June 11, 1998
TO: Interested Parties
FROM: Transition Board
SUBJECT: Draft proposal for FERC regulation of Bonneville and a contingent cost recovery mechanism to be included in the "Northwest Chapter" of national utility restructuring legislation
The Transition Board has released a draft proposal for FERC regulation of Bonneville and a contingent cost recovery mechanism. The proposal is to include these components in a "Northwest Chapter" of national utility restructuring legislation. The Transition Board will hear comments at its meeting in Portland on June 25, and will accept written comments until July 1. In July the Transition Board plans to revise its proposal and forward it to the region’s governors.
Draft Proposals for
Federal Energy Regulatory Commission Regulation of Bonneville Transmission and
For the past several weeks, the Transition Board has listened carefully to the comments of various interests on the staff’s "strawman" proposals for Federal Energy Regulatory Commission (FERC) regulation of Bonneville transmission and a contingent cost recovery mechanism or, as it is frequently called, a "stranded cost" mechanism for Bonneville. Based on our consideration of those comments and our analysis of the issues, we have developed this proposal on which we seek public comment. This proposal is in no way final. We remain open to and interested in the views of interested persons and organizations throughout the region. We will consult extensively with interests on this proposal before making our final recommendations to the Governors. We also understand that there are a number of possible issues involving the subscription process. While we do not address subscription directly in this proposal, we may find it necessary to address it at a later date.
Among its other recommendations, the Comprehensive Review recommended that Bonneville be "legally separated into two organizations – a power marketing organization ... and a transmission organization." 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.
Since its formation in April 1997 the Transmission Work Group has examined various forms of separation. It considered such issues risks and complexities of pursuing legislation, perceived impacts on the security of WPPSS bonds, and assignment of Bonneville’s current treaty obligations. The group eventually decided that the most practical option is functional separation of Bonneville’s business lines with regulation by FERC of the transmission business line (TBL) that is "equivalent" to FERC’s regulation of investor-owned utilities (IOUs). The work group has found considerable agreement on what FERC’s regulation of Bonneville should look like, but has not reached consensus on all aspects. This proposal by the Transition Board includes policy direction on some aspects, and solicits further comment on others.
Two alternative legislative approaches to FERC regulation of Bonneville were discussed in the work group. One is based on Bonneville’s "organic" statutes [ These 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 and others.] , with amendments to these statutes as appropriate to redefine FERC’s authority. The other approach is based on the Federal Power Act and FERC’s authority over investor-owned utilities, with appropriate modifications to reflect Bonneville’s special circumstances. While it should be possible to come to the same definition of FERC’s authority by either path, the work group could not come to agreement on which path to take.
The Transition Board’s proposal starts with FERC’s authorities in Parts II and III of the Federal Power Act, with modifications for Bonneville. We could arrive at the same definition of FERC’s authority by starting with Bonneville’s organic statutes. This approach, however, will make it easier to demonstrate to the rest of the country that Bonneville’s transmission system is subject to regulation that is fundamentally the same as for other transmission systems elsewhere. It also seems simpler to make an explicit list of modifications to the FPA than to comb through Bonneville’s organic statutes to find all the places where changes are necessary. It will be necessary to include language that overrides sections of Bonneville’s organic statutes that conflict with the proposed authorities of FERC. Finally, it is more consistent with FERC final authority for FERC to be interpreting its own statute than Bonneville’s statutes, however modified.
The Transition Board recommends that section 201 of the Federal Power Act be amended to make it clear that FERC’s authority under the Federal Power Act is limited to Bonneville’s transmission and does not expand FERC’s authorities over Bonneville’s power marketing. The Transition Board also recommends that Bonneville be excluded from FERC’s authorities under sections 204, 207, 209, 214, and 305 of the Federal Power Act and that section 212(i) be repealed. The Transition Board recognizes that disagreement persists regarding subjecting Bonneville to FERC’s authorities under sections 202, 302, 307, 314, 315 and 316 (see attachment, "What Sections of the Federal Power Act Should Apply to Bonneville?"). The Board is not yet prepared to make recommendations on these sections and invites specific comment from the public on them.
[ This proposal is made with the understanding that: a) Congress can override a FERC order to build transmission facilities; and b) it is FERC’s practice to phase in, over time, costs shifts among customers resulting from FPA compliance.]
1. Total transmission cost recovery. Generally, FERC should apply the "just and reasonable" standard to Bonneville’s transmission rates. However, Bonneville has no stockholders to absorb losses, so FERC cannot disallow recovery of Bonneville costs already incurred.
2. Nothing in FERC’s regulation of Bonneville should adversely affect Bonneville’s priority of payments or the security of its third party debt.
3. The environmental obligations of federal and non-federal users of Bonneville’s transmission (e.g. to control nitrogen levels at hydro projects by generating to avoid spill) sometimes require access to Bonneville’s transmission. To the maximum extent possible, users should obtain this access and pay for it through a normal open access transaction. In rare instances, open access transactions may be inadequate to assure access. In those rare instances, the users will require priority access, with equitable compensation determined by an after-the-fact mechanism.
4. Except to the extent that FERC may be given authority over Bonneville’s stranded costs, there should be no expansion of FERC authority over Bonneville power costs.
5. The redefined authority of FERC should apply only to transmission tariffs and other transmission matters proposed by the Administrator to be effective on or after October 1, 2001.
6. Bonneville should be permitted to join a FERC-regulated independent system operator. Currently the participation of investor-owned utilities in ISOs is voluntary. The issue of mandated participation in ISOs is under discussion at FERC.
The Transition Board’s philosophy in this proposal is to concentrate the departures from usual FERC regulation in the guidelines for FERC decisions, rather than in the decision process. Most of the differences in FERC regulation of BPA, compared to its regulation of jurisdictional utilities, are in the explicit list of exceptions, above. The Transition Board’s proposed process for FERC review of Bonneville transmission rates is intended to be identical to that followed for investor-owned utilities, except that hearings on Bonneville rates would be held in the Pacific Northwest. The result, hopefully, is a "clean" process that is familiar to FERC, with clear direction at those points where regulation of Bonneville is different than regulation of investor-owned utilities.
The following summarizes the existing Federal Power Act process for filing, approval and appeal of Bonneville transmission rates, terms and conditions, with slight modification.
1. Bonneville conducts a regional negotiation to gain a settlement, if possible, on transmission rates, terms and conditions. As is the current practice, in its proceedings FERC would give substantial weight to settlements at any stage.
2. Bonneville files its transmission rates, terms and conditions with FERC.
3. FERC may accept or reject the filing, or order a hearing. Hearings are conducted by a FERC administrative law judge in the Pacific Northwest and result in an initial decision by the ALJ.
4. FERC considers the ALJ’s initial decision and record and briefs from Bonneville and other interested parties, and issues its final decision on rates.
5. Bonneville (and other parties) can request a rehearing with FERC.
6. Bonneville (and other parties) can appeal FERC’s decision to the Circuit Court of Appeals (Ninth Circuit or District of Columbia Circuit). The court reviews FERC’s order.
7. Given that Bonneville would be appealing another federal entity ruling, they should be allowed to provide their own legal representation.
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 before it loses 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, the U.S. Treasury will not be called upon to absorb long-term losses. Consequently, a contingent cost recovery mechanism is an essential element of a "Northwest Chapter" of federal restructuring legislation.
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 provide for broad regional participation to ensure cost recovery consistent with the foregoing objectives.
• 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 achieve these objectives, the Transition Board proposes the following contingent cost recovery mechanism. The proposed mechanism has three stages:
Any revenue insufficiency will first be addressed through application of 4(h)(10)(c) credits to the extent possible and the use of financial reserves.
If financial reserves are exhausted and Bonneville is forced to defer a Treasury payment, the administrator should implement a capped rate adjustment mechanism for Bonneville’s power rates. This mechanism would raise subscriber rates to the lower of:
(1) The level necessary to eliminate the revenue shortfall, or
(2) A predetermined cap. The cap would be set in the rate case leading to the subscription period based on a commonly accepted independent forecast or indicator of market prices during the rate period.
This mechanism will provide clarity to potential power subscribers before subscribing regarding their possible exposure to upward rate adjustments.
Any remaining unrecovered costs would be recovered through a uniform transmission charge. The charge would be limited to $100 million in any year, up to a total of $500 million. The duration of the recovery mechanism would be 15 years – a period long enough to take Bonneville to the point that Supply System debt will have been largely paid off. This stage is implemented only after the first two stages have proved inadequate to address Bonneville’s cost under-recovery. This stage is intended to result in broad regional participation in helping address Bonneville’s cash flow problem while not disadvantaging Bonneville’s power customers relative to the market.
The charge would be levied in the form of a charge for access to the transmission system based on the demand placed on the system in the year in which the deferral occurred. This approach is intended to encourage efficient use of the system, in contrast to the effect of a charge levied on kwh transmitted, which would penalize the marginal transaction.
Any recovery from the transmission system would be treated as an obligation of the Power Business Line to the Transmission Business Line that would be repaid when conditions permit with interest calculated at Bonneville’s cost of capital. With this mechanism, power subscribers would repay the Transmission Business Line out of their future benefits. If there are no future benefits, there is no repayment.
Any power customer that subsequently chooses not to re-subscribe for Bonneville power shall have an obligation to repay its share of any Power Business Line obligation to the Transmission Business Line.
To the extent possible given market conditions and Bonneville’s costs, Bonneville should set rates to ensure an adequate level of reserves entering the subsequent rate period.
It is essential that customers and others have confidence that there are adequate safeguards to ensure that Bonneville has incentives to manage its costs as effectively as possible. This is particularly so in the third stage where Bonneville has monopoly power over the transmission system. The following safeguards would be employed:
• The administrator must make full use of his authority under section 4(h)(10)(c) of the Northwest Power Act before implementing contingent cost recovery.
• Contingent cost recovery could only be implemented in the case of an actual deferral of Treasury payments.
To implement the third stage of contingent cost recovery Bonneville would have to carry out a rate proceeding. The Administrator’s decision to impose a transmission surcharge would be reviewed by the Federal Energy Regulatory Commission (FERC). The function of FERC review would be to see that Bonneville was adequately mitigating the stranded costs through opportunities to reduce costs and increase revenues while fulfilling its legal obligations. FERC would not have authority to make judgments on the prudence of past expenditures.
The Transition Board’s Transmission Work Group has discussed which parts of the Federal Power Act (FPA) should apply to Bonneville, both in a small group of attorneys and in meetings of the whole work group. While the group has reached consensus on a number of the sections of the FPA, there is still disagreement on several sections:
1. FPA section 201 - Declaration of policy; application of Part: (a) Federal regulation of transmission and sale of electric energy; (b) use or sale of electric energy in interstate commerce; (c) electric energy in interstate commerce; (d) "sale of electric energy at wholesale"; (e) "public utility" defined; (f) United States, State, political subdivision of a State, or agency or instrumentality thereof exempt; (g) books and records -- The group reached consensus that this section needs an amendment to make it clear that the authority of the Federal Energy Regulatory Commission (FERC) over Bonneville under the FPA would apply to Bonneville’s transmission, not its power marketing. The group was not able to reach consensus on the specific wording of that amendment.
2. FPA section 202 - Interconnection and coordination of facilities; emergencies; transmission to foreign countries: (a) Regional districts; establishment; notice to State commissions; (b) sale or exchange of energy; establishing physical connections; (c) temporary connection and exchange of facilities during emergency; (d) temporary connection during emergency by persons without jurisdiction of Commission; (e) transmission of electric energy to foreign country; (f) transmission or sale at wholesale of electric energy; regulation; (g) continuance of service -- The group could not reach consensus on the applicability of this section. Some parties are concerned that this section would allow FERC to require Bonneville to join an Independent Grid Operator (IGO); other parties feel that if investor-owned utilities (IOUs) are required to join, Bonneville should face the same requirement. There was also some concern that this section might subject Bonneville to some undesirable interaction with state regulators.
3. FPA sections 302 - Rates of depreciation; notice to State authorities before fixing -- The group was unable to reach consensus. Bonneville is concerned that this section could force it to change its methodology in scheduling repayment of its debt to the federal treasury.
4. FPA section 307 - Investigations by Commission: (a) Scope; (b) attendance of witnesses and production of documents; (c) resort to courts of United States for failure to obey subpoena; (d) testimony by deposition; (e) deposition of witness in a foreign country; (f) deposition fees -- The group reached partial consensus. It agreed that FERC investigations and power to issue subpoenas should apply to Bonneville (Bonneville reiterates that FERC’s power is limited to transmission-related matters). The group agreed that FERC authority to order depositions should apply to Bonneville, but Bonneville is concerned that this authority should not waive existing privileges (e.g. executive privilege). The group did not reach consensus on whether or how to meet Bonneville’s concern. There was also disagreement on the authority of courts to order response to subpoenas and to impose criminal and financial penalties on BPA employees.
5. FPA section 314 - 316 –
FPA section 314 - Enforcement of provisions (a) Enjoining and restraining violations; (b) writs of mandamus; (c) employment of attorneys
FPA section 315 - Forfeiture for violations; recovery
FPA section 316 – Penalties
The group could not reach consensus on enforcement and penalties applied to Bonneville and its employees. Bonneville views these sections as unnecessary, since Bonneville would always obey an order of FERC. Other parties, while they agree these sections are unlikely to be exercised, view the sections as ensuring treatment for Bonneville that is comparable to that of other utilities.