Northwest Energy Review Transition Board

Progress Report on Development of the "Northwest Chapter"

of National Utility Restructuring Legislation

EXECUTIVE SUMMARY

In January of 1997, the governors of the four Pacific Northwest states appointed a Transition Board to oversee implementation of the recommendations of the 1996 Comprehensive Review of the Northwest Energy System. This report to the congressional delegation of the Northwest states covers the progress in six areas. Three of those areas have been the direct responsibility of the Transition Board: the status of the Bonneville Power Administration’s transmissions system, dealing with Bonneville’s potential stranded costs and the subscription process for marketing Bonneville’s core power products for the period FY 2001 and beyond. Progress in three other key areas — control of Bonneville’s operating costs, governance of the Columbia/Snake system, and future fish and wildlife costs — is also summarized, although these issues have not been the direct responsibility of the Transition Board.

In each of these areas, there are areas of agreement and disagreement. Our characterization of levels of agreement does not include Bonneville, which is not able to take positions in these areas currently.

In the area of Bonneville’s transmission system, the region has reached general agreement that Bonneville’s transmission should be functionally separated from power marketing, and that the Federal Energy Regulatory Commission should have greater authority over Bonneville transmission rates, terms and conditions. The specific form of FERC regulation of Bonneville is still under debate.

In the area of stranded costs, parties in the region have reasonable agreement on the kind of problems that contribute to Bonneville’s cost risks. However, there is little agreement on which of these problems should be called stranded costs, the specific mechanisms that should be used to collect stranded costs, the limits that should apply to such a mechanism or the allocation of stranded costs among the region’s parties.

In the area of subscription, there is general agreement that a single offer will not satisfy all customers’ needs, and that bilateral contract negotiations will be necessary. This will be a challenge, but the work group is generally optimistic that subscription can be successful.

In the area of cost control, the Cost Review panel formed by the Northwest Power Planning Council and Bonneville released its final report in March. The report identified nearly $150 million in potential reductions, based on previous budget baselines that already included significant reductions from current budgets.

In the area of governance, a process involving representatives of federal, state and tribal governments has developed a draft agreement to coordinate fish and wildlife policy and planning. This draft agreement was released March 30, 1998; comments will be received through May.

In the area of fish and wildlife costs, there is a wide range of alternatives under consideration, many of which would require spending significantly more than current levels. Parties continue to develop financial alternatives that might be able to handle this range, but the outcome is not yet clear.

INTRODUCTION

The final report of the 1996 Comprehensive Review of the Northwest Energy System recommended that the region’s governors name a Transition Board to "work with regional interests and Bonneville in a public process to oversee the subscription process and provide liaison with the Northwest congressional delegation and affected constituencies." The Transition Board was also made "responsible for making recommendations to assist in implementation of the Review’s recommendations."

The Transition Board is aware that work is proceeding in Congress on national restructuring legislation. The Transition Board has committed to bringing recommendations on the "Northwest Chapter" of that legislation to the governors and the Northwest delegation by July 1, 1998. In the meantime, this report is intended to give the delegation an update on the state of regional discussions in six major areas:

1. The role of Bonneville Power Administration’s transmission system

2. Treatment of Bonneville’s potential stranded costs

3. Definition of "subscription" for Bonneville’s power after 2001

4. Control of Bonneville’s costs of power and transmission operations

5. Changes in governance of the Columbia and Snake River hydroelectric system

6. Future budgets for fish and wildlife

1. TRANSMISSION

Background

In the area of transmission, the Comprehensive Review recommended: 1) that an independent grid operator be formed with Bonneville participation and 2) that Bonneville be "legally separated into two organizations – a power marketing organization ... and a transmission organization." It also recommended that Bonneville’s transmission be subject to regulation equivalent to the regulation of the transmission of investor-owned utilities by the Federal Energy Regulatory Commission (FERC).

The Transition Board judged the organizational efforts of regional utilities to form an independent grid operator (IndeGO) to satisfy the first recommendation. While the IndeGO effort has been suspended recently, discussions about features of an independent grid operator are continuing. To satisfy the second recommendation, the Transition Board formed a Transmission Work Group to explore the issues and suggest the best path to legal separation of Bonneville into power marketing and transmission entities.

The Transmission Work Group was formed in April 1997 and has met 20 times since then. It examined various forms of separation and considered such issues as legislative difficulties, perceived impacts on the security of WPPSS bonds, and assignment of all of Bonneville’s current obligations under laws, contracts and treaties. The group eventually decided that the most practical option is functional separation of Bonneville’s business lines with regulation by FERC that is "equivalent" to FERC’s regulation of investor-owned utilities (IOUs). There was widespread agreement that this would be a significant change in FERC regulation of Bonneville, and that this change was desirable.

The group considered a number of differences between Bonneville and investor-owned utilities, and whether differences might make it appropriate for FERC regulation of Bonneville to vary in some ways from its regulation of IOUs. The group recognized, in particular, that the lack of stockholder owners of Bonneville makes it difficult for FERC to disallow Bonneville expenses, once spent, from inclusion in transmission rates. Another result of Bonneville’s lack of stockholders is that capital costs included in rates might need to include some sort of risk component, covered for IOUs in the equity return. Bonneville also has other legal requirements such as its obligation to repay the Treasury in full.

The group identified a number of issues related to FERC equivalency:

Issue - Starting point of legislation

There are two general positions on how to develop legislation defining the new role of FERC in regulation of Bonneville. The publicly owned utilities propose to start with FERC’s current authority over Bonneville as defined in Bonneville’s organic statutes, [ These statutes include the Bonneville Project Act of 1937, the Flood Control Act of 1944, the Regional Preference Act of 1964, the Federal Columbia River Transmission System Act of 1974, the Northwest Power Act of 1980, the Bonneville Refinancing Act of 1996 and others.] and to expand FERC’s authority with specific changes to the organic statutes. The investor-owned utilities propose to start with FERC’s current authority over jurisdictional utilities (in the Federal Power Act) and modify that authority with appropriate exceptions in Bonneville’s case. Either approach will require a careful review of Bonneville’s organic statutes to determine which of Bonneville’s current authorities and obligations should be maintained.

Issue - Nature of separation of BPA business lines

As described above, the work group has put aside the option of complete legal separation of Bonneville into two agencies with power and transmission responsibilities for the time being. There appear to be a number of practical difficulties of separating the agency’s current obligations, both financial and otherwise. There is also a concern that even though separation might leave holders of WPPSS bonds and other third party debt at very low risk, a separation of Bonneville into two entities could be perceived as an increase in debtholders’ risk, with potentially significant legal and financial effects. Since functional separation of Bonneville’s business lines with IOU-equivalent regulation by FERC of the transmission business appears to offer most of the benefits and to avoid many of the complexities, the work group has come to concentrate its discussions on the specifics of this approach. If this approach is successful, it would be unnecessary to revisit the issue of complete legal separation of Bonneville. The publicly owned utilities have not formally affirmed that functional separation is the preferred option, but their agreement is implicit in their discussion of principles for FERC regulation.

Issue - How should cost accounting of BPA business lines be separated?

There is general agreement that when Bonneville can cover its revenue requirements for each business line, the FERC Uniform System of Accounts for functionally separated business lines is the appropriate standard. When one business line (e.g., the Power Business Line, or PBL) is unable to cover its revenue requirement, there is general willingness to allow it to borrow from the other business line (e.g., the Transmission Business Line, or TBL) if the other business line has a surplus at the time. There is general agreement that the TBL should not be able to set its rates to cover PBL costs except for ancillary services and other power services necessary to maintain transmission reliability. Some parties would allow a surcharge on transmission rates, if approved by FERC, when Bonneville has an actual or projected insufficiency of funds.

Issue - How are BPA transmission rates set?

Interested parties have a range of positions as to a recommended process of setting Bonneville rates. The representatives of public power and some of the direct service industries would support a process that begins with the current process and gives more oversight to FERC. The investor-owned utilities would support FERC authority and process that is close to that for investor-owned utilities, but with some exceptions, such as hearings in the Pacific Northwest and pre-approval of investment by Congress or FERC, that are designed to reflect the real differences between Bonneville and an investor-owned utility.

Issue - What are conditions of access to BPA transmission?

There is general agreement that the conditions of access to Bonneville transmission should be those required of investor-owned utilities. Some parties have proposed that access might be reserved in special circumstances such as operations of the hydropower system for fish that require generation, or as determined by FERC to be in the public interest. Others were concerned that such special rights might be used for anti-competitive purposes, and they contend such circumstances can be accommodated commercially.

Issue – Should BPA be able to join an Independent System Operator (ISO)?

There is general agreement that the Bonneville transmission business line should be permitted to join an independent system operator. Though most of the discussion took place outside our work group, there was much less agreement about the desirability of Bonneville actually joining IndeGO. This, however, had more to do with the specifics of the IndeGO proposal than with the desirability of an ISO in principle.

Bonneville has expressed concern that it might not be able, under its statutory responsibilities, to turn over control of its transmission assets to an ISO. The U.S. Department of Energy Office of General Counsel has released an opinion ("Bonneville Power Administration Authority to Participate in an Independent System Operator," February 26, 1998) responding to those concerns. The memo concludes that Bonneville can turn over operation of its transmission assets to an ISO, but Bonneville must retain enough oversight to be able to ensure that its responsibilities are met. The memo describes a BPA/ISO contract that provides standards for the ISO (designed to guide the ISO in meeting BPA’s responsibilities), and allows BPA to withdraw from the ISO if the ISO doesn’t meet the standards. The work group has not had the chance to discuss the practical issues involved in negotiating such a BPA/ISO contract.

Issue – Should BPA be able to make retail sales?

This issue is not strictly a transmission business line issue, but was raised in the Comprehensive Review and in some of the proposals regarding FERC regulation of Bonneville. There is general agreement that Bonneville should not sell to final consumers except to those currently having contracts. It appears to be generally acceptable for BPA to sell to Federal agencies for their own needs as Bonneville is currently authorized to do.

2. STRANDED COSTS

The Transmission Work Group was initially reluctant to take up discussion of stranded costs, but late in 1997 the group agreed to address the problem.

Issue – What is the problem to be solved?

The group has come to think of the issue as not a single problem, but as one or more of five relatively distinct problems. The component problems have different causes and may require different remedies.

A. Revenue shortfall because of variation in precipitation, short term markets, and so on

This is a familiar problem for Bonneville, and it has adequate remedies without resorting to a stranded cost mechanism. Bonneville has always faced variable output and variable revenues. Variable annual precipitation and limited year-to-year storage have meant that the total amount of energy produced by the hydroelectric system varies from the average by as much as 25%. Short-term markets are likely to remain at least as volatile as they are now, resulting in variation in Bonneville’s revenue from secondary hydroelectricity. One response to this variation in precipitation and similar uncertainties is a reserve fund. The reserve fund could be sized to allow Bonneville’s rates to reflect expected precipitation and secondary energy, without activating a special cost recovery mechanism every time they are below average. Bonneville’s customers in the past have expressed concern that Bonneville’s estimate of an adequate level of reserves was higher than the customer’s estimate. Another response is including in sales contracts a Contingent Rate Adjustment Clause (CRAC) that adjusts rates in response to clearly defined water and market conditions. The reserve fund and CRAC could also be used in combination.

The most important point to be understood in connection with this problem is that Bonneville and its customers have always faced the problem of variable revenues, and are accustomed to dealing with it. Strictly speaking, it is not a stranded cost problem. Lower than average precipitation and lower than projected secondary energy revenues can be objectively distinguished from other problems that may leave Bonneville unable to cover its revenue requirements. An objective contingency should help assure customers that rate adjustments such as the CRAC described above are only employed in response to the agreed conditions, and not to cover increased staffing costs.

B. Operating costs

The operating costs of an investor-owned utility, once it has made the transition from regulation to competition in its generation business and has made the one-time allocation of stranded costs, face market discipline. Bonneville’s status as a federal agency makes such a once-and-for-all assignment of stranded costs problematic, as discussed in the next section. As a result, Bonneville’s future operating costs could affect the level of any stranded costs. Bonneville’s customers have expressed concern that providing a mechanism for recovery of Bonneville’s stranded costs also removes pressure on Bonneville to reduce its operating costs and to resist the impulse to add unnecessary employees and functions.

At the same time, there appear to be new opportunities to reduce Bonneville’s operating costs as some of its historical responsibilities diminish (e.g., acquisition of generation to cover regional growth in demand). The Bonneville Cost Review identified opportunities to save $145 million per year in Bonneville’s operating costs.

FERC consideration of Bonneville’s potential stranded costs would necessarily consider Bonneville’s level of operating costs and whether all reasonable efforts had been made to lower them.

Several parties also cited the uncomfortable political fallout that might occur if Bonneville missed a Treasury payment, as additional incentive for Bonneville to minimize operating costs.

The Transmission Work Group has not discussed specific proposals to give any parties other than the FERC outside authority over Bonneville’s operating costs, but has identified the issue as one of the components of the "stranded cost problem." The group’s discussions generally assume that some form of control of Bonneville’s operating costs that would satisfy customers could be designed.

C. Costs of historic investments stranded by persistent low market prices

If precipitation and other short term variations are within projected patterns, Bonneville experiences no extraordinary additional costs, and if its operating costs are well controlled, it appears very likely that Bonneville’s revenues will be adequate to cover its operating costs and repayment of its current debt. However, it is always possible that Bonneville, like any other electric utility, could face future energy developments (e.g., highly efficient fuel cells) that result in market prices that are below BPA’s costs.

In that event, BPA’s ability to recover its costs should be contrasted with that of an investor-owned utility facing electric restructuring. In the case of an investor-owned utility, the most common approach to calculate any stranded costs is to estimate those costs that a utility would not be able to recover in a fully competitive market. If the evaluation indicates there are stranded costs, the regulators usually establish a one-time allocation of such costs between the customers and the utility. Thereafter, the generation assets are no longer subject to rate regulation and any profits or losses generated by these assets are those of the asset owner.

In contrast, Bonneville, as a federal agency, was not established to make profits, but to recover the cost of its assets. It has no stockholders who have volunteered to bear potential losses (in return for the opportunity to make profits). As a result, it is inappropriate for a cost-based, non-profit Bonneville to use a stranded cost approach developed for the circumstance of a market-based, investor-owned utility. Since it seems very unlikely that it faces stranded historic costs over the long run, until recently little effort has been directed toward designing a necessarily unique approach to such a stranded cost problem for Bonneville.

D. Incremental new investments or programs (e.g., Fish & Wildlife)

The first three components of the overall problem appear to be manageable. While the Transmission Work Group has not chosen preferred mechanisms for each component, promising mechanisms have been identified and discussed. The question of stranded cost treatment for new investments or programs, however, is more contentious.

One point of view is that such costs are not sunk, so do not qualify for stranded cost status. A counter argument is that while the costs are not sunk, there is an already-existing obligation to mitigate the effects on fish and wildlife of past investments in the hydro system — the often-cited analogy is to decommissioning costs of a nuclear power plant. Although these positions on principle have not changed much after considerable discussion, some customers have been willing to discuss some increase in Bonneville’s Fish and Wildlife costs, if the increases are modest and capped. The examples cited in these discussions include new investments in fish screens and spawning habitat improvement.

E. Reconfiguration of the power system

The National Marine Fisheries Service (NMFS), as part of the Endangered Species Act process, is conducting an evaluation of alternatives including drawdown or breaching of the 4 lower Snake River dams. A decision is scheduled in 1999. Similar changes for John Day dam are also under discussion. These changes, if they were authorized by Congress and implemented, would change the power system and its costs substantially. Other proposals, such as responses to the Clean Water Act or early retirement and decommissioning of the Washington Public Power Supply System’s nuclear plant (WNP2) could have similar consequences.

The Transmission Work Group has found it difficult to discuss this component of the overall problem. Some parties have pointed out that any change to the power system as substantial as reconfiguration will require the approval of Congress. At that time Congress would almost certainly consider the allocation of costs of the change and any necessary changes in existing statutes. Accordingly, they advocate focusing regional discussion now on the other aspects of stranded costs, where the prospects of coming to agreement are better.

Issue – What costs are included in stranded costs?

As mentioned earlier, there is debate on which costs should be eligible for treatment as stranded. Investor-owned utilities’ stranded costs are generally limited to costs that were sunk on some date when it should have been clear that the utility would be making the transition to competition. Before that date, the utility had a responsibility to acquire enough generation to serve its customers’ demand for electricity, and was granted a monopoly franchise and a reasonable rate of return. The utility accepted a limited rate of return and shared risk with its customers. After the date, the deregulated utility can expect to be released from the responsibility to acquire generation, to lose its monopoly and to lose any limitation or protection for its rate of return. In the future the utility will have the opportunity to earn whatever profits it can, but will bear all risks.

Bonneville, as pointed out earlier, was not established to earn profits, and is not organized to absorb losses (no stockholders). As a result, a clean and final transition, from regulated utility sharing risk with its customers to profit-making utility bearing full risks, is not possible. In addition, Bonneville has fish and wildlife obligations whose cost is not all sunk and whose future cost is not yet known.

The work group touched on this issue a number of times, but did not come to any agreement. Some customers referred to the treatment of stranded costs of investor-owned utilities as a model, and would favor limiting stranded costs to those sunk by some given date. Environmentalists cited the existing obligations to fish and wildlife and argued that the costs are those of remedying the effects of past investment in the power system. They would favor including costs to meet those obligations, even if they are incurred in the future. Public power has proposed a stranded cost mechanism that does cover future costs, with limits on level and duration.

Issue – What are the incentives to control costs?

The view expressed by many in the work group was that an independent review — probably by FERC — of any Bonneville application of a stranded cost recovery mechanism would include examination of Bonneville’s efforts to keep stranded costs down. In this view, the possibility that FERC might refuse to allow recovery of stranded costs if it judged that Bonneville’s cost control efforts were inadequate provides a strong incentive to control costs effectively. In addition, the political repercussions of a deferral of a Treasury payment (advocated by many as the trigger for a stranded cost recovery process) would be strong encouragement for vigorous cost control effort. Others in the group suggested third party audits of Bonneville management and operations to help control costs.

Issue - Who decides?

The group mostly agreed that Bonneville should initiate any process to recover stranded cost, and that FERC should review and approve Bonneville’s need for recovery. The investor-owned utilities supported FERC review consistent with the FERC’s authorities, policies and regulation pertaining to IOUs. The representatives of the publicly owned utilities generally supported BPA-specific legislative guidelines for FERC in its review and approval of Bonneville stranded costs. The Columbia River Inter-Tribal Fish Commission (CRITFC) proposed that a collaboration of Federal, state and tribal governments in coordination with the Three Sovereigns process should determine Bonneville’s need for stranded cost recovery.

Issue – What triggers the mechanism?

The work group’s discussion of the appropriate trigger for the stranded cost mechanism focussed on credibility of the trigger and its effects on Bonneville’s incentives to control costs. Several parties expressed the opinion that projections of BPA’s finances could be manipulated, and that a trigger linked to such projections (e.g., projected reserves or probability of repayment) was too vulnerable to that sort of manipulation. These parties prefer that the trigger be an objective event that everyone will want to avoid, such as a deferral of Bonneville’s Treasury payment. Others believe that the consequences of actual Treasury deferral, or even significantly reduced reserves, are to be avoided and that stranded costs should therefore be assessed prospectively.

Issue – What limits (time and/or $) on recovery?

Many representatives of environmental groups are reluctant to accept any limit on recovery of stranded costs. They view mitigation of the hydro system’s impacts on fish and wildlife as a debt that is defined by some level of recovery of salmon runs, etc. rather than the amount of

money required to accomplish the recovery. Most utilities and major power customers are very concerned with reducing uncertainty about stranded costs. The public power representatives have proposed a limit of $50 million per year, up to a cumulative limit of $400 million over the 2001-2011 period.

Issue – Recovery mechanism

The mechanisms discussed included a uniform transmission surcharge, an adjustment of any below-market rates up to market levels, the use of an early debt repayment fund and a directed charge. A directed charge could be based on the customers’ past benefits from the federal power system, the customers’ opportunities to benefit from future cost-based rates, or the customers’ responsibility for system costs. The group’s debate on recovery mechanisms focussed on two issues: the fairness of the allocation of stranded cost resulting from a given mechanism, and the impact of the mechanism on economic efficiency.

The mechanism discussed most (because it appears to be the only non-contractual mechanism currently available to Bonneville) is a uniform transmission surcharge, commonly referred to as "peanut butter," imposed on all users of the federal transmission system. The advocates of this mechanism are generally the representatives of the public utilities. They favor a broad allocation of stranded costs.

Representatives of other customers regard a uniform transmission surcharge as unfair. They argue that FERC will not accept such a charge. They also argue that it would discourage customers from using the transmission system to its most efficient extent. They propose to give FERC the authority to determine the allocation of stranded costs. They expect that FERC would specify a directed charge, based on costs imposed on the system by each customer.

Staff Note: Recovery Mechanisms and Economic Efficiency

Most of the discussion of recovery mechanisms has dealt with either their fairness, or their effect on economic efficiency. The question of which recovery mechanism is fairest is almost certainly impossible to answer to everyone’s satisfaction. We can, however, analyze the effects of alternative forms of recovery mechanism on the efficiency of use of the transmission system.

Principles of efficient pricing assert that users will make the most efficient use of the transmission system when their cost of transmitting an incremental kWh is equal to the cost to the system of transmitting the same kWh. The basic cost structure of the transmission system is mostly fixed costs, with very low variable costs (in the absence of congestion). Accordingly, the most efficient pricing system for the transmission system will be mostly fixed charges (e.g., access fees) with a small charge equal to the variable cost for each incremental kWh transmitted (in the absence of congestion). If the cost to the customer of transmitting the incremental kWh is above the (variable) cost to the transmission system, it will discourage the customer from making optimal use of the system.

This suboptimal use of the transmission system is due to the mismatch of customers’ variable costs and the system’s variable costs. The effect will be the same whether the mismatch is due to a poorly designed surcharge (to collect stranded costs for the Power Business Line) or due to a poorly designed price structure (to collect the revenue requirement for the Transmission Business Line). The participants in the IndeGO discussions recognized this and chose a pricing structure that collected nearly all costs in access charges, leaving only the cost of transmission losses and congestion (when present) as variable costs of using the IndeGO system.

It’s also worth noting that any of the general types of cost recovery mechanisms might or might not lead to this type of mismatch of customers’ costs and system costs. The effect depends on whether the recovery mechanism increases the customers’ variable costs of using the system. The bottom line is that the efficiency effect of stranded cost recovery does not depend on whether the mechanism is "peanut butter" or a directed charge; instead, it depends on whether it impacts customers as a fixed cost or variable cost.

3. SUBSCRIPTION TO BONNEVILLE POWER

Background

Subscriptions are the cornerstone recommendation of the Comprehensive Review. Subscription responds to the question of how the Bonneville Power Administration should dispose of the electrical output of the Federal Columbia River Power System, after existing power sales contracts expire in 2001? The basic idea is to replace these contracts with a variety of new, short and long-term purchase commitments. Pacific Northwest customers would subscribe to Federal power to meet all or a portion of their electricity needs. The contracts would be designed to achieve three objectives: 1) align the benefits and risks of access to Federal power; 2) ensure adequate revenues for BPA to recover its costs, including repayment of Treasury and third-party debt; and; 3) retain the benefits of the system for consumers in the region.

The subscription proposal is essential because it addresses the role of BPA in marketing power in the emerging competitive market. If subscriptions are implemented successfully, it will define Bonneville’s role while ensuring cost recovery and financial stability for the Federal agency. And, in combination with cost-control, subscriptions hold the promise of avoiding any stranded costs associated with the Federal power system.

For subscriptions to succeed, BPA must offer power products that meet customers’ needs, are commercially reasonable, and have prices that are competitive. This is essential because all of Bonneville’s potential customers will have multiple choices in a robust, highly competitive marketplace. The essential challenge of a successful subscription is to develop contractual arrangements that are commercially viable and competitive, while ensuring that benefits and risks are aligned and BPA’s costs are recovered over time.

It has become clear, however, over the course of the regional discussions of both subscription and of transmission separation issues, that there is no consensus on the ability of subscriptions to guarantee that stranded costs will be avoided.

The Comprehensive Review originally connected the issues of subscription and stranded cost. Within limits, subscribers would sign up for cost-based rates, paying costs when they were above market and reaping the benefits of costs when they were below market. Over the long term, this was expected to be an attractive proposition for subscribers, and thus largely to obviate the need for separate stranded cost provisions.

While the issues of subscription and stranded costs continue to be connected, the discussions of the issues have been deliberately separated. Subscription proposals are going forward under the assumption that subscription does not imply that subscribers will be required to pay rates that are above market levels, but that power at cost-based prices should be available to subscribers if costs are below market levels. This has been made easier by the increasingly common perception that future power markets may well allow Bonneville to be competitive absent significant cost increases.

At the same time, discussions have been going forward in the transmission separation work group on a stranded cost proposal. While any stranded cost proposal that will be developed will likely take account of subscribers in distinct ways, it will also likely apply to others than subscribers, and its development will be somewhat independent of the progress of subscription. The advantage of this approach is that it allows the subscription process to focus on the details of the power transactions and contracts.

Subscription Work Group

A Federal Power Subscription Work Group was formed in March 1997, to explore ways to meet the essential challenge of a successful subscription. The work group is co-sponsored by BPA and the Pacific Northwest Utilities Conference Committee, and reports its progress regularly to the Transition Board. The group is composed of potential customers and customer associations, out-of-region purchasers, public interest groups, state government officials, and BPA.

The work group has met frequently over the past year. The group has collaborated in good faith, and has made progress on the definition of BPA’s subscription products and the development of several alternative business relationships between BPA and subscribers. The goal of the group’s efforts has been to implement the Comprehensive Review’s recommendations. One of the working assumptions has been to do this without the need for changes to the existing statutes. The issue of need for legislation continues to be raised.

The work group has identified the following issues it still needs to deal with:

• Resolution of the rights of the IOU residential and small farm customers in a subscription process.

• Provision for cost functionalization between power and transmission business lines.

• Interpretation of long-standing BPA definitions such as "requirements power."

• Resolution of the potential for risk and cost shifting in fixed-price contracts.

• Accommodation of a "slice of the system" product.

Several of these unresolved issues may raise the question of need for legislative changes.

There is a broad consensus on the portfolio of subscription products, although the group continues to discuss the pricing approaches as well as additional products. These are products that BPA is capable of providing, and that customers have a business interest in purchasing. This list of products will help ensure that the subscription offering is commercially viable. The work group has also explored several business and contract relationships that would be appropriate between BPA and subscription purchasers. These discussions have narrowed the range of reasonable contract relationships, but have also reinforced the idea that one-size-fits-all is not a workable approach in a competitive environment. Significantly, the work group has also reached broad agreement on the administrative approach BPA should use to implement subscription. Finally, the group has explored pricing principles for the subscription products. This discussion will most likely shift into a more formal PBL rate case by this fall.

At the onset of this effort, the Subscription work group recognized that collaborative, multilateral discussion would not be sufficient to conclude the subscription effort. Ultimately, contracts will be the result of bilateral negotiation between a willing buyer and a willing seller. The work group also recognized that BPA must establish rates for the subscription products in an administrative proceeding.

Over the next several months, bilateral negotiations between BPA and individual customers and rate-making discussions will intensify. The group has yet to determine the level of consistency necessary between various subscription contracts. There will always be some conflict between the desire for contract consistency to avoid inequity in risk or cost shifting in cost-based rates and the desire for custom-fitted contracts to meet a subscriber’s needs.

BPA plans to file its proposed rates for 2002-2006 subscription products in September, 1998, and will hold a series of rate case workshops through the summer months to help air issues and prepare for this filing. In the meantime, contract negotiations on subscriptions with specific customers will continue to intensify. BPA has already announced pre-subscription sales for over 650 aMW. By this summer, BPA expects to be broadly engaged in subscription negotiations. In early 1999, after rates are finalized for subscription products for the 2002-2006 period, the subscription effort is expected to culminate.

The work group has contributed significantly to a successful subscription of Federal power. There is some degree of consensus and a broad understanding on the basic building blocks: commercially viable products, contract relationships, approach to implementation and pricing principles.

Bilateral contract negotiations and a contentious rate proceeding will necessarily focus on more detailed issues and test the consensus of the subscription work group. It is also likely that new issues will surface. The work group will continue to be a forum to explore solutions to these issues as they arise.

If BPA and the region are successful, subscription offerings will be commercially viable products at cost-based rates that recover BPA costs over time. Progress toward this outcome has been significant: however much remains to be resolved and timing is critical to a successful outcome.

4. COST CONTROL

Background

Effective control of Bonneville’s manageable costs is viewed as a necessary condition meeting Bonneville’s obligations to Treasury and third-party bond holders; satisfying its fish and wildlife obligations and retaining the benefits of the federal Columbia River Power System for the Northwest. To address the issue of cost control, the Northwest Power Planning Council and Bonneville convened the Cost Review of the Federal Columbia River System (Bonneville Cost Review). The Cost Review panel included members of the Northwest Power Planning Council, senior Bonneville managers, and five "outside" members with expertise in corporate management and finance. This group spent six months reviewing Bonneville’s planned expenditures and opportunities for reducing costs.

Cost Review Recommendations

The Cost Review recently released its final report. [ Cost Review of the Federal Columbia River Power System, Final Report. Northwest Power Planning Council Publication CR 98-2, March 10, 1998.] For the period FY 2002-2006, the Cost Review identified approximately $147 in reductions in Power Business Line annual expenses from budget baselines established by Bonneville early last fall. Those baselines, in turn, incorporate reductions in Power Business Line annual expenses that are approximately $85 million less that the planned annual expenses from the 1996 rate case for the FY 1996 2001 period. These reductions are illustrated in the following figure. It must be acknowledged, however, that there are significant policy and management issues that will have to be addressed in order to fully realize the savings.

Undisplayed Graphic

Of the Cost Review’s recommendations, only one set clearly requires legislative attention. These recommendations deal with legislative changes necessary to give Bonneville internal administrative flexibility similar to that available to other members if the electricity industry.

The single highest priority is personnel management system reform. The second highest priority is procurement and property management system reform. The dollar savings potential for these are equally high. Specifically, the Cost Review recommended changes to:

• Allow Bonneville to develop and implement a new personnel system in consultation with its employees. The new system would follow Federal merit system principles and retain Federal employee benefits and salary caps, while providing the agency greater flexibility in hiring and removing employees as well as fixing their number and pay.

• Allow Bonneville to develop and retain a more business-like procurement and property management system. The new system would allow BPA to procure and dispose of goods and services, including computer systems, in the most cost-effective and business-like manner. This authority would include the ability to resolve disputes with potential suppliers and suppliers in a timely manner. This authority would also include the acquisition and disposal of real property, while following current limits in BPA organic statutes on acquiring and disposing of major power and transmission facilities.

It is not clear that federal electricity industry restructuring legislation is the most appropriate vehicle for changes of this nature. The Transition Board is not anticipating incorporating the legislative changes recommended by the Cost Review in our draft of a Northwest Chapter this summer. The Board, however, encourages Bonneville to work with the delegation to address the recommended changes.

5. RIVER GOVERNANCE

Since June 1997, representatives of federal, state and tribal governments (the "Three Sovereigns") have been discussing ways to coordinate governmental actions affecting Columbia River fish and wildlife. The discussions have produced two drafts of a memorandum of agreement that the parties have invited the public to review. In many respects, the two drafts are identical. Among the drafts’ provisions are elements described in the following paragraphs.

Federal, state and tribal governments could integrate fish and wildlife policy by developing a coordinated framework or plan for Columbia River fish; requesting government entities to adjust their schedules or coordinate their analyses; taking an issue from one of these government processes and attempting to reach a consensus recommendation that other agencies would be expected to implement; facilitating the implementation of fish and wildlife actions by others; or consolidating or eliminating duplicative or unnecessary processes.

None of the participants would give up any legal rights or responsibilities. If the Three Sovereigns were unable to reach consensus, the entity with responsibility for any action has full authority to act.

Initially, the Three Sovereigns process would focus on Columbia River salmon issues, including the effects of salmon mitigation on other resources. However, the agreement recognizes that the parties are concerned with other fish and wildlife issues, and a broader range of issues could be taken up.

To carry out this work, the drafts would create two entities: a Sovereigns Forum and a Sovereigns Committee. The Forum would consist of senior decision-makers – one representative of each of the four governors, 13 tribal leaders and one representative of the federal Administration. The Forum is expected to provide policy guidance, review priorities, and oversee staff work. The Forum would be staffed by a Sovereigns Committee consisting of four state, four federal, and four tribal representatives.

All meetings of the Three Sovereigns process would be open, and time would be provided for comments and proposals of interested parties.

The drafts were released for public review on March 30, 1998. Comments will be received through May. At this time, until the parties have reviewed the comments and determined how to proceed, we recommend not addressing governance issues in any legislative proposals.

6. FISH AND WILDLIFE COSTS

Several parties or groups are engaged in analyzing potential fish and wildlife costs for the years after 2001 under a number of possible recovery and restoration strategies.

Under the Administration’s current fish cost memorandum of agreement for 1996-2001, Bonneville committed to absorb the costs of the current system operating regime for fish and wildlife and to provide an average annual amount of $252 million for expenditures, broken into $112 million per year average for capital investment repayment, $40 million per year for reimbursable operation and maintenance costs (e.g., reimbursement for Lower Snake River Compensation Plan hatchery operations appropriations), and $100 per year for operation and maintenance of fish and wildlife projects directly funded by Bonneville.

With regard to capital costs for the years 2002 to 2012, a workgroup associated with the Three Sovereigns process and Bonneville personnel have estimated the potential costs of various approaches to system configuration, including in-river migration improvements, emphasis on juvenile migration through improvements in transportation, reservoir drawdowns, and system alterations to meet Clean Water Act requirements. The annual capital cost estimates for 2002 to 2006 range from $120 million to an average of $180 million per year, depending on which option is implemented. The range of the capital cost estimates for the years 2007 to 2012 is even broader, from an annual average of $120 million to an annual average of over $430 million, with years in which the capital cost estimate is more than $500 million.

Choices concerning future fish and wildlife activities that may require expenditures in Bonneville’s other two cost categories are partly dependent on the recovery strategies chosen for mainstem system configuration and partly on the acceptance of scenarios for recovery and restoration strategies apart from the mainstem operation measures. The end result is that the cost estimates for these other two categories have also been expressed in ranges. Thus with regard to reimbursable operation and maintenance expenses, the workgroup’s cost estimates range from an average of $45 million to $55 million per year for 2002 to 2006, and $25 million to $68 million average per year for 2007 to 2012. With regard to Bonneville’s direct expenditures on fish and wildlife projects to implement the Council’s Fish and Wildlife Program and portions of the Biological Opinions, cost estimates prepared by the fish and wildlife managers rise to approximately $170 million to $180 million per year average for 2002 to 2006, and $195 million to $203 million average per year for 2007-2012.

Total estimated expenditures across the three categories under the different fish and wildlife recovery scenarios range from $280 million to $400 million average per year for 2002 to 2006. The range is necessarily greater for the years 2007 to 2012: one Bonneville-estimated alternative averages approximately $315 million per year for those years; most of the alternatives are in the $430 million to $460 million average per year range, while one is over $600 million per year average and another one is over $700 million per year average.

The Northwest Power Planning Council staff has been evaluating other costs and risks of major system configuration options, including effects on foregone revenues, energy and capacity effects, reliability and system stability issues, and ways in which the revenue generated from different price forecasts for Bonneville power relate to the potential costs faced by Bonneville. These analyses are underway, and should be sufficiently developed to provide preliminary estimates by May 1998.

All of these cost estimates and analyses are necessarily preliminary and under refinement. Bonneville is preparing for a rate case for the 2002-2006 period. In doing so, Bonneville is aiming to produce rates that will allow customers to subscribe to energy, without foreclosing any of the system configuration and recovery scenarios now under discussion yet also without conceding that Bonneville will necessarily be obligated to use its power revenues to pay the entire cost of all possible system configuration alternatives. These fish and wildlife cost estimates, while preliminary, should allow Bonneville to present potential customers with a fair range of numbers.

We do not recommend legislation on this subject at this time.