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PRELIMINARY DRAFT-SUBJECT TO CHANGE

September 10,1996

Comprehensive Review of the Northwest Energy System Draft Report

Designing a Competitive Electric Power Industry for the 21st Century


INTRODUCTION

Why Are We Doing This?

The electricity industry in the United States is in the midst of significant restructuring. This restructuring is the product of many factors including national policy to promote a competitive electricity generation market and state initiatives in California, New York, New England, Wisconsin and elsewhere to open their retail markets to competition. This transformation is moving the industry away from the regulated monopoly structure of the past 75 years. Today we are served by individual utilities, many of which control everything from the power plant down to the delivery of power to our homes or businesses. In the future, we may have a choice among power suppliers who deliver their product over transmission and distribution systems that are operated independently as common carriers.

There is much to be gained in this transition. Electricity consumers are already benefiting from competition in a number of significant ways. Competition in the natural gas industry has helped lower the cost of electricity from gas-fired generating plants. Competition among manufacturers and developers of combustion turbines has contributed to less expensive, more efficient power plants that can be built relatively quickly. Surplus generating capacity on the West Coast combined with increasing competition among wholesale suppliers has reduced the price utilities must pay for power on the open market. Broad competition in the electricity industry that reaches down to the consumer could result in lower prices for consumers and more choices about the sources, variety and quality of their electrical service.

But, there are also risks inherent in the transition to more competitive electricity services. Merely declaring that a market should become competitive will not necessarily achieve the full benefits of competition or ensure that they will be broadly shared. It is entirely possible to have deregulation without true competition. Similarly, the reliability of our power supply could be compromised if care is not taken to ensure that competitive pressures do not override the incentives for reliable operation. How competition is structured is important.

It is also important to recognize the limitations of competition. Competitive markets are about economic efficiency, not fairness or other social or environmental goals such as low-cost electricity to rural areas, conservation and renewable resources, and fish and wildlife recovery. To the extent that the citizens of the Northwest want their electricity system to deliver these social and environmental benefits, special attention will be required to accomplish those goals during and after the industry's transition.

In some respects, the transition to a competitive electricity industry is more complicated in the Northwest because of the presence of the federal Bonneville Power Administration. Bonneville is a major factor in the region's power industry, supplying, on average, 40 percent of the power sold in the region and controlling over half the region's high-voltage transmission. Bonneville benefits from the fact that it markets most of the region's low-cost hydroelectric power. It is hampered by the fact that it has high fixed costs, including the cost of past investment in nuclear power, and the majority of the costs for salmon recovery. As a wholesale power supplier, Bonneville is already fully exposed to competition and is struggling to keep its costs close to the market. The transition to a competitive electricity industry raises many issues for the Bonneville Power Administration and the region. In the near term, how can Bonneville continue to meet its financial and environmental obligations in the face of intense competitive pressure? In the longer term, when market prices rise and some of Bonneville's debt obligations have been retired, how can the Northwest retain the economic benefits of its low-cost hydroelectric power when the rest of the country is facing market prices? And finally, what is the appropriate role of a federal agency in a competitive market? The question is not only whether Bonneville can compete in the near term but also, should it be a competitor?

The Comprehensive Review

To seize the opportunities and moderate the risks inherent in the transition to competitive electricity markets, the governors of Idaho, Montana, Oregon and Washington convened a "Comprehensive Review of the Northwest Energy System." The governors appointed a 20 member steering committee that is broadly representative of the various stakeholders in the power system to study that system and make recommendations about its transformation. The members of the steering committee are listed in Appendix A. Each governor has a representative on the steering committee to make certain the public is educated about and involved in the Comprehensive Review. In establishing the review, the governors stated:

"The goal of this review is to develop, through a public process, recommendations for changes in the institutional structure of the region's electric utility industry. These changes should be designed to protect the region's natural resources and distribute equitably the costs and benefits of a more competitive marketplace, while at the same time assuring the region of an adequate, efficient, economical and reliable power system."

Since January of this year, the steering committee has held 22 days of meetings. In addition, almost 400 people have been involved in over 100 meetings of various work groups reporting to the steering committee. This draft report is the initial product of that work. It is a proposal for restructuring the Northwest electricity industry to meet the challenges and seize the opportunities inherent in the competitive transition. Your comments on this draft report will help frame a final report to the Governors to be delivered in December of this year. That, in turn, will be the basis for recommendations from the Governors to the Northwest Congressional delegation and the state legislatures as appropriate.

SUMMARY OF DRAFT RECOMMENDATIONS AND QUESTIONS FOR PUBLIC COMMENT

The draft recommendations of the Steering Committee are summarized in the following sections along with questions regarding many of the key issues that were discussed by the Committee. More detailed discussion of the recommendations is presented later in the report. For purposes of organization, the recommendations are presented in four topic areas: federal power marketing; conservation, renewable resources and low-income energy services; competition and consumer choice; and transmission. Also summarized are the Steering Committee's thoughts and questions regarding the future role for a four-state regional body. Although described as distinct parts, the reader should think of this as an overall comprehensive proposal, the parts of which are interdependent.

Federal Power Marketing -- the Bonneville Power Administration

The Steering Committee's goals for federal power marketing are to 1) align the benefits and risks of access to existing federal power; 2) ensure repayment of the debt to the U.S. Treasury with a greater probability than currently exists; and 3) retain the long-term benefits of the system within the region. The mechanism that is proposed to accomplish these goals is a combination of long- term (30 year) and short-term (five-year minimum) subscriptions. Subscriptions would be available first to regional customers in a specified multi-part priority order, starting with preference customers, then DSIs and IOU exchange customers, followed by other regional customers and concluding with non-regional entities.

Approximately 60 percent of each regional subscription would be reserved for long-term subscriptions until all regional entities have had a chance to take long-term subscriptions. After that, all regional entities would be allowed to take futher subscriptions, if power is still available, in any mix of long- and short-term subscriptions they desire. If regional long- and short-term subscriptions remain unfilled, power would be offered under long- and short-term subscriptions to non-regional customers.

Long-term subscribers get the rights to purchase power at cost for the term of the contract. While the costs of the power from the federal system is currently somewhat above market prices, the costs are generally expected to be below market prices in the future. Short-term subscribers get the right to purchase power at cost plus an option fee for the term of their contracts. Payment of the option fee gives them the right to renew their subscriptions and purchase an option for further renewal. One mill per kilowatt hour (less than 5 percent of the projected power cost) has been proposed as the option fee.

The subscribers assume all risk of the effects of year to year variations in weather, future power system cost increases and changes in market conditions. For example, if we were to experience lower than expected market prices that are below Bonneville costs for an extended period of time, the subscribers would still be obligated to pay Bonneville's costs. Short-term subscribers would be able, at the end of their subscription period, to let their subscriptions lapse and buy at market prices in this case. If they let their subscriptions lapse, however, they are not guaranteed the ability to buy at cost in the future, should that become desirable.

The costs of additonal fish recovery measures above the National Marine Fisheries 1996 Biological Opinion and the fish cap in BPA's current rates should be shared between the customers and the US Treasury. Further, this sharing should be on a roughly 50-50 equivalent basis up to a limit, or a cap on the customers' responsibility that reflects substantial additional costs. These costs, in aggregate (customer and Treasury shares combined), are on the order of $450 to $500 million in today's dollars above the cost of current measures. Further analysis of these numbers is required. Further spending above this amount would be the responsibility of the US Treasury.

Many alternative approaches are available for cost sharing. It could be dollar for dollar. Alternatively it could be a sliding scale where customers pay a higher percentage of the initial measures and a declining percentage to a capped figure at a lower level. For purposes of ease of understanding, it is recommended that customer expenditures above the existing fish cap be on a 50-50 basis with Treasury up to the limit of the customers' responsibility

If market prices are above costs, the Treasury would share in these benefits by getting 20 percent of the difference between market prices and the cost, including the fish recovery cost. The Treasury's share could cover any fish cost not paid by subscribers, or could be a dividend to them.Subscribers may resell power.

Tentatively, the Steering Committee decided that options would not be salable to other parties, but they would specifically like to hear public comment on this question.

The proposal would also have the effect of constraining the role of the Bonneville Power Administration in the competitive market. The fact that most of Bonneville's power would be subscribed at cost would limit Bonneville's market role. In addition, it is proposed that Bonneville would not acquire resources to serve load growth of its customer except on a direct bilateral basis where the customer takes on all the risk of the acquisition. Similarly, it is proposed that Bonneville would not sell directly to new retail loads, beyond the existing DSI loads, though it may sell through intermediaries whose transactions would be subject to state or local jurisdiction.

Questions for Public Comment


Conservation, Renewable Resources and Low-Income Energy Services

The Northwest electric utility 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.

To ensure that cost-effective conservation, renewable resources development and low-income weatherization are sustained during the transition to competition and beyond, the Comprehensive Review recommends that 3 percent of the revenues from the sale of electricity services in the region be dedicated to those purposes for a period of ten years. Based on 1995 revenues, this amounts to approximately $210 million per year. $210 million is 57 percent of what was spent for these purposes in 1995.

The Review believes that most of these funds are most appropriately used at the local level. Consequently, the Review recommends that two thirds of the funds be retained by local distribution utilities to carry out locally-initiated cost-effective conservation and low income weatherization. Conservation projects implemented and funded by large consumers could be credited against the local conservation target. Local utilities would also offer or allow other electricity service providers to offer "green" power to their consumers -- power from renewable energy sources. Local utilities would continue their current levels of low-income energy bill assistance until state governments pick up this responsibility. Several options are recommended for consideration by the states.

Some conservation and renewable resource activities can, however, benefit from regional planning and coordination. The Review recommends that one third of the funds be used by a regional non-profit agency with utility, government and public interest membership. Its functions would be to bring about changes in the markets for targeted energy efficiency products and services that will improve their market share; to plan and contract for research and limited demonstration of renewable energy technologies, and support the development of several megawatts annually of renewable generating capacity. A Regional Technical Forum would be established to set goals and track and evaluate implementation of conservation and renewables in the region.

The Review is not proposing state or federal legislation to require collection and allocation of these funds. The proposal relies on the voluntary commitment of the utilities and regulatory commissions to authorize and carry out the collection, disbursement and appropriate use of the funds. How the funds are collected is also a matter for state or local decision, as appropriate. The Steering Committee expects that methods of collection that are competitively neutral and affect all participants in the market equally will be found to be preferable. The Steering Committee believes that voluntary commitment will work. The steering committee will be listening for the quality of the commitment during the public comment period and in the months thereafter. If it is determined to be necessary, there are mandatory alternatives that could be pursued.

Questions for Public Comment

Competition and Consumer Choice

The goal for retail electricity markets is a competitive market that is driven by consumer choice. If implemented properly, this can deliver a more efficient power system, lower costs, increased product choice and product innovation, and continued reliability and safety to all consumers. The Review recommends that regulators and local utility boards and commissions be prepared to offer open access for all customers by 2001. A competitive retail electricity market requires separation of the distribution and electricity marketing functions of current retail utilities. This is necessary to ensure that consumers will have unimpeded access to alternative electricity suppliers, and vice versa, over the wires of the distribution utility. The distribution utility would continue to be a regulated monopoly responsible for the reliable and safe delivery of electricity from electric service companies to consumers over local distribution "wires." Electricity service companies will offer a variety of electricity products and services (e.g., firm or interruptible power, power from "green" resources, peak or off-peak power, fixed or spot market prices) to consumers on a competitive basis and may, in fact, offer other products unrelated to electricity markets. The electricity services portion of current integrated retail utilities could compete in this market if the distribution utility function is sufficiently separated from the electricity services business to ensure that control of distribution is not used to advantage the electricity services business.

It is recognized that putting such a competitive market in place will require a significant transition. There is a danger that, until competitive markets have fully developed for all consumers, the benefits of increased competition may be realized primarily by large consumers. Therefore, the Review calls for active government oversight of the transition and active programs to facilitate and encourage the development of meaningful market access for all consumer classes and to prevent unwarranted cost shifts between customer classes. Specifically, the policy calls for licensing of new electricity service providers, applicability of consumer protection laws, formal complaint processes, consumer information programs, and the local electricity provider serving as a "provider of last resort" to ensure continued affordable service to all consumers during the transition period. To further minimize cost shifts to small consumers, policies should be adopted to provide utilities a fair opportunity to recover costs of previous investments that may be "stranded" by the opening of the market. However, this is viewed as a transitional problem only, and incentives must be included for utilities to mitigate any stranded costs they potentially face.

Questions for Public Comment

Transmission

Transmission is the "highway system" over which the products of electrical generation flow. If there is to be effective competition among generators, transmission facilities should be operated independently of generation ownership. An Independent Grid Operator (IGO) regulated by the Federal Energy Regulatory Commission (FERC) with broad membership including Bonneville and the region's other major transmission owners is recommended as a means of ensuring independence of transmission operation. An IGO should also have clear incentives to maintain reliability and encourage efficient use of the transmission system..

The independent operation of Bonneville's transmission facilities is particularly important to effective competition among generators in our region, because these facilities make up a large part of the regional transmission system. To ensure this independence, it is recommended that Bonneville be legally separated into two organizations -- a power marketing organization to market the power from the federal power system and a transmission organization to carry out the transmission functions. In separating these organizations and their funding, it will be necessary to ensure that the security of Washington Public Power Supply System debt is not impaired. A separated Federal transmission owner (e.g., the Bonneville Transmission Corporation) could lease its assets to an IGO, or could be an IGO and operate other participants' assets if the other participants agree.

Legislation may be required to accomplish these goals. While legislation is under consideration, Bonneville should move quickly to achieve as much administrative separation as possible, and to participate in efforts to form an IGO that could operate both federal and non-federal transmission assets.

Questions for Public Comment

Future Role for a Four-State Regional Body

When the Northwest Power Act was passed in 1980, the authors contemplated an extended time of electricity shortage and the need for increasingly costly large scale power plants. The Northwest Power Planning Council was established with two representatives from each of the Northwest states to provide the states and the public a role in determining the future need for electricity and how that need could best be met. The Power Planning Council has been credited with many improvements in electricity planning. However, in an era in which market forces will play the primary role in determining what plants get built and what can be charged for their output, the Northwest Power Planning Council's planning role is no longer relevant.

There is, however, much that is unknown about the competitive future we are about to embrace. As the Northwest transitions toward a competitive electricity industry, there may be roles that the region would desire to be carried out by a regional body. These roles may involve ensuring that the transition to a competitive market is done efficiently and fairly throughout the region and that the public values the Northwest has sought from its power system are preserved and enhanced. These roles might include: Reliability -- monitoring and evaluating the degree to which the competitive market is ensuring reliability and proposing corrective actions if necessary; The Competitive Marketplace -- providing information, evaluation and analysis of the evolving marketplace to ensure full, fair and effective competition throughout the region; Conservation and Renewables -- suggesting regional goals for conservation and renewable resources, tracking and reporting on progress toward those goals and recommending steps to overcome obstacles to achieving those goals; Multi-state Issues -- analysis of resource related issues where the resource affects more than one state, and coordination of multi-state implementation efforts; Fish and Wildlife -- providing a mechanism for public and industry input into fish and wildlife decisions and deciding how those funds derived from the power system are to be spent on fish and wildlife projects; and Public Participation and Involvement- informing and involve interested members of the public on matters that affect them, their environment and their economy.

Questions for Public Comment

YOUR CHANCE TO SPEAK UP

The Comprehensive Review of the Northwest Energy System is heading into the final stretches. Your help in commenting on the draft proposals contained in this report will be very helpful to the four Northwest governors and to the Comprehensive Review Steering Committee. Your voice will help ensure the benefits of a more competitive electricity industry are shared broadly in the Pacific Northwest. There are a number of ways for you to learn about and comment on the draft recommendations:

Workshops and Hearings

A series of 10 workshops and hearings will be held around the region in October and November. The workshops are designed to let you ask questions about the proposal and to hear from representatives of a number of the interest groups involved in the Review.

Hearings will occur in a room adjacent (or close) to the room in which the workshops will occur. Hearings will begin one hour after the workshops and will run until 9 p.m., or as long as people are providing comments (the workshops will run the entire evening, including during the hearings). See Appendix B for the schedule and locations of the hearings and workshops.

Other ways you can learn about or comment on the draft recommendations include:

Write:

Comprehensive Review, c/o Public Affairs, 851 SW 6th Avenue, Suite 1100, Portland, OR 97204.

Be sure to include your name, address and phone number. If you have a fax number and/or an e-mail address, include them.


Fax:

Fax your comments to: Comprehensive Review, c/o Public Affairs. The number is 503-795-3370.


E-mail:

Send your e-mail message to: comments@nwppc.org

Or, add yourself to the Comprehensive Review e-mail list by sending a message to:

listserver@nwppc.org

In the message field, type:

subscribe compreview yourfirstname yourlastname

An example, using a person named John Doe, is:

subscribe compreview john doe


World Wide Web:

Visit the Comprehensive Review's homepage at http://www.newsdata.com/enernet/review/review.html.


DISCUSSION OF THE STEERING COMMITTEE'S DRAFT RECOMMMENDATIONS

THE BONNEVILLE POWER ADMINISTRATION -- ADAPTING TO A COMPETITIVE ENVIRONMENT, PRESERVING THE BENEFITS OF LOW-COST HYDROPOWER FOR THE NORTHWEST

Goals

The Steering Committee's goals for federal power marketing are to 1) align the benefits and risks of access to existing federal power; 2) ensure repayment of the debt to the U.S. Treasury with a greater probability than currently exists while not compromising the security or tax-exempt status of Bonneville's third-party debt; and 3) retain the long-term benefits of the system for the region. The proposal is also intended to be consistent with emerging competitive markets and regional transmission solutions.

Background

The Bonneville Power Administration is a federal power marketing agency charged with marketing the power output of the federal dams on the Columbia and its tributaries. It is a wholesale supplier, marketing power to utilities who, in turn, sell power to retail consumers. The only exceptions are the Direct Service Industries (DSIs) who have historically been served directly by Bonneville. On average, Bonneville markets about 40 percent of the firm power in the region and substantial but varying amounts of non-firm power. Bonneville is required to sell its firm power (the power that can be counted upon even under poor water conditions) to offer contracts to public agency customers (e.g., municipal utilities, public utility districts, cooperatives) and DSIs at cost. Only when it cannot sell all its power within the region is it allowed to market outside the region. As a result of the Northwest Power Act of 1980, Bonneville also has the responsibility of acquiring new resources to meet the loads of those customers who choose to place their loads on Bonneville.

Historically, Bonneville has been a low cost supplier of electricity. In recent years, however, Bonneville's power has lost its price advantage. This has been the result of a combination of factors including low gas prices, surplus generating capacity on the West Coast; the opening of the competitive wholesale electricity market and the resulting decline in electricity prices. Bonneville has also experienced increased costs resulting from requirements for salmon recovery, resource acquisition costs and other factors. Bonneville's ability to reduce costs is hampered by the fact that a large part of its costs are fixed + repayment of debt to the U.S. Treasury for the construction of the hydroelectric and transmission systems and repayment of the debt for three Washington Public Power Supply System nuclear power plants.

The opening of competition has put great stress on Bonneville. Bonneville's utility and DSI customers now have a greater degree of choice under amended or new power sales, and 1981 power sales contracts will be expiring in 2001. Bonneville has been struggling, both as a matter of policy to determine its future competitive role, and to secure sufficient sales to cover its costs and make its payments to the Treasury and the Supply System. The ultimate risk, should Bonneville be unable to cover its costs, lies with the Treasury. While this is occuring, many of Bonneville's traditional customers, particularly those without generation resources continue to look to the Agency as their primary or exclusive power supplier.

In the future, however, conditions are likely to change. Most expect that gas prices and the market price of electricity will eventually rise. In addition, Bonneville's fixed costs can be expected to fall as debt is paid off. When this happens, Bonneville's power would be very attractive. Whether the Northwest will be able to retain these future benefits has been brought into question, in part due to legislation that would sell federal power marketing agencies. Even if Bonneville is not privatized, the revenues that a low cost power producer could generate could be very attractive to future Congresses, particularly if the Treasury has been called upon to bear the risks of the that power producer when conditions are not so favorable. In this context, a long term solution that retains the benefits of the system in the Northwest is deemed highly desirable.

Finally, there is the question of the appropriate role of a federal agency in a competitive market. Right now, Bonneville is struggling to compete. In the longer term, as restructuring proceeds and the electricity industry becomes more and more competitive, the question may no longer be "Can Bonneville compete?" but "Should Bonneville compete?"

Recommendations

Summary

The recommendation made by the Steering Committee is to institute a subscription-based system for marketing the power produced by the federal system. The subscription process would maintain the principles of public and regional preference to the output of the Bonneville system at cost. The subscription system is central to aligning the risks and benefits of the system, and to reducing the risk faced by the Treasury. Treasury currently faces the risk of market prices below cost, but does not receive the benefit when market prices are above costs.

Subscribers would contract to purchase power from the system at cost, take or pay, for the period of their subscriptions, including periods like we are now experiencing, when costs are above market prices. Subscribers would also be able to purchase at cost when costs are below market levels. The power product contracted for could vary depending on the requirements of the customer. One product could be provided for customers with predictable loads ,or who acquire load shaping services from another entity. Alternatively, BPA would offer a take and pay arrangement for customers that want to rely upon BPA to serve their actual monthly loads.

Bonneville would not acquire additional resources to serve load growth except on a bilateral contract basis, where the customer absorbs the risk. However BPA could offer short term products and services that are responsive to variations in loads from planning estimates to those customers willing to pay for such services. Moreover, if the system is fully subscribed, there would be no need for Bonneville to market to retail loads.

Subscribers would gain advisory influence over power-related costs and would have the ability to call for binding arbitration on certain cost issues under their contracts.

There is an emphasis on long term contracts. To make such contracts salable, customer responsibility for any additional fish related costs above existing levels are specified on a shared basis up to a customer ceiling. In turn, when BPA costs are below market, a portion of this difference is returned to the US Treasury.

Disposition of Federal Power

Long term subscriptions provide stability to BPA, the Treasury and customers. However, a number of customers, particularly those without generating resources, may want to place much of their loads in shorter term intervals as they make the adjustment to new competitive markets. For purposes of this model, long term is considered to be 30 years, similar to a license for a generation project. Short term is considered to be 5 years. The firm energy capability of the Federal system subject to some form of allocation is about 8,000 aMW. For overall stability, a minimum of 5,000 aMW or more needs to be longer term contracts, representing more than 60% of the entire system.

Long-term subscribers get the right to purchase power at cost for the term of the contract, up to 30 years. While the cost of the power from the federal system is currently somewhat above market prices, the cost is generally expected to be below market prices in the future.

Short-term subscribers also get the right to purchase power at cost, paying the same general costs as the long term customers. However, the short term subscribers are required to pay a "subscription fee", earlier referred to as an "option". The subscription fee would enable the customer to either extend their cost-based contract, or to reduce or terminate loads on BPA at the end of the existing contract commitment. The subscription fee is a premium payment reflecting the risk to the system of some degree of customer instability. The subscription fee should be priced to both reflect its value, while at the same time not making it economically and competitively prohibitive. An option fee of 1 mill per kilowatt hour or slightly more (about 5% of the projected power cost) has been proposed. Short-term subscribers could continue short term in the future by purchasing subsequent subscription fees, or convert to long term power for the balance of the long term contract period without subsequent subscription fees.

The subscribers assume a greater level of risk than in the current system. For example, if we were to experience lower than expected market prices that are below Bonneville costs for an extended period of time, the long term subscribers would still be obligated to pay Bonneville's costs. Short-term subscribers would be able, at the end of their subscription period, to let their subscriptions lapse, but may elect to stay, hoping to realize the longer term savings associated with the system. There would be a high level of annual probability of Treasury payments, placing more risk of the effects of year to year variations in weather, future power system cost increases (e.g., the cost of generator rewinds and other necessary maintenance and upgrades) and changes in market conditions on the customers.

The process for the disposition of federal power should be completed by 2001, so that the results can be in place when Bonneville's existing contracts expire. The term of the contracts would be determined by the individual subscribers, during their initial subscriptions for firm power. Firm power would be subscribed for by month with appropriate ancillary delivery services. Any remaining firm power and other products should be sold at market prices whenever possible and the revenue used to reduce costs to the subscribers.

At the end of the contracts, long-term purchasers and those who have continuously renewed their short-term contracts would have the first right of refusal to renew contracts for subsequent terms. The initial subscription, and any subsequent ones, would follow a specific priority order. Any power that is freed up as a result of non-renewal of contracts would be offered at cost through the same priority structure to all long-term subscribers within the priority structure described below. Subscribers who have let their subscriptions lapse would not be guaranteed the ability to buy at cost in the future.

Priority for Subscriptions

The priority order for subscriptions would be implemented in a sequential multi-phase process. Customers could elect to split their subscriptions between long- and short-term contracts subject to constraints.

Phase 1

The first phase would be reserved for publicly owned utilities to subscribe up to contractual entitlements of the highest two consecutive years of the 1997-2001 contract period. The public utilities would be split into two groups based on their end-use loads, regardless of supply source: 1) utilities with loads 50 aMW and over and 2) utilities under 50 aMW. Each group would subscribe first for long-term contracts and then for short-term contracts, with no priority between the two groups of utilities. For the over-50 aMW group, the long-term subscriptions would have to be at least 60 percent of the total subscribed load being placed on Bonneville by this group (not the subscribers total load) and for the under-50 aMW group the long-term subscriptions would have to be at least 40 percent of the total subscription.

These thresholds apply to each group as a whole. As long as the group meets the target, individual utilities within the group do not need to. However, the two groups (over- and under-50 aMW) are treated separately. If the groups do not meet the collective targets, the individual utilities within each group that do not meet the targets must adjust their subscriptions, either by switching short-term to long-term, or by reducing their short-term subscriptions till the groups meet the targets.

When this first subscription has been accomplished, all the public utilities have the opportunity to subscribe again, before going to other classes of customers. The utilities must start from their previous final positions and can only add subscriptions, with the same rules for proportions of long- and short-term subscriptions applying to the final set of subscriptions. The same process for adjusting excess short-term subscriptions also applies.

Phase 2

During the second phase, the DSIs and the residential and small farm customers of the IOUs (through their representatives, described below) would be allowed to subscribe. The DSI subscriptions would be limited by contractual entitlements of the highest two consecutive years of the 1997-2001 contract period. The IOU customer subscriptions would be limited by their total regional load of the residential and small farm customers.. There would be no priority between these two groups. The process would be the same as for the two groups of public utilities described in Phase 1. Each group would subscribe first for long-term and then for short-term subscriptions. The threshold for both groups would be 60 percent of the subscribed load long-term. Individual subscriptions might not meet the threshold requirement as long as each group total met the threshold. If either of the collective subscriptions (DSIs as a group, IOU customers as a group) did not meet the threshold, the non-conforming customers in the group would have to adjust, by switching short-term to long-term, or by reducing the amount of short term, until the group proportion met the threshold. If more firm power was subscribed to than was available for subscription in Phase 2, subscriptions would be reduced, pro rata on the basis of loads, within Phase 2.

For the purposes of the subscriptions, IOU residential and small farm customers could be represented by investor owned utilities (IOUs) or non-utility aggregators that have Northwest residential or small farm loads, as certified by state regulators. The benefits of purchases for these customers would have to be passed through to the end users.

Following the subscriptions by the DSIs and IOU residential and small farm consumers, other regional wholesale entities would be allowed to subscribe up to the limits of their historical load (not loads on Bonneville). These customers would most likely be representatives of IOU commercial and industrial consumers. They would have the same requirement for a 60 percent/40 percent split of their total subscriptions between long- and short-term subscriptions. The same process as described above for other customer groups, including pro rata allocations if necessary, would apply.

Phase 3

Phase 3 is for long-term subscriptions only. There are no limits on how much could be subscribed by any individual subscriber. Unlimited subscriptions are made available, first to publicly owned utilities, second to DSIs and residential and small farm customers of the IOUs, and third to other regional wholesale suppliers for regional loads. Pro rata allocations on the basis of the desired subscription amount would be applied at each step if necessary.

Phase 4

Phase 4 is for short term subscriptions only. There are no limits on how much could be subscribed by any individual subscriber. Unlimited subscriptions are made available first to publicly owned utilities, second to DSIs and residential and small farm customers of the IOUs, and third to other regional wholesale suppliers for regional loads, all for short-term subscriptions. Pro rata allocations on the basis of the desired subscription amount would be applied at each step if necessary.

Phase 5

The fifth phase of subscriptions is for non-regional entities and non-regional loads. It does not have any limits on subscriptions and allows either long- or short-term subscriptions. Public preference would apply outside the region, and pro-rata allocation would apply, first among public utilities, if necessary, and then among all other subscribers, if necessary. The power would be priced at cost.

Subsequent Subscriptions

To the extent firm power becomes available as a result of non-renewal of contracts, the remaining power will be offered for long term subscription through the same multi-phase process described above, expanded by any new public utilities that may have formed in the interim. Customers who elect not to subscribe to BPA, or who subsequently allow short term subscriptions to lapse would not be guaranteed the right to new subscriptions or to purchase at cost in the future. Contracts would not be subject to recall, for preference or other reasons, once signed.

Resale

Subscribers may resell the power for which they have subscribed. The Steering Committee did not reach consensus on whether options should be resalable and specifically seeks comment on this question. Arguments against resale are the following:

Arguments in favor of resale are the following :

The Exchange

As a result of the Northwest Power Act of 1980, Northwest utilities have the right to sell to Bonneville an amount of power equal to that required to serve their residential and small farm customers at the utilities' average system costs and receive an equal amount of power at Bonneville's average system cost. In reality, this is an accounting transaction. No power is actually delivered. This was intended to be a mechanism to share the benefits of the low cost federal hydro system with the residential and small farm customers of the region's investor owned utilities. As a result of decisions made by Bonneville in its most recent rate, those benefits have been reduced. The regional review acknowledges that the residential and small farm consumers of exchanging investor-owned utilities will be adversely impacted by the reduction of exchange benefits. The review encourages the parties to continue settlement discussions and to explore other paths to ensuring that residential and small farm loads receive an equitable share of the benefits of the federal base system.

Treatment of Fish Cost Risk to Subscribers

In Order for BPA to effectively market long term contractual commitments to customers who are required to pay all costs as specified in their power sales contracts, there needs to be parameters established in advance on the degree of financial risk for potential additional fish mitigation. This is particularly true if the mitigation imposed is beyond the control of the customers. However, establishing a maximum level of funding for fish measures may be politically or legally unacceptable and could be an impediment to recovery.

The discussion of fish risk is presented in the context of potential contractual obligations of the customers and Treasury. Therefore, none of the following discussion is an endorsement or recommendation of any level of funding for fish mitigation. That issue will be decided in other forums and be other parties.

This proposal is built upon the premise that the costs of any additonal measures above the National Marine Fisheries 1996 Biological Opinion and the fish cap in BPA's current rates should be shared between the customers and the US Treasury. Further, this sharing should be on a roughly 50-50 equivalent basis. There would, however, be a limit, or a cap on the customers' responsibility that reflects substantial additional costs. These costs, in aggregate (customer and Treasury shares combined), are on the order of $450 to $500 million in today's dollars above the cost of current measures. Further analysis of these numbers is required. Further spending above this amount would be the responsibility of the US Treasury. It is assumed that any contributions by Treasury will come in the form of appropriations rather than any deferral or forgiveness of other BPA obligations.

Many alternative approaches are available for cost sharing. It could be dollar for dollar. Alternatively it could be a sliding scale where customers pay a higher percentage of the initial measures and a declining percentage to a capped figure at a lower level. For purposes of ease of understanding, it is recommended that customer expenditures above the existing fish cap be on a 50-50 basis with Treasury up to the limit of the customers' responsibility.

It is important to note that the customer "risk" for fish is limited to about 15% using a BPA generation revenue requirement of $1.65 billion. To the extent that over the 30 year period there are major changes in the size of the generation revenue requirement, or due to the effects of inflation, the issue of the cap may have to be periodically revisited, as long as the rules of doing so are known in advance and spelled out in the contracts.

Since the Treasury has the potential in this proposal of taking on additional risk associated with fish mitigation, there needs to be an incentive for their participation. Because BPA's rates are currently above market there may be few financial incentives immediately available. However, there is a high likelihood that BPA's costs will fall below market, and that major savings will be available with the retirement of BPA's third party debt, making the second half of a 30 year period look extremely attractive. In years where BPA's costs based rates are below market, it is recommended that 20% of the difference between cost and market be returned to the Treasury as a supplemental payment, beyond all other BPA obligations. In essence customers would be agreeing in their contracts that BPA could recover through rates an additional 20% of the difference between an indexed market rate and a cost based rate (when lower.)

In summary, the Treasury would be paid 20% of the difference between cost based rates and market rates each year when costs are below market. In exchange Treasury would agree that in each year of the contract they would pay 50% of additional fish recovery measures, and the full amount above an agreed upon ceiling.

Treasury also has another element of risk. To the extent short term customers decide not to renew contracts, perhaps due to fish costs or for other reasons, while BPA's costs are above market there is an opportunity for some shortfall in revenue. This shortfall is the difference between BPA's costs and the revenues they would receive from selling this abandoned power in the open market. This risk is in part contained based upon the assumption that at least 60% of the system will be allocated to long term subscribers. To the extent there is a shortfall associated with termination of contracts any such accumulated shortfall should be repaid to the Treasury. The mechanism to make this repayment would be the rates charged to the eventual subscribers who sign up for the abandoned power.

Customer Advisory Committee

Customers, particularly those signing up for long term commitments, need to have an effective mechanism to assure them that BPA's revenues and costs over time reflect the intent of their power sales contracts. Existing federal legislation allows for appointments of advisory committees to assist agencies such as BPA, without exercising formal governance responsibilities. The BPA administrator would still technically report to the Department of Energy, but would receive strong customer input through an Advisory Committee. The Committee would consist mainly of subscribers and would include representatives of other interests. The committee would have oversight of the budget requests, of overall capital budgeting levels and operating cost levels, rate setting, key marketing issues, and input into the power-related capital and operating cost decisions of the Corps of Engineers and the Bureau of Reclamation. The committee would provide input to decision-making authorities on fish-related matters. However, it is assumed that final determinations regarding fish measures are within the purview of the existing of future mechanism for river governance.

Although the Advisory Committee should be helpful in establishing policy direction for the power operations of BPA, it is not the primary or exclusive mechanism for subscribers to determine their business relationship with BPA. New power sales contracts will define the nature of the business relationship between BPA and individual customers. These contracts will both have common features and unique characteristics depending upon the types of services the customer is buying from BPA. It is recommended that the contracts contain an ability for subscribers to call for binding arbitration on specific power cost-related items.

Bonneville in the Competitive Market

The proposal would also have the effect of constraining the role of the Bonneville Power Administration in the competitive market. The fact that most of Bonneville's power would be subscribed at cost would limit Bonneville's market role. In addition, Bonneville would not acquire resources to serve load growth of its customers except on a direct bilateral basis where the customer takes on all the risk of the acquisition. However, Bonneville would be making spot market power purchases sufficient to both 1) supplement monthly firm hydro energy in meeting current firm loads and 2) store water for flow augmentation. The proposal distinguishes these purchases, which are not necessarily required to be on a bilateral contract basis, from purchases to meet load growth, which are required to be on a bilateral contract basis.

Finally, Bonneville would not sell directly to new retail loads, beyond the existing DSI loads, though it may sell through intermediaries whose transactions would be subject to state or local jurisdiction.

Questions for Public Comment

In addition to requesting comment on all aspects of the proposal, the Steering Committee specifically requests comment on the following questions:

CONSERVATION, RENEWABLE RESOURCES AND LOW INCOME ENERGY SERVICES: REFLECTING THE VALUES AND MEETING THE NEEDS OF NORTHWEST CITIZENS

Goals

The Steering Committee has three clear goals for conservation, renewable resources and low income energy services:

The Steering Committee prefers that its goals for conservation and renewable resources be achieved by relying, wherever possible, on market forces to accomplish cost-effective conservation and renewable resources. However, the Committee recognized that the market for energy efficiency services is not fully mature and that potentially valuable renewable resource technologies are not currently economically competitive. It also recognized that competitive markets are highly unlikely to provide households with limited incomes with means to meet those basic services now supplied by electricity. The Steering Committee concluded that during the transition to a competitive electricity market (and perhaps longer), the region's electric utilities should continue to commit a minimum amount of their revenues to facilitating the development of cost-effective conservation, preserving renewable resource options and sustaining low income energy services.

Background

Conservation

For nearly two-decades electric utilities in the Northwest have been the dominate force behind the development of conservation. The rationale for their active pursuit of conservation stemmed from the fact that until quite recently the cost of new power generation exceeded the price they charged consumers for electricity. Serving new loads raised everyone's prices. Therefore, when utilities acquired conservation at a lower cost than new generation, the total cost of electricity for all consumers was less.

Conservation faces a radically different environment today than it did just a few years ago:

Despite these changes, it is estimated that there remain to be developed substantial amounts of conservation which cost less than the alternative sources of power. In its 1996 Draft Plan, the Northwest Power Planning Council estimated that approximately 1500 average megawatts of conservation would be cost-effective to develop in the region over the next twenty years. There is some controversy about these estimates. However, even taking into account the uncertainty surrounding those estimates, the amount of cost-effective conservation remaining to be developed is large enough to warrant trying to ensure that it is developed.

There is currently some momentum behind conservation acquisition. This momentum is created by existing utility activities and the funding already committed to those activities and operation of market forces. It is estimated that this momentum will probably prompt the development of approximately one-third of the 1500 average megawatt potential over the next few years. However, the annual rate of conservation development is projected to decline significantly. By the year 2000, it is estimated that the rate of conservation development as a result of both utility programs and the actions of the market will well below that required to develop the full cost-effective conservation potential.

The question then is, what happens after the turn of the century? Many of the market barriers to development of conservation resources - inadequate information, split incentives, and so on - still exist. The Review expects the competitive market for efficiency products and services to be stimulated by the opening of competition. However, the industry is still immature. The experience from countries that have already opened up their electricity markets seems to indicate that the market for these products and services will not develop quickly without special attention.

It is estimated that, after taking into account the conservation expected to be developed by utilities and market action between now and 2000, there remains approximately 70 average megawatts of cost-effective conservation to be developed per year through the year 2016. The total cost of developing that conservation averages approximately $165 million per year. For purposes of comparison, in 1995 when the region's expected cost of the electricity that could be avoided by conservation investments was nearly double today's, Bonneville and the region's utilities invested approximately $330 million in conservation, generating just over 120 average megawatts in savings.

Renewable Resources

Renewable resources can offer unique social and energy system benefits. These benefits include environmental value, such as the avoidance of carbon dioxide emissions that may be contributing to global climate change; resource diversity; and local economic benefits which might not be reflected in the resource's price. Some applications of renewable resources, for example the use of solar photovoltaics in remote locations, are cost-effective today. However, as "utility-scale" generation, current solar, wind and geothermal technologies are more expensive than present gas-fired combustion turbine alternatives. For example, a number of demonstration projects involving wind and geothermal resources are underway in the region pursuant to the Northwest Power Planning Council's renewable resource confirmation agenda. As a result of recent declines in the market price of power, these projects are anticipated to produce power that is from one and one-half to four times more costly than current market prices, with the wind projects representing the lower end of this range. In an increasingly competitive electricity market, renewable resources may not be developed unless their economics improve or consumers are willing to purchase their power at somewhat higher prices that reflect renewable resources' non-market benefits through "green power" marketing.

Though few renewable are cost-effective in the near-term, ensuring that renewables are available for development may have appreciable economic value in the future. An unexpectedly rapid rise in natural gas prices and/or the adoption of carbon dioxide control measures could alter the economics of renewables. For instance, in its 1996 Draft Plan, the Northwest Power Planning Council found that the imposition of a carbon tax of $40 per ton in the year 2005 could increase the lifetime benefits of developing renewables in the Northwest to just under one billion dollars. Footnote1

Low Income Energy Services

Programs to ensure that low-income consumers are adequately and fairly served are comprised of a combination of 1) energy efficiency services, 2) energy assistance, and 3) customer service practices. Energy efficiency services includes traditional weatherization, creative efficiency programs, and consumer education. Energy assistance includes emergency assistance, rate discounts, percentage of income payment plans, fuel funds, traditional payment assistance programs such as the federal Low Income Heating Energy Assistance Program (LIHEAP), and integration of services with other social service agencies.

It is estimated that approximately 14 percent of the households in the Northwest have incomes below 125 percent of federal poverty guidelines. This amounts to 540,000 households. About 55 to 65 percent of the dwellings occupied by low income households that are heated with electricity have yet to be fully weatherized. This translates into between 165,000 and 235,000 electrically heated homes, apartments and mobile homes that are not as energy inefficient as they should be. This means higher electricity bills for those who can least afford them.

Historically, low income energy service programs have been funded from a combination of federal, state and utility sources. In 1995 roughly $19 million per year was provided for low-income weatherization assistance in the region. The region's utilities and Bonneville are providing about 40 percent ($7 million) of these funds. Also in 1995, approximately $39 million was provided for bill payment assistance of some type. The region's utilities provided about 40 percent ($16 million) of this assistance with all of the remaining funds coming from federal sources.

In recent years there has been a substantial reduction in the level of federal contribution to these programs. For example, federal funding of LIHEAP in Washington State was reduced by 42 percent between 1994 and 1995. State and utility contributions have not increased to offset the reduction in federal funding.

Recommendations

To ensure that cost-effective conservation, renewable resources development and low-income weatherization are sustained during the transition to competition and beyond, the Comprehensive Review recommends that 3 percent of the revenues from the sale of electricity services in the region be dedicated to those purposes for a period of ten years. Footnote2 Based on 1995 revenues, this amounts to approximately $210 million per year. $210 is 57 percent of what was spent for these purposes in 1995.

The Review believes that most of these funds are most appropriately used at the local level. Consequently, the Review recommends that two thirds of the funds be retained by local distribution utilities to carry out locally-initiated cost-effective conservation and low income weatherization. Some conservation and renewable resource activities can, however, benefit from regional planning and coordination. The Review recommends that one third of the funds be used by a regional non-profit agency with utility, government and public interest membership. Its functions would be to bring about changes in the markets for targeted energy efficiency and renewable resource products and services that will improve their market share; to plan and contract for research and limited demonstration of renewable energy technologies to support the development of renewable generating capacity. A Regional Technical Forum would be established to set goals and track and evaluate implementation of conservation and renewables in the region. The approximate allocation of funds to different purposes is shown in Table 1. The specific recommendations are described in detail in the following sections.

Table 1

Annual Allocation of funds to Conservation, Renewable Resources, and Low Income Energy Services

Purpose

Percent of electricity revenues

$ Millions based on 1995 electricity revenues

Local Conservation

1.6%

$110

Low-Income Weatherization

0.4%

$30

Total - Local Implementation

2.0%

$140

Conservation Market Transformation

0.43%

$30

Renewables Market Transformation - new projects

0.49%

$34

Renewables Research

0.014%

$1

Renewables Development and Demonstration

0.071%

$5

Total - Regional Implementation

1.0%

$70

Total

3.0%

$210


Conservation

The Steering Committee considered a variety of options for ensuring that a large proportion of the roughly 1000 average megawatts of cost-effective conservation potential that remains is captured. These ranged from total reliance on market forces to the adoption of a distribution system access fee to fund regional and local conservation investments.

Conservation was divided into two areas for action: local and regional conservation. "Local conservation," covers those actions designed to influence on-site consumer efficiency choices. Local conservation also includes low income weatherization activities Regional actions include the establishment of a "regional technical forum" and a non-profit entity to carry out conservation market transformation.

Local Conservation, Including Low Income Weatherization

The Steering Committee recommends that the region's retail distribution utilities commit to allocating at least two percent of the revenues from sales of electricity and distribution services towards the development of cost-effective conservation and low income weatherization services for the next ten years. To the extent possible, tariffs to collect these funds should be implemented simultaneously with implementation of open retail access. Based on current electricity revenues, this is anticipated to generate approximately $110 million per year in conservation investments and $30 million per year for low income weatherization investments in the region. Retail distribution utilities may be credited for documented conservation investments made by their large customers. The Steering Committee recommends that these large customers have the option of receiving credit for documented conservation investments in their facilities up to the equivalent of their share of the local distribution utility's revenue commitment to conservation, excluding low income weatherization.

For purposes of tracking regional progress on conservation and low income weatherization, the Steering Committee recommends that all retail distribution utilities adopt and publish an annual report of their conservation and low income weatherization achievements. The Committee also recommends that utilities make this report available to the non-profit entity to be established to carry out regional market transformation for conservation and renewable resources. This report should identify at least the amount of conservation achieved by economic sector, the number of dwellings occupied by low income households that were weatherized and level of utility investment in these areas.

Regional Technical Forum

The Steering Committee recommends that a Regional Technical Forum (RTF) be established. The RTF should set regional goals for conservation and renewable resources, track regional progress toward the achievement of these goals and provide feedback and suggestions for improving the effectiveness of conservation and renewable resource development programs. The RTF should also conduct periodic reviews of the region's progress toward meeting its conservation and renewable resource goals no less frequently than every five years. The RTF would be composed of representatives of utilities, other electricity services providers, government and public interest groups.

Market Transformation

The Steering Committee recommends that the region's retail distribution utilities should, as soon as possible, mount a coordinated effort to transform markets for efficient technologies and practices. Footnote3 The intent of market transformation is to undertake activities that will increase the market share of targeted efficiency products and services that will be sustained after incentives or other support are withdrawn. Because markets invariably cut across utility and jurisdictional boundaries, it makes most sense to pursue these efforts at regional scale. This effort should establish a non-profit entity to manage conservation market transformation ventures for the region. This entity's governing body should consist of utility, government and public interest representatives. This entity should have a planned life of at least ten years in recognition of the time required to permanently transform markets, and the range of markets or end-uses to be targeted. Initial funding should come from approximately equal contributions by Bonneville and the region's investor-owned utilities. The Steering Committee recommends that long term funding of the region's market transformation ventures for conservation should be provided by direct contributions from the region's retail distribution utilities. It recommends that the region's retail distribution utilities commit to contributing approximately 0.43 percent of electricity revenues towards regional market transformation efforts. This is anticipated to provide approximately $30 million per year for conservation market transformation.

Renewable Resources

Similar to conservation the Steering Committee considered a range of options for meeting it's goal for developing renewable resources in the region. The Committee's draft recommendations for renewable resources are described below.

Existing Renewable Resource Projects

The Steering Committee recommends that current sponsors should complete wind and geothermal demonstration and pilot projects. Funding these projects, estimated to cost between $30 to $45 million per year, is the responsibility of the respective project sponsors and is not included as part of the 0.49 percent of revenues to be committed to the development of new renewable resources.

New Renewable Resource Projects

The Steering Committee also recommends that renewable resource market transformation activities be planned and carried out by the newly established non-profit entity charged with conservation market transformation. Renewable resource market transformation activities should focus initially on the development of solar, wind and geothermal renewable resources. The intent is to further develop what are now "immature" technologies. Depending on the success of "green marketing" to consumers in the region additional renewable resource development may occur. The Steering Committee recommends that long term funding of the region's market transformation ventures for renewable resources should be provided by direct contributions from the region's retail distribution utilities. It recommends that the region's retail distribution utilities commit to contributing approximately 0.49 percent of their retail revenues towards regional market transformation efforts for renewable resources for the next ten years. It is anticipated that this will provide approximately $34 million per year in contributions from retail distribution utilities.

Renewable Resource Research, Development & Demonstration

The Steering Committee recommends that the region's retail distribution utilities commit to allocating less than 0.1 percent of their retail revenues needed to provide $1 million per year for research, and $5 million per year for development and demonstration of distributed renewable resources. Local distribution utilities should contribute these funds to the non-profit entity established to carry out market transformation for conservation and renewable resources.

Green Marketing

The Steering Committee recommends that retail distribution utilities should provide for "green marketing" (i.e., the sale of qualifying renewable resources) to individual consumers in advance of full retail open access. Retail distribution utilities may accomplish this by offering their retail consumers "green resources" or by permitting other energy service providers to sell "green resources" to their retail consumers.

Low Income Energy Services

Low Income Energy Assistance

The Steering Committee recommends that utilities maintain their current level of low income energy assistance (estimated to be at least $16 million/year) until such time as states adopt mechanisms for providing these services. It is estimated that total regional need for low income energy assistance is in the range $60 to $107 million per year. The Steering Committee recommends that states consider alternatives for providing this assistance which include, but are not limited to the following options:

Universal Electrical Service Fund - This approach establishes a "Universal Electrical Service Fund" to provide energy bill assistance. This fund could be supported by a retail distribution system access fee (meters charge), electricity supplier access charge or from general purpose government funding, including federal LIHEAP funds and other funds. Qualified low income (i.e., incomes 125 percent or less of the federal poverty level) customers would be entitled to receive from all electricity suppliers the bill assistance or rate discount needed to ensure that they do not pay more than a fixed proportion (e.g., five percent) of their income for electric energy services. All electricity suppliers could draw from the "Universal Electrical Service Fund" to provide the bill assistance needed to serve each qualified low-income customer, plus a standard administrative cost. Existing retail distribution utility low income energy assistance program expenditures could be credited towards any required contributions to the Universal Electrical Service Fund.

Portfolio Standard for Low Income Service - This approach attempts to vest low-income customers with "market value" rather than a burden to be avoided. Under this approach all licensed electricity suppliers would be required to serve a minimum proportion of qualified low-income (e.g., 125 percent of federal poverty level) customers as a condition of maintaining their license. Footnote4 Electricity suppliers who served above the minimum share could be permitted to sell their excess as "service credits" to other suppliers who had yet to achieve the minimum. In this approach the cost to serve the minimum proportion of low income customers would be internalized as cost of doing business as an electricity supplier. How the supplier recovered any additional cost to serve low income customers would be left to the supplier as would how they managed to maintain their minimum proportion of low income customers. If the supplier failed to maintain service to the minimum their license could be suspended.

Exemption from Charges

The Steering Committee recommends that qualified low income consumers should be exempted from paying local distribution utility charges that are adopted to support conservation, renewable resources and low income energy services.

Collecting and Allocating the Funds

The Steering Committee's proposal relies on the voluntary commitment of the utilities and regulatory commissions to authorize and carry out the collection, disbursement and appropriate use of the funds. State or federal legislation to require collection and allocation of the funds to support regional market transformation efforts for conservation and renewable resources, regional research, development and demonstration of distributed renewable resources, local conservation and low income energy services is not proposed at this time. The Steering committee believes that a voluntary, local adoption system will work. During the public comment period on the draft recommendations the Steering committee will test the quality of utility commitment. Actions such as tariff filings, board resolutions or ordinances would be helpful in providing evidence of such commitment. If it is determined to be necessary, there are mandatory alternatives that could be pursued. Footnote5

To the extent possible, the steering committee recommends that tariffs to collect these funds should be implemented simultaneously with implementation of open retail access. However, the steering committee makes no recommendations as to how individual utilities should collect the funds, i.e., through a charge based on volume of kilowatt-hours sold, through a distribution access charge that is independent of or less directly related to kilowatt-hour sales, or some other method. The Steering Committee is relying on the appropriate regulatory bodies to establish an appropriate method of collection. The Committee is mindful, however, of the fact that how the charge is collected can have effects on both equity between customers and the competitive balance between different suppliers or fuels. The Committee is also aware that significant differences in how the charge is collected between distribution systems can alter the competitive balance between systems. The Steering Committee believes that regulatory bodies will find it preferable to collect these charges in ways that do not distort competitive balance.

Questions for Public Comment

CONSUMER ACCESS TO THE COMPETITIVE MARKET: ENSURING THE BENEFITS OF COMPETITION FOR ALL

Goal

The goal of the comprehensive review steering committee recommendations on retail markets and customer choice is to encourage a more efficient power system, lower electricity costs, and increased product choice and greater product innovation for all consumers. These were adopted subject to a commitment to maintain the reliability and safety of the electrical power system. The steering committee concluded that this goal could best be accomplished by putting in place a competitive electricity market that is driven by consumer choice. This section describes the background of facts and trends which led to this decision, then describes the recommended vision of a competitive retail electricity market driven by consumer choice, and finally lays out several steps that should be taken to accomplish a transition to this competitive market by 2001.

Background

The steering committee decisions about competition and customer choice in the retail electricity markets were made in the context of the changes already occurring in regulation, legislation, and electricity markets themselves. The changes that affect retail markets are more recent than the changes in the wholesale markets, but they are a natural extension of those changes. FERC Order 888 will force open the wholesale markets for electric power, but that order left decisions about retail electricity markets to the states.

During the past year, most states have initiated processes to address the question of retail competition. A variety of conclusions have been reached. Some states, such as California, have established schedules and passed legislation for moving to retail competition. Others, such as New Hampshire and Illinois, have developed pilot programs to test the feasibility of retail competition in electricity. Others have allowed retail wheeling rates for large customers on a case-by-case basis. There is enough action at the state level on retail competition to establish a perception of tremendous momentum toward a more competitive retail electricity market. "It's inevitable," was a phrase heard often during the comprehensive review process.

In spite of the high level of state activity in this area, or perhaps because of the uneven progress by states, national legislation has been introduced to require retail competition in electricity markets nation wide. Rep. Dan Schaefer (R-CO) introduced a bill entitled "The Electricity Consumers' Power to Choose Act." This bill would give all consumers the right to choose their electric service provider by December 2000. A similar bill, the "Electric Power Competition Act of 1996," has been introduced by Representative Edward Markey (D-MA).

The strong momentum toward retail competition reflects the current feasibility of some large consumers acquiring their own electricity supplies in the wholesale market. Prices of wholesale power often are below the price industries are paying their local utility and the potential savings are an important factor in businesses' bottom lines. Large users are quick to point out that they buy almost nothing at retail except for electricity. Similarly, power marketers are anxious to provide power and services to large customers. Both energy marketing companies and large users support more open retail power markets.

Opening up retail markets only to large users, however, is highly controversial and would, in all likelihood, limit the potential benefits that could be gained from more active competition. The major concern is that additional costs would fall on small captive customers as a result of large consumers acquiring their electricity elsewhere and leaving stranded costs behind. Without some agreement on how to recover stranded costs, there is a clear temptation to pass those costs on to captive customers.

The surest way to prevent shifting of costs to small captive customers is to free them to acquire their power supplies from alternative sources, just like the large consumers. When consumers have choice among electricity suppliers it is very difficult to subsidize other consumers at their expense. However, unlike the wholesale market, there is currently no well developed competitive retail electricity market. There are many important issues to be addressed and several technical problems to be solved before a widely available retail electricity market can be developed.

One of the major concerns raised is that of continued universal service at affordable prices. Reliable electricity supplies are a fundamental component of modern lifestyles and public safety. Some are concerned that few competitive electricity suppliers will come forth to serve small consumers, especially low income consumers, at affordable rates. There may be increased need for consumer protection standards and information and education to help consumers make decisions about a product that is invisible, but essential to modern life. Some form of oversight may be needed to ensure a truly competitive retail market and to keep separate the regulated and competitive portions of the electricity system. And more sophisticated billing and metering systems will be needed to keep track of the vastly increased number of participants in the market.

Some of these problems are best solved by allowing the market the opportunity to develop. Others require government intervention and oversight. The steering committee proposal attempts to balance these two categories of need by allowing the market to develop while, at the same time, specifying solutions to important social concerns that arise with retail competition and setting an ambitious target to achieving full retail competition.

Recommendation

The basic recommendation of the steering committee can be stated very simply. All retail distribution utilities should be prepared to accommodate open retail market access for all consumers by the year 2001. The implications of this statement are far reaching, however. It will completely change the structure of the retail electricity market. It implies significant actions by not only utilities, but state legislatures, regulators, and local governing boards of consumer-owned utilities. These recommendations are offered with the intent of aiding the appropriate regulatory bodies as they address these issues.

In order for consumers to have real choices in electricity supply, they must have unimpeded access to alternative electric service providers. Similarly, new energy service providers must have access to consumers through the local distribution system on a non-discriminatory basis with no advantage to the incumbent utility. The only way to effectively ensure these conditions are in place is to require division of the incumbent utility into two separate business lines; one a regulated electricity distribution utility, and the other an electricity service company that competes on an equal basis with other energy service providers. The steering committee concluded that legal divestiture of the energy services component is not required given that adequate regulatory safeguards are in place to assure independence of the two businesses. Some companies may find it advantageous to legally separate, but the steering committee recommendation does not require it.

Electricity distribution utilities

Thus, two new businesses would be created from the current electric utility. One will continue to be a regulated monopoly. It will be an electricity distribution utility responsible for the safe and reliable delivery of electricity over the network of local distribution wires. This utility will have an obligation to connect any consumer to the electricity grid, but will not ultimately be responsible for acquiring the electricity that it delivers. The distribution utility will provide open and non-discriminatory access to the local distribution grid to any electricity supplier. The distribution utility may be the point of collection of funds to support public purposes such as conservation, renewable resources, stranded cost recovery, and low income weatherization and bill support. Initially, the distribution utility may provide metering and billing services on an unbundled basis; that is, with the separate components of the electricity costs itemized. However, metering and billing may ultimately become a separate competitively provided service.

Electricity service companies

The other business, electricity services, will be a competitive industry. The affiliate of the current retail electric utility, after separation from the distribution business, will complete with other electricity service providers to serve end-use customers. This company will offer a variety of electricity products and services to consumers in an effort to win as many customers as possible, or as suit its business strategy. It may rebundle such separate products and services as bulk electricity supply, transmission, shaping to load patterns, reserves, and distribution. The transmission and distribution would be acquired from the regulated utilities that provide such services, while the electricity generation, shaping and reserves may be bought in the competitive power generation markets or supplied from plants that the company owns. The electricity service company will probably utilize various financial derivatives to provide risk mitigation services such as fixed price products. It may not have any defined service territory or be limited to only one line of business. It may offer natural gas, oil, energy efficiency services, and even cable television along with its electricity products. Due to the nature of electricity, the electricity service company will probably be licensed by the state or local authorities and subject to consumer protection standards. The steering committee recommended that the federal power marketing agency not compete in this competitive retail energy services business.

Policies for structuring competition

The steering committee developed a number of policy guidelines for state and local policy makers to implement in order to be ready for retail competition by 2001. These were referred to as market maintenance procedures because they are intended to facilitate the efficient and fair operation of a competitive retail electricity market. Many of these guidelines are concerned with putting consistent requirements in place for all market participants.

Registration and licensing standards

Consistent registration or licensing standards should be established for all market participants sufficient to protect consumers and the delivery infrastructure from abuse. Regulators or local agencies should be equipped with the authority to correct abuses should they occur, by reviewing and revoking licenses or by assessing financial penalties.

All market participants serving small residential and commercial consumers should fall fully within the jurisdiction of state consumer protection laws and regulations. Consumer protection legislation and regulations should be adopted or applied to address issues including but not limited to: credit terms, disconnection of service, standardized billing information, redlining and discriminatory pricing, unfair trade practices and fraud, service quality, and consumer privacy.

Electricity bills

Standardized information should be available on monthly bills, or other appropriate media, which would convey information about the provider's resource portfolio, environmental characteristics of that portfolio, and a consumer satisfaction index. If itemized costs appear on consumer bills, disclosure should be complete, not partial. For example, charges for stranded cost recovery, transmission, distribution, low-income assistance, generation by type, DSM, and renewables should be included. Energy bills should include a place for the consumer to lodge complaints concerning service abuse. A neutral resolution mechanism for disputes between consumers and their energy service providers should be established within regulatory bodies or local agencies.

Balanced competition

Policies should be established to ensure that competition between established power providers and new market entrants is based on the value of services and products provided to the consumers and not on variations in the regulatory or market requirements faced by these categories of retail service providers. Consistency should be established among market participants in access to consumers, responsibilities for protection of consumers and for maintenance of a competitive market (open access, service obligation, product labeling, etc.). To the degree possible, regionally consistent policies concerning meters charges should be established. Similarly, where the commercial transactions of established providers are taxed, the transactions of new entrants should be equally burdened.

Clarify regulatory authority

The restructuring of the retail electricity market will necessitate some changes to established government responsibilities relating to the electricity industry. The relationship between state or local utility regulatory agencies and state consumer protection agencies and laws needs to be clarified, or, if necessary, new institutions may need to be established. Responsibility for low income assistance for electricity bills and the funding of that assistance needs to be decided. The relationship between federal regulatory authority and state and local regulatory authority to accomplish public policies (through the use of meters charges, local distribution charges, or other means) and to oversee the competitive market for retail services should be clarified.

Incentives for reliability and efficient use of local distribution systems

Distribution system charges will remain regulated to ensure reliability, efficiency, and appropriate cost allocation. Local distribution and delivery services should be priced and regulated in a manner that fosters reliability and the efficient use and expansion of the facilities.

Transitional Steps

The steering committee identified a number of transitional steps that should be taken to help complete the development of a competitive retail market by the year 2001. State legislatures, regulators, local governing boards and utilities should begin to implement these steps as soon as possible. To the extent possible, decisions and actions by public policy makers during the transition should not create an advantage or impose a disadvantage on any group of competitors, or preclude later actions to enable the development of efficient markets.

Unbundled billing

Consumers electricity bills currently show one price for delivered electricity. The various components of the cost are not identified, that is, the components are bundled into one charge. These components may include bulk electricity supply, shaping services, reliability reserves, transmission, local distribution, and conservation program costs among others. Consumers will be better educated about electricity services and better prepared to make separate decisions about some of these products and services in the future if they begin to see the separate components on their bills now. Therefore, utilities should begin to unbundle, that is, itemize, the components of consumers bills for informational purposes in preparation for separate pricing in the future.

Separation of local distribution from electricity services

Utilities should reorganize their companies to functionally separate local distribution service from electricity services. Separate accounting systems should be developed in preparation for the side-by-side, but independent, existence of a regulated wires utility and a competitive electricity service company. Full legal separation of the two functions is not required so long as regulators and local governing boards put in place the necessary safeguards to prevent utilities from using their monopoly positions in distribution to influence their market positions in the competitive electricity services business.

Provide open transmission system access as soon as possible

Utilities, working with their regulators or local governing boards, should provide open and non-discriminatory access to the local electricity distribution system as soon as possible. Utilities should develop open access tariffs for this purpose. Making such services available will help the competitive electricity services business develop and will provide early identification of any problems associated with operating in an open access retail market environment. Lessons learned will feed into the more formal restructuring process and help insure its successful implementation.

Modify distribution utility service obligations

Most utilities currently have a regulatory obligation to serve, that is provide electricity services to all customers in their service territory. In the market envisioned by the steering committee, such an obligation is inconsistent. Instead, the distribution utility should have an obligation to connect all customers to the electricity services market through their distribution system. Neither the distribution utility, nor its affiliated electricity service company, will have any special obligation to provide electricity supplies and services to consumers in the restructured electricity market. Regulators and local governing boards need to alter the utility service obligation requirements to be consistent with a competitive electricity services market.

Promote development of electricity service providers

It is important to gain experience in competitive retail electricity markets and to put in place conditions that encourage its development to effectively serve all types of consumers. In addition to the unbundling and open access tariffs described above, state legislatures and regulators are encouraged to establish an orderly transition to direct access to competitive retail electric service markets. An orderly transition would facilitate the market's development while insuring that all consumer classes benefit and that unwarranted cost shifting is prevented. Particular concern exists for the small consumer. Pilot programs should be designed and implemented to encourage the development of aggregators who can provide competitively priced power for small customers. States should recognize that effective competition may not materialize in all market segments. They should be prepared to consider alternative means to address this problem when it occurs, including, but not limited to, authorizing local units of government to aggregate small customers.

A "green" power marketing program should be developed to introduce varied products to consumers and to provide an opportunity for renewable resources to compete in the retail electricity market based on their environmental characteristics and price.

Finally, a provider of last resort mechanism should be maintained to accommodate those who cannot choose a supplier or for whom no suppliers materialize. Such a mechanism, for example, could include a last resort supplier of energy at affordable rates, or could be a system of random assignment of electricity service providers to consumers who have not been able to effectively access the market.

Opportunity to recover stranded costs

Opening up the retail electricity market to competition raises the possibility that some utility costs become stranded; that is, a utility may not be able to recover the full costs of some previously rate based assets. To the extent that stranded costs are a problem, utilities may resist competition and may attempt to shift stranded costs onto other captive customers. To facilitate the transition and reduce cost shifting incentives, utilities should be given a fair opportunity to recover legitimate, non-mitigable stranded costs. Any policies on stranded cost recovery should preserve a strong incentive for utilities to mitigate stranded costs to the greatest extent possible. Recovery of non-mitigable stranded costs may be accomplished through exit fees or distribution access fees. However, it should be clear that stranded costs are transitional in nature and recovery provisions should be limited in duration and amount recovered.

Questions for Public Comment

TRANSMISSION: OPEN-ACCESS HIGHWAY FOR COMPETITION IN GENERATION

Goals

The primary goal of the steering committee's proposals for transmission is a transmission system whose structure and operation help ensure a fully competitive generation market. The proposals are also designed to improve the efficiency of use of the transmission system, and to maintain the system's reliability as the pressures of competition on utilities increase.

Background

If consumers are to realize the benefits of competition in the generation of electricity, competitors in that market must have equal access to the transmission system. The Federal Energy Regulatory Commission (FERC) has recognized the critical importance of equal access, as demonstrated in its Orders 888 and 889, and has indicated that its policy goal for transmission is to facilitate a fully-competitive wholesale market for generated electricity. The steering committee is convinced that we can expect FERC to move ahead with definition of rules to make sure that all competitors have non-discriminatory access to the transmission system.

If a single party owns both transmission and generation, there is potential for the owner to increase the profits of its generation by limiting transmission access to competitors. That owner is also subject to competitive pressures that may serve as a disincentive to needed investments in transmission maintenance and expansion. These pressures may also encourage operation on the edge of reliability limits. To assure equal access and reliability requires that decisions affecting transmission be effectively separated from decisions affecting generation. The necessary separation can be accomplished by the formation of a FERC-regulated Independent Grid Operator, or IGO (referred to in the FERC Order 888 as an Independent System Operator, or ISO) that is responsible for the operation of the transmission assets of multiple owners. Operating and charging for the use of these systems as a single system would also eliminate "pancaking" of transmission rates (paying a different rate to each transmission owner over whose system a power transaction is scheduled) and make possible more efficient operation.

Transmission Recommendations

The Steering Committee recommends the formation of an IGO, regulated by FERC and including the transmission assets of Bonneville and the other owners of major transmission assets in the region. Membership should be voluntary, but every effort should be made to enlist wide participation.

IGO Responsibilities

This IGO should have operational control over the transmission system and enough generation to ensure short-term reliability. The IGO will also have responsibilities in other areas such as maintenance, planning and expansion. The IGO should have clear incentives to maintain reliability and encourage the efficient use of the system. The IGO will necessarily follow FERC principles for ISOs, and may include modifications agreed to by participants and approved by FERC. Load control centers could be maintained locally, if participants prefer. The steering committee recommends that intermittent, as-available and distributed generation should be treated fairly in buying and selling necessary ancillary services and the provision of transmission services, and that transmission planning should follow long term least-cost planning principles.

Bonneville Power Administration

Since Bonneville's transmission facilities make up a large part of the regional transmission system, the independence of operation of these facilities from Bonneville power marketing considerations is particularly important. Therefore, the Review recommends that Bonneville's power marketing and transmission functions should be fully and legally separated (including separated funds). This will require that concerns about the security of Supply System debt be resolved. The resulting Bonneville Transmission Agency or Corporation (BTC) should become a full participant in the IGO. If other participants agree that the interests of the BTC have been sufficiently separated from those of power marketing, the BTC could be the operator of the IGO.

Legislation will be necessary to accomplish the separation of Bonneville's transmission and generation functions. Legislation should also subject Bonneville's transmission revenue requirement to FERC regulation that is equivalent to FERC regulation of IOUs.

Governance

The makeup of the IGO governing board should follow FERC guidelines, which require that no individual market participant or class of market participants have the ability to control the IGO. It should include owners and users, state and regional regulatory entities on an ex-officio basis (similar to the Northwest Regional Transmission Association and the Western Regional Transmission Association) and at least some independent outside representatives from the broader public.

Wheeling for Retail Loads

The IGO, in providing wheeling for retail loads, would be governed by rules set out in FERC Order 888. These rules would allow such wheeling if it is authorized by the state or utility in which the retail load is located. The steering committee recommends that Bonneville should honor the same rules until it becomes a participant in an IGO.

Pricing of Transmission

Transmission pricing becomes increasingly important as the transmission system is used by more parties and transactions become more market-based. Some pricing practices used in the past would give users inappropriate signals for their use of transmission in the expected competitive environment of the future and inaccurate signals regarding the location of power resources and the expansion of transmission system capacity. These issues are being addressed by both the Northwest and Western Regional Transmission Associations. The Review recommends that pricing of services provided by the IGO should follow principles being developed through the regional transmission associations and will be subject to FERC regulation.

Transition Issues

During the period that the legislation is under consideration Bonneville should move to accomplish as much separation of generation and transmission as is possible by administrative measures. In addition, Bonneville should participate in efforts to form an IGO that could operate both federal and non-federal assets.

An IGO should assist in facilitating a competitive power market for customers that take delivery of their power requirements at subtransmission voltages over facilities they currently do not own. In the transition to an IGO, BPA should work with these customers to assure that fair pricing mechanisms, reasonable transition periods, and opportunities for utilities to gain control over delivery facilities are available.

Questions for Public Comment

FUTURE ROLE FOR A FOUR-STATE REGIONAL BODY

Background

When the Northwest Power Act was passed in 1980, the authors contemplated an extended period of electricity shortages. Many believed that the shortages could only be averted through the construction of increasingly costly, large scale power plants. The participation of the federal Bonneville Power Administration was believed to be essential to the financing of these plants. As part of the bargain struck in return for this expansion of Bonneville's authority, the Northwest Power Planning Council was established. The Council, which is made up of two representatives of each of the governors of the four Northwest states, was to provide the states and the public a role in determining the future need for electricity and how that need could best be met, giving priority to conservation, renewable and high efficiency resources. The Council was also charged with developing a program to protect mitigate and enhance the fish and wildlife resources of the Columbia River basin.

The Power Planning Council has been credited with many improvements in electricity planning. However, in a competitive environment, market forces will play the primary role in determining when and what generating resources get built and what can be charged for their output. In such an environment, the Northwest Power Planning Council's regional planning role and oversight of Bonneville's resource acquisitions are no longer relevant.

Future Roles?

The Review believes that moving to a competitive electricity industry can yield benefits. There is, however, much that is unknown about the competitive future. As the Northwest moves toward a competitive electricity industry, there may be roles that the region would desire to be carried out by a regional body. These roles involve ensuring that the transition to a competitive market is done efficiently and fairly throughout the region and that the public values the Northwest has sought from its power system are protected. Some of these roles may only become clear as the restructuring of the industry progresses, but it appears that they include:

Reliability

One of the concerns expressed about the move to a competitive electricity market is the degree to which that market will result in a power supply that is reliable, both in terms of adequacy of supply and operation. New institutions, like the independent grid operator are proposed to deal with some of these issues. Those institutions are, however, themselves untried. At least during the transition period while new institutions and market structures are developing, it could be desirable to have a regional body to monitor and evaluate the degree to which the competitive market is ensuring reliability and to propose corrective actions, if necessary.

The Competitive Marketplace

Competition will create a regional, and probably west-wide electricity market. While an individual utility approach will remain important for regulation of the distribution function, much of the market activity will occur across utility and across state boundaries. There will be many new non-utility and non-regulated actors in this market. In addition, differences in market structure and rules between and within states can result in market friction and create opportunities for market participants to arbitrage these differences to the detriment of consumers and overall market efficiency. The development of the market may need to be monitored for potential problems of market power or structural market inefficiencies until the new structure is mature. It could it be desirable to have a regional body that provides information, evaluation and analysis of the evolving marketplace to help ensure full, fair and effective competition throughout the region.

Conservation and Renewable Resources

The Review's proposal for conservation and renewable resources relies heavily on local action to overcome market barriers. However, it also recognizes that there is value establishing regional goals, tracking and reporting progress region-wide, analyzing the obstacles to achieving those goals and devising strategies to overcome the obstacles. These kinds of activities are consistent with the work the Northwest Power Planning Council has been carrying out successfully for the last 15 years. A regional body, working with power suppliers, industry, governments and public interest representatives, could be an appropriate way to accomplish these tasks in the future.

Multi-State Issues

The Columbia River and its tributaries knit the Northwest together and make it an interdependent region to perhaps a greater extent than other regions of the country. The economies of the Northwest states are inextricably linked to the rivers and the multiple purposes they serve. Other resource issues also cut across the boundaries of the Northwest states. It could be desirable to have a four-state body to analyze multi-state resource related issues and coordinate multi-state initiatives, where economies of scale are possible or cross purposes could be avoided.

Fish and Wildlife

As noted above, the Northwest Power Planning Council has responsibility for developing a fish and wildlife program for the Columbia River Basin. In that process, it provides an avenue for public and industry input into some fish and wildlife decisions and decisions about how those funds derived from the power system are to be spent on fish and wildlife projects. However, ultimate decision-making on river operations is likely to be governed by the federal endangered species law, treaty commitments and other obligations. There could be value in a four-state body that can act as a regional voice in these matters.

Public Participation and Involvement

One of the primary charges given the Northwest Power Planning Council under the Northwest Power Act was to facilitate public participation and involvement on issues related to electricity and fish and wildlife in the region. The Council has attempted to fulfill this charge by maintaining an extensive public information and public outreach program, both through its central offices and its offices in each of the Northwest states. In some respects, the competitive market will give consumers a much greater say in the electricity industry than they have had before. Nonetheless, a four-state body with the ability to inform and involve interested members of the public on matters that affect them, their environment and their economy across the region could continue to be of value.

Questions for Public Comment

APPENDIX A
COMPREHENSIVE REVIEW STEERING COMMITTEE BIOGRAPHIES



Chuck Collins, Chair

Since 1981, Collins has been president of the Colsper West Corporation in Seattle, Washington. Prior to that he served as vice president and general manager at Polyform, U.S., Ltd.; transit director at Seattle Metro; and county administrator in King County. From 1981 through 1985 Collins was a member of the Northwest Power Planning Council, serving as chairman from 1984 to 1985. Currently, he is chairman of the State Commission on Student Learning and a board member for the Washington Dental Service, Inc.

Collins earned a bachelor's degree in philosophy from Gonzaga University in 1965, and a master's in public administration from the University of Washington in 1970.

Alvin Alexanderson

Alexanderson is the vice president for rates and regulatory affairs at Portland General Electric Company. His responsibilities include least-cost planning and demand-side resource evaluation. He received his bachelor of science degree from Hillsdale College and his law degree from the University of Michigan School of Law. He served as assistant attorney general for Oregon from 1972 to 1979, emphasizing economic regulation and antitrust law. He joined PGE in 1979 and has served as deputy general counsel, vice president of finance and president of Portland General Exchange, a power marketing affiliate.

His legal practice and his marketing and rates management experience covers a wide range of retail and wholesale pricing questions. He frequently represents investor-owned utility associations in matters involving wholesale power and transmission pricing. He lives in West Linn, Oregon, with his wife and two children.

Rick Applegate

Applegate is the West Coast conservation director for Trout Unlimited. Prior to that he spent eight years at the Northwest Power Planning Council as director of fish and wildlife. He has also worked for the Montana State Legislature, the Montana Constitutional Convention and the Environmental Quality Council. Applegate served as a minority staff director of a subcommittee of the U.S. Senate Judiciary Committee. Rick has a bachelor of arts degree in political science and history and a master's in environmental policy from the University of Montana.

Ken Canon

Since 1981, Canon has represented Industrial Customers of Northwest Utilities (ICNU) as its executive director. ICNU represents its member's electric energy interests before the Bonneville Power Administration (BPA), the Northwest Power Planning Council, with individual utilities and in other forums. In addition, Canon is the managing director of the Association of Public Agency Customers, a subset of ICNU, and participates in BPA rate proceedings.

Prior to 1981, Canon represented industries in legislative and regulatory arenas as the assistant general counsel for Associated Oregon Industries. Canon graduated from Willamette University Law School and is a partner in the Canon & Hutto