intending to form the RTF in May, the Council seeks public comments on the draft proposal by March 17. The regional panel expects to decide on the RTF's formation at its April 6 meeting in Boise. (Visit the Council's Web site to read the draft proposal and the accompanying letter.)
The RTF and BPA's Conservation/Renewables Discount
The Council's draft proposal notes BPA's rate discount planning has presumed a significant RTF role in technical support. "It is clear that the responsibilities associated with the C&R discount will increase the RTF's workload and the sensitivity of that work," the proposal states. "This has necessitated a revisiting of the thinking about the RTF. The purpose of this paper is to suggest a different formulation for the RTF in light of the responsibilities it will have with respect to the C&R discount and to seek public comment on that formulation."
Among the prospective RTF rate discount projects cited in the proposal: 1) A list of conservation measures/programs, along with their estimated savings and regional power system values; 2) A process for updating the list as technologies and standard practices change; 3) Protocols for estimating the savings and system value of non-listed conservation measures/programs, such as complex commercial/industrial initiatives; 4) Renewable resource criteria; 5) Recommended protocols to measure and evaluate savings or energy production.
The RTF, according to the proposal, likely also would analyze information from BPA customers claiming their discounts, "to provide a regional level assessment of the effectiveness of the C&R discount." It could also conduct a few targeted evaluations. "In both instances, the purpose of collecting and analyzing this information is to improve the program effectiveness on a going-forward basis, not to penalize customers for past actions."
Also outlined in the proposal are general RTF roles: "The RTF would collect, review and distribute existing protocols for verification and evaluation, and develop and promulgate new methods in response to new information and/or new approaches to achieving conservation savings . . . For tracking, the RTF would develop standardized forms and data definitions for use by retail electricity distribution utilities, state and local low-income weatherization service providers and renewable resource developers. The RTF would compile the data submitted and publish an annual regional summary . . . compar[ing] the level of activity and expenditures reported with the Comprehensive Review's 'public purpose' goals. In addition and clearly more important, the RTF would assess what was being accomplished through those expenditures--electricity savings achieved, low-income consumers served, renewable resource production achieved--and at what cost . . . The RTF would also take a proactive role to promote effective programs and approaches . . . [and] provide its findings and recommendations to local utility governing bodies and/or state regulatory agencies regarding program effectiveness and potential for improvement."
Proposed RTF Structure, Governance
Affected parties must believe the RTF provides quality and objective technical information, "not unduly influenced by one set of interests or another," the Council's draft proposal states.
It envisions the RTF as strictly advisory to BPA and its conservation/renewables discount. "Bonneville will have to carry out a process of its own to accept, reject or modify the recommendations of the RTF."
The Council would fund the RTF (with possible other financial sources, such as state public-purposes money). However, it would function as a special advisory committee to the planning agency, and its recommendations to BPA would not be subject to Council approval.
RTF members would be appointed by the Council from nominees submitted by stakeholders and the public. These people "should bring to the RTF technical experience and expertise in the analysis of conservation and renewable resources, the design of conservation and renewable resource projects and programs, their implementation and their evaluation."
Based on the Northwest Energy Efficiency Alliance model, the Council proposes two seven-member groups on the RTF: one would have a BPA representative and six BPA customer representatives; the other would have four representatives of state energy agencies and three public-interest-group representatives. Each state regulatory agency would be invited to serve in a non-voting capacity. RTF advisory groups should include "key consumer representatives," including industrial customers and energy services providers.
RTF recommendations would need approval from at least 10 of the 14 members. Public input on RTF decisions also should be encouraged.--Mark Ohrenschall
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A fuel cell system successfully demonstrated in two Oregon homes is poised for broader distribution around the Northwest via local electric utilities.
"Our [utility] customers are quite interested in having us jointly develop this and making it available to them," said Mark Jackson of Bonneville Power Administration, which contracted with Northwest Power Systems of Bend, OR, on a prototype 5-kilowatt proton exchange membrane fuel cell system. "It's another option to offer their customers at the end of a distribution line."
The system performed "flawlessly" in two recent demonstrations at residences in the Bend and Eugene areas, according to Jackson. The demos included a battery storage system to supply peak-power needs. The 3-foot by 3-foot by 40-inch power generator also survived a 5,000-plus-mile road trip through the four Northwest states, where engineers and executives from numerous utilities viewed the system at work. "They really thought it was cool," reported Jackson.
The PEM fuel cell converts a methanol/water mixture into hydrogen and then into electricity through a chemical reaction, creating heat and water as byproducts. This particular machine consists of the proton exchange membrane, a patented fuel processor and hydrogen purification system, and assorted other equipment such as hoses, valves, pumps, blowers, radiators and a power conditioner, according to Northwest Power Systems president Alan Guggenheim.
It is also uniquely integrated. "Nobody's offering what we're putting together," said Jackson. "No other stand-alone fuel cell system makes its own hydrogen on site and conditions power and everything else."
And, yes, it is pricey. Each Northwest Power Systems unit costs $50,000 (for orders of 10-24 units, according to the company's Web site). The operating cost for electricity produced at the Bend demonstration was about 12 cents per kilowatt-hour, which includes a 10-year amortization of the fuel cell system, captured heat value and methanol fuel. That's roughly double Pacific Power & Light's local residential rate of 5.5 cents/KWh. "We have a ways to go in terms of efficiency and we have a ways to go in terms of total cost of energy," acknowledged Guggenheim.
But he believes fuel cell systems will shrink in price and new conventional power supplies will grow more expensive. "There's going to be a little paradigm shift. These fuel cells will make economic sense in addition to their already good environmental sense." Fuel cells don't create hazardous pollutants, such as carbon monoxide, nitrogen oxides and particulates, Guggenheim noted. They quietly produce consistently reliable power. Their conversion rate in transforming fossil fuels into energy is about 45 percent, reasonably high for power generation--and when excess heat is captured for reuse, the conversion efficiency jumps to about 90 percent.
Both Guggenheim and Jackson envision fuel cells as particularly viable energy alternatives in places distant from distribution lines. "We expect the hundreds of large utilities as well as the electric cooperatives here in the Northwest to use fuel cells in remote locations where emergency propane or diesel-powered backup generation and battery storage might otherwise be used," Guggenheim said in a November news release. "They could also use fuel cells directly in the power system, especially in remote locations where they can replace other forms of backup power."
BPA's Interest
"We've been tracking fuel cells for a long time," said Jackson, who served on an Electric Power Research Institute steering committee for distributed generation research and development. "Basically through [the committee] I got quite interested in PEM technology and got hooked up with Northwest Power Systems." The Bend company, founded in 1996, makes patented small-scale fuel processors for use in PEM fuel-cell systems, according to its Web site. This fuel processing capability "makes the whole thing work" in the absence of readily available pure hydrogen, according to Jackson. The 5-KW unit built under contract for BPA also incorporates a PEM fuel cell made by an Italian firm.
"BPA seems to be very strongly behind these new and much cleaner forms of distributed generation," said Guggenheim. Indeed, Jackson described BPA administrator Judi Johansen and deputy administrator Jack Robertson as "the principal proponents of pursuing" the fuel cell project.
BPA supports distributed generation, with a focus on fuel cells. Robertson said the push to develop cars that run on non-gasoline fuels has led to advances in fuel cell technology that make the proton exchange membrane a viable option for small-scale electricity generation. Robertson views Bonneville's role as helping bring the technology to market, as with investing in wind energy. And he views PEM fuel cells as renewable energy, like wind, and "an intelligent way to push renewables."
If the cost of PEM power drops to 7 cents/KWh, he said, it's attractive to rural utilities that "see it as an alternative to transmission investments." Seven cents per KWh may be more than retail, he pointed out, but there are no transmission or distribution charges. And since most utilities view distributed generation--whatever its source--as a complement to existing transmission and distribution systems, eliminating T & D costs is a selling point. If the technology continues to gain acceptance among rural utilities, "acceptance there could make it more competitive in other places," Robertson said. "Penetration could occur quite rapidly."
Robertson believes the growing viability of distributed generation resembles the evolution of today's personal computers from mainframe central computer
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| This 5-kilowatt fully integrated PEM fuel cell supplied power to a residence in Bend, OR (Photo courtesy of Northwest Power Systems) |
Initial funding for developing the prototype system came from residual BPA research and development funds, according to Jackson. BPA's Power Business Line has approved continued funding, and Jackson expects money for fuel cells to be included in Bonneville's post-2001 wholesale rates.
BPA already has ordered 10 additional PEM fuel cell units, and the agency plans to distribute them to interested utility customers on a cost-shared basis. The utilities can use the units wherever they choose. "I think we'll have more demand than we can accommodate for the first 10," Jackson said; BPA account executives will decide which utilities get fuel cells.
Should this limited sample prove successful, BPA anticipates ordering 100 more cost-shared units, for a substantially lower price per system.
"It's an interesting marketing effort," said Jackson. "Nobody's really sure the best way to distribute fuel cells into the markets. Some say they'll wind up at Costco, but there's no customer support or installation assistance with a discount warehouse product. Some utilities are thinking they can keep a customer and not string wires. They might sell customers the fuel to power it, do warranty work, installations . . . They see it as something else they can offer their customers." BPA, as a federal agency, can't capitalize on fuel cell business opportunities as can local utilities, he noted.
In any case, fuel cells will likely be a niche energy market for quite some time. "It certainly isn't going to displace the system in 10 years," said Jackson, adding with a laugh, "It might take 50 years for that."--Mark Ohrenschall (Jude Noland contributed to this report)
More Information:
The trade group Industrial Customers of Idaho Power wants the Idaho Public Utilities Commission to reconsider its Jan. 21 order granting Idaho Power recovery of its 1997 spending on membership in the Northwest Energy Efficiency Alliance (see Con.WEB, Jan. 29, 1999).
In a petition for reconsideration filed Feb. 12, ICIP said it believes the commission's decision is based on a "non-existent standard of review" and does not conform with the law.
Part of the problem, according to ICIP attorney Peter Richardson, is that Idaho Power has no direct control over the Alliance and the Idaho PUC has no jurisdiction over the market transformation collaborative. "If we're going to have to spend money on conservation, we should do it in Idaho, on Idahoans," Richardson said. And "if there's a global reason to do [market transformation], do it at the public policy level."
ICIP's petition for reconsideration faults the commission order on several fronts.
First, the petition said the commission based its decision on a "non-existent standard of review" by failing to apply a cost-effectiveness standard to Alliance expenditures. In so doing the IPUC abandoned its legal responsibility to ensure Idaho Power "charges are just and reasonable." By not applying a cost-effectiveness standard, ICIP argued, "a prudency finding is impossible to make," yet the commission's decision indicated the 1997 Alliance expenditures are prudent. ICIP said this finding is arbitrary and further claims it is unsupported by the record.
The group also contends allowing recovery of 1997 costs "violates the ground rules initially set by this commission" in its original order authorizing the utility's participation in the Alliance. In that order the IPUC said it would be premature to authorize recovery on a "pay-as-you-go basis" until the Alliance and its programs "have demonstrated their prudence." By approving recovery of 1997 costs, ICIP says, the commission is "doing exactly what it ruled it would not do."
The industrial customers also contend the Alliance has overstepped its bounds and moved into the legislative and lobbying arenas. "Ratepayer funds should not be used to lobby or otherwise attempt to influence government or other public policy," the petition reads. But the "theme" of Alliance executive director Margie Gardner's testimony in the Idaho Power case, said ICIP attorney Richardson, is that "they want to influence federal regulation" in areas such as setting more stringent federal efficiency standards for household appliances. This is especially true in the Alliance's support of the WashWise program (now known as the Energy Star Resource-Efficient Clothes Washers program) to promote high-efficiency washing machines, in which, he said, "The federal process is the key target."
Idaho PUC and Idaho Power officials declined comment on ICIP's petition.--Jude Noland
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