| Northwest Energy Review Transition Board | John Etchart, Montana |
| 851 S.W. Sixth Avenue, Suite 1100 Portland, Oregon 97204-1348 |
John Savage, Oregon |
| Phone 503-222-5161 or 1-800-452-5161 FAX 503-795-3370 |
Marilyn Showalter, Washington |
| Todd Maddock, Idaho |
September 16, 1998
To: Interested Persons
From: Dick Watson, staff
Subject: Transition Board Proposal for Contingent Cost Recovery
Attached for your information is the Transition Board’s proposal for contingent cost recovery as it currently stands. It represents the Board’s thinking as of the date of this revision. Bonneville will soon be announcing its proposal for subscription and will be initiating a public process on that proposal. Bonneville's proposal will probably bear on some of the same issues addressed by the Transition Board. The Board intends to study Bonneville's proposal and the public comment on that proposal as well as to continue to seek the thoughts of interested parties on this proposal. The Board is also directing staff to do further research on some of the issues already raised in public comment on its earlier proposals. The Board will make its final recommendations at the conclusion of this process.
Northwest Energy Review Transition Board
Proposal for a
Contingent Cost Recovery Mechanism
(TB 98-17, Revised September 16, 1998)
For the past several months, the Transition Board has listened carefully to the comments of various interests on the staff’s "strawman" and two versions of the Board’s own draft proposals for a contingent cost recovery mechanism or, as it is frequently called, a "stranded cost" mechanism for Bonneville. The following represents the Board’s thinking as of the date of this revision. Bonneville will soon be announcing its proposal for subscription and will be initiating a public process on that proposal. Bonneville's proposal will probably bear on some of the same issues addressed by the Transition Board. The Board intends to study Bonneville's proposal and the public comment on that proposal as well as to continue to seek the thoughts of interested parties on this proposal. The Board is also directing staff to do further research on some of the issues already raised in public comment on its earlier proposals. The Board will make its final recommendations at the conclusion of this process.
Because Bonneville is constrained legally and by the realities of a competitive wholesale power market, it can effectively only charge rates that are the lower of its costs or market price. Its rates can exceed market prices only for relatively short periods, i.e. within a rate period, before it risks losing customers. The Board believes that, under most circumstances, the probability of Bonneville being unable to recover its costs and the magnitude of those unrecovered costs are relatively small. Perceptions of Bonneville’s future financial condition have generally been improving over recent months. Under some expectations about future market conditions, it is likely that Bonneville’s customers would see substantial benefits relative to purchasing from the wholesale power market, even if Bonneville is called upon to bear additional costs for salmon mitigation or other reasons. There are, however, possible combinations of market conditions and additional costs where Bonneville would be unable to fully recover its costs. It also appears that if Bonneville is to experience cost recovery problems, those problems probably occur in the 2007 – 2012 time frame when it is more likely to be subjected to larger costs and/or reductions in power production as a result of salmon mitigation measures.
Effective cost management can reduce the likelihood that Bonneville could not recover its costs. Also, traditional risk management tools, like building and maintaining adequate financial reserves, can completely or substantially mitigate cost under-recovery under some conditions. However, as a federal agency, Bonneville does not have stockholders who knowingly accepted the risk of losses or who stand to benefit when market prices exceed costs. Congress and the Administration need confidence that, under an acceptable range of conditions, Bonneville will be able to make its payments to Treasury in a timely fashion. Consequently, a contingent cost recovery mechanism is essential if a "Northwest Chapter" of federal restructuring legislation is to be received favorably.
In developing this proposal, the Transition Board is attempting to satisfy the following objectives:
• To the greatest extent possible, the mechanism should align the incidence of future benefits and future risks;
• The mechanism should not disadvantage those who subscribe for Bonneville power relative to their alternative of purchasing on the market;
• The mechanism should minimize and bound the uncertainty to which purchasers of Bonneville power are subject;
• The mechanism should provide incentives for Bonneville to control its costs;
• The mechanism should not allow Bonneville to use its monopoly power in transmission to recover power system costs if power subscribers are paying significantly less than market prices.
• To the extent possible given market conditions and Bonneville’s costs, Bonneville should ensure an adequate level of reserves entering the subsequent rate period (2007—2012). This level of reserves should take into account the risk of costs Bonneville may have to bear during that period.
To achieve these objectives, the Transition Board proposes a staged contingent cost recovery mechanism. The proposed mechanism has two stages of progressively more aggressive actions. These stages are triggered by projected levels of reserves. The trigger for the second stage is a forecast reserve level that would lead to a high probability of deferral of Treasury repayment absent remedial action. The relationship of the different trigger levels, and some important considerations in setting them, are discussed after the description of the stages. These stages of contingent cost recovery are to be preceded by the application of 4(h)(10)(c) credits to the fullest extent possible and the use of financial reserves, including any unused borrowing authority. In addition, effective ongoing cost management must have been exercised before the stages of contingent cost recovery are implemented.
The Transition Board, by proposing a staged mechanism based on projected reserve levels, intends to avoid, if possible, the necessity of implementation of more aggressive subsequent stages or, at least, to minimize them while maintaining a high probability of Treasury repayment. Requiring that these stages be preceded by use of reserves and credits and a process of effective cost management is a safeguard against abuse of the contingent cost recovery mechanisms.
The Transition Board recommends that Bonneville work with the Northwest Power Planning Council to establish a broadly-based cost management advisory committee involving customers and representatives of other key interests. The purpose of this committee would be to consult with Bonneville management on an ongoing basis on issues of both management efficiency and policy choices affecting Bonneville's costs.
The Board further recommends that prior to the initiation of any contingent cost recovery, Bonneville hold a public hearing and make a showing that it has done or is doing all that is feasible to control its costs.
The Transition Board believes that effective cost control is an essential precursor to contingent cost recovery. Cost management should be and is an ongoing activity of Bonneville management. However, the Transition Board believes it is appropriate to build on the Comprehensive Review's recommendation for a customer advisory committee. The ability to consult regularly with a broadly based set of outside interests that understand Bonneville and have a stake in its financial health should be valuable to Bonneville in achieving cost reductions and giving its cost management efforts greater credibility. To ensure that Bonneville has done or is doing all that is feasible to control costs before implementing contingent cost recovery, Bonneville should make a showing to that effect in a public hearing.
If the projected end-of-fiscal-year reserves are below the first trigger level, the administrator should implement a capped rate adjustment mechanism for Bonneville’s power rates for the next fiscal year of the rate period. This mechanism would raise subscriber rates to the lower of:
1. The level necessary to restore reserves to the level necessary to assure the desired level of Treasury repayment, taking into account the effects of any cost reductions achieved through Bonneville’s cost management efforts, or
2. A predetermined market cap.
If feasible, the cap would be set by the New York Mercantile Exchange (NYMEX) futures market at the California-Oregon border (COB, appropriately adjusted for delivery point and product character), over the year following imposition of the rate adjustment. Currently, this futures market more than 4 to 5 months out is "thin." That is, few futures contracts are traded in later months, so the credibility of futures prices as a market projection over a whole year is uncertain. Expanded participation in this market over time may remedy this problem. If, by the time of potential application, the futures market over a span of a year is judged to be sufficiently deep to represent a true market, the futures market should be used. If not, the cap would be set by the margin between actual prices in the past year’s spot market and Bonneville’s monthly prices in the same period, appropriately adjusted for delivery point and product character.
The Transition Board believes that establishing a market cap based on a forward looking market index is preferable in that it reflects the prices at which customers could purchase power over the coming year and is less subject to weather-related variability. However, unless the futures market is sufficiently deep, the index might not be reliable. If that is judged to be the case, a mechanism using actual spot market prices over the past year would be an acceptable substitute. The intent in either case is to allow customers to know the limits of their exposure on a year-ahead basis.
If, after implementation of the first stage, projected reserve levels are at or below a second, lower trigger level that implies a high probability of Treasury deferral, Stage 2 would be implemented. Before reaching this stage, Bonneville would evaluate all its options in both the Power Business Line and the Transmission Business Line for closing the remaining gap between costs and revenues and develop a plan. Upon reaching Stage 2 Bonneville would implement the non-transmission elements of that plan to the extent of its authorities. However, if the plan includes a charge on transmission, that charge would be subject to review by the Federal Energy Regulatory Commission (FERC). The standards for review would be: 1) the "just and reasonable" standard of the Federal Power Act, and 2) the requirement of the Northwest Power Act that "rates be set to assure payment of the Federal investment in the FCRPS over a reasonable number of years after first meeting the administrator’s other costs." FERC would approve the charge or order changes.
FERC review should not include Bonneville’s Power Business Line. However, FERC should not approve a charge unless Bonneville: 1) has made the public showing that it has done or is doing all that is feasible to control costs; 2) has implemented the first stage of contingent cost recovery; and 3) is implementing any other non-transmission elements of its plan to close the gap between costs and revenues. Meeting these conditions should be considered evidence that Bonneville is mitigating its unrecovered costs.
Any power costs recovered through transmission charges would be treated as a loan from the Transmission Business Line to the Power Business Line, to be repaid with interest as soon as conditions permit.. This loan is ultimately borrowed from a mixed group of generators and end-use customers, whose costs of capital are likely to be higher than Bonneville’s. To reflect this situation, at least roughly, interest would accrue at the cost of capital of investor owned utilities. Recovery by this mechanism would be limited to $100 million in any year, up to a cumulative total of $600 million. The duration of this stage of the recovery mechanism would be 15 years.
The question of recovering power system costs from transmission, as part of a contingent cost recovery mechanism, has been a difficult issue for the region. Such cost recovery should occur only if all other potential remedies are being exercised and it should be subject to review by FERC on the same basis as FERC will review other Bonneville transmission rates under the Transition Board’s recommendations for Federal Power Act conformance. If Bonneville has complied with the steps laid out in this proposal, it will have mitigated unrecovered costs such that FERC’s review should not extend to a review of Bonneville’s Power Business Line. However, FERC should not approve a transmission charge unless those steps have been complied with. In addition, to the extent power costs are recovered through transmission, they are to be treated as a loan to ensure that those costs are ultimately allocated to power customers. Because the transmission charge is, in effect, a loan from a mix of generators and end use consumers, an interest rate more representative of their cost of capital than Bonneville's treasury borrowing rate should be used.
The annual and cumulative limits on recovery through this stage are intended to bring about a broader national discussion on the proper allocation of Bonneville’s unrecoverable costs. If unrecoverable costs exceed these limits, it is likely that a major contributor to those costs will be the effects of significant changes to the power system for the purposes of fish recovery mandated by federal law. The limits reflect the recognition that, in this case, there is a broader national interest in and responsibility for the costs of recovery of threatened and endangered species. The fifteen-year period that is allowed for this mechanism is a period long enough to take Bonneville to the point that Supply System debt will have been largely paid.
A target reserve level should be established for the last year of the initial rate period that takes into account anticipated costs during the 2007—2012 period. Both the trigger levels in the final years of the initial rate period should be selected to achieve the end of period reserve level after making the last year’s Treasury payment.
It appears that if Bonneville is going to experience cost recovery problems, those problems are more likely to occur in the 2007 – 2012 period. This is when Bonneville is more likely to be subject to larger costs/and or reductions in power production capability as a result of salmon mitigation measures. The intent of this recommendation is to ensure that Bonneville has reserves entering into that period that take into account the risks of higher costs during that period.
Our proposal is to implement Stage 1 measures followed by implementation of stage 2 measures if the first stage measures prove insufficient to remedy the problem. This means that the first trigger must be at a higher level of projected reserves than the second trigger. The margin between trigger levels should be sufficient to allow each stage’s effects a chance to make implementation of the next stage unnecessary. The trigger levels should be such that the likelihood of reaching them is relatively small but not so small as to make the subsequent cost recovery mechanisms ineffective. The coordination among the target level of reserves and trigger levels for contingent cost recovery stages will require a significant analytical effort. Bonneville has performed these analyses in the past and should set these levels as part of the rate case to accomplish these goals.
The overall probability of making Bonneville’s payment to the Treasury is affected by a number of variables under Bonneville’s control. Bonneville calculates the probability of making its Treasury payment taking into account net revenues for risk included in their basic power rates, together with any contingent cost recovery mechanisms like cost reductions and rate adjustment. The target level of reserves is that end-of-year level that yields an acceptably high probability of making all of the Treasury payments during the five-year rate period. The trigger levels are those levels of reserves that trigger those mechanisms. The trigger levels would typically be set below the target levels because random variability in water conditions and markets could have a reasonable probability of restoring reserves to the target level without resorting to other mechanisms.
The target level of reserves and the levels of projected reserves used as triggers for power rate adjustments and the last stage of contingent cost recovery can vary but these levels must be coordinated to meet a given level of confidence of making the Treasury payment. Raising the net revenues for risk in power rates, other things being equal, would allow lower triggers for the stages of contingent cost recovery while maintaining the same probability of Treasury payment. Conversely, for a given target level, lowering the trigger level for one mechanism would require raising the trigger levels for the other mechanism.