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“Strawman” Proposal for the Northwest Power System”
1. Instructions to the Strawman drafters
1.1. A “Sharp-edged” proposal – one that strikes sharp distinctions on issues.
1.2. Definitive decisions on key issues – not a set of choices.
1.3. Proposal should keep benefits in the NW.
Benefits accrue to end-users, not intermediaries.1.4. Generally consistent with the Steering Committee's points of consensus where they are not in conflict.
2. Governors' charge to the Steering Committee
2.1. Goal of the review is to develop, through a grassroots process, recommendations for the Northwest states, the tribes, the Clinton administration and the Congress regarding needed changes in the institutional structure of the region's utility industry.
2.2. These changes should be designed to:
2.2.1. Protect the region's natural resources.
2.2.2. Distribute equitably the costs and benefits of a more competitive marketplace.
2.2.3. Assure the region of an adequate, efficient, economical and reliable power system.
3. Summary of the Proposal
3.1. Transmission – Transmission system operated by an IGO with Bonneville a member.
3.2. Competition, Consumer Access – recommended principles or guidelines for state regulators and local boards and commissions aimed at retail utilities being prepared to accommodate open access for all customers by 2001.
3.3. Conservation, renewables and low income – a regional meters charge equivalent to $1/month/household to support market transformation, some additional regional conservation, renewables RD&D and existing pilots, and low income weatherization.
3.4. Federal Power Marketing:
3.4.1. A system of long term (30 year) subscriptions to:
3.4.1.1. the firm output of the federal system at cost, take or pay, or
3.4.1.2. a share of the net revenues, positive or negative, from sale of federal power products at market.
3.4.2. A subscriber board with budget authority;
3.4.3. a sharing of potential benefits (excess of market prices over costs) with fish and wildlife.
3.4.4. provisions for releasing subscribers from their take or pay obligations if hydro system capability is degraded beyond certain limits; and
3.4.5. A backup system of selling output of federal system at market with any losses charged to current firm power customers and any dividends returned to those customers, unless retained by Treasury.
4. Transmission
4.1. Goal: A transmission system that:
4.1.1. Helps ensure a fully competitive generation market.
4.1.2. Improves the efficiency (asset utilization) of the transmission system.
4.1.3. Maintains reliability.
4.2. Givens/Assumptions:
4.2.1. The FERC will insist on:
4.2.1.1. Open, non-discriminatory access to the transmission system.
4.2.1.2. Effective separation of generation and transmission decisions.
4.2.2. Membership in FERC-regulated IGO will provide effective separation.
4.2.3. An Independent Grid Operator (IGO) is being formed in the region.
4.3. Concerns about security of Supply System debt require maintaining single Bonneville fund and make legal separation of Bonneville power marketing and transmission difficult.
4.4. Transmission Recommendations:
4.4.1. Bonneville should become a full participant in the IGO:
4.4.1.1. Legislation clearing way for Bonneville to turn over operation of federal transmission assets to IGO.
4.4.1.2. Legislation to subject Bonneville's transmission revenue requirement to FERC regulation on same basis as IOUs. FERC regulation of cost transfers to transmission protects transmission users.
4.4.2. IGO governing board includes owners and users; and state and regional regulatory and policy entities on ex officio basis similar to NRTA, WRTA.
4.4.3. IGO membership is voluntary (other than Bonneville).
4.4.4. Local load control centers can be maintained.
4.4.5. Wheeling for retail loads:
4.4.5.1. IGO governed by eligibility rules of FERC Order 888.
(OK if authorized by state or utility in which load is located)
4.4.5.2. Before Bonneville is member of IGO, Bonneville should honor the same rules.
4.4.6. Pricing - IGO establishes transmission pricing consistent with:
4.4.6.1. Principles to be determined through WRTA, NRTA.
4.4.6.2. FERC regulation.
4.4.7. Transmission will not be used to collect non-transmission costs unless:
4.4.7.1. States cannot implement meter charge for conservation, renewables, low income services (see Conservation, Renewables, Low Income).
4.4.7.2. Necessitated by failure of proposed federal power marketing system and collection is consistent with FERC rules.
5. Competition, Consumer Access
5.1. Goal: A competitive electricity market that delivers lower prices, increased choice, product innovation and continued reliability to all consumers.
5.2. Givens/Assumptions:
5.2.1. Retail access is a given, the only questions are transitional: who gets access, how quickly, under what circumstances.
5.2.2. Speed of implementation important to minimizing cost shifts among customer groups.
5.2.3. An effective and equitable competitive electricity market requires access by all customers to alternative sources of electricity supply and unimpeded access by alternative electricity suppliers to consumers.
5.3. Nature of the Recommendations for Consumer Access:
5.3.1. They are recommended principles or guidelines.
5.3.2. Decisions are up to state regulators and locally-elected boards and commissions.
5.4. Consumer Access Recommendations:
5.4.1. By 2001, all retail utilities should be prepared to accommodate open access by all customers.
5.4.2. To be prepared to accommodate open access, regulators or the boards or commissions of retail utilities should:
5.4.2.1. At least functionally unbundle distribution parallel to FERC requirement for functional unbundling of generation and transmission (divestiture not required).
5.4.2.1.1. Itemized billing for energy charges and distribution system costs.
5.4.2.1.2. Distribution system charges cost-of-service based.
5.4.2.2. Provide non-discriminatory open access to distribution system to aggregators, new energy service providers.
5.4.2.3. Establish an obligation to connect for distribution entity although not necessarily an obligation to provide energy service after the transition period.
5.4.2.4. Adopt policies for recovery of legitimate, non-mitigable stranded investment that minimize cost transfers.
5.4.2.4.1. Exit fee or distribution access fee.
5.4.2.4.2. Utility should have incentive to mitigate stranded cost to greatest extent possible.
5.4.2.4.3. Transitional in nature – limited in duration and amount.
5.4.2.5. Consider the need for and adopt if necessary.
5.4.2.5.1. Consumer protection for small consumers.
5.4.2.5.2. Licensing standards for alternative service providers.
5.5. Speeding the transition:
5.5.1. Allow large consumers access when cost transfers are acceptably minimized.
5.5.2. Carry out pilot programs to provide access to small customers.
5.5.3. Permit “Green Marketing” of power from renewable resources.
5.5.4. These steps:
5.5.4.1. Gain experience in operating in an open access environment.
5.5.4.2. Promote development of load aggregators/ alternative retail electricity service providers.
5.6. Transition to a Fully-Functioning Competitive Retail Market (2001-2006):
5.6.1. Distribution utility should have obligation to ensure reliability AND ability to charge for the service.
5.6.2. Distribution utility should be the “provider of last resort” for potentially “red-lined” customers and those who don't or can't choose and alternative supplier.
5.6.2.1. Recovery of any additional costs incurred in serving these customers is the decision of the appropriate regulators or governing bodies.
6. Conservation, Renewables, Low Income Energy Services
6.1. Goals/Givens:
6.1.1. Conservation:
6.1.1.1. Minimize total cost of energy services to individuals.
6.1.1.2. Rely to the greatest extent possible on and facilitate market mechanisms.
6.1.1.3. Market outcomes are likely to deviate from socially desired outcomes – some market intervention will be necessary.
6.1.1.4. Support for interventions should be funded from competitively neutral sources.
6.1.2. Renewables:
6.1.2.1. Preserve renewables as long term option.
6.1.2.2. Maintain and enhance capability for renewables and distributed generation through research and limited demonstration.
6.1.2.3. Allow renewables opportunity to compete for customers.
6.1.3. Low income weatherization and energy assistance:
6.1.3.1. Federal funding for these activities is declining.
6.1.3.2. Energy service needs of low income population are not being met and are more costly to provide than for other consumers.
6.1.3.3. Low income consumers may not be “desirable” customer group in competitive environment.
6.1.3.4. Low income energy assistance is more appropriately a general purpose government function.
6.2. Near Term Actions – 1997 - 2001:
6.2.1. BPA and Utilities should support conservation market transformation activities:
6.2.1.1. $15 million/year from BPA and a proportionate amount from Investor-owned utilities – total of approximately $30 million/year.
6.2.1.2. Implemented through a non-profit corporation.
6.2.2. In order to assure a smooth transition, utility conservation acquisitions should be consistent with their submissions to the 1996 PNUCC Northwest Regional Forecast.
6.2.3. BPA and utilities should:
6.2.3.1. Finish wind projects already underway.
6.2.3.2. Complete resource exploration, confirmation and environmental assessment phases of current geothermal projects but not complete unless market for power exists.
6.2.4. BPA and utilities should continue current levels of support for renewables research.
6.2.5. Federal, state, local and utility low income energy services should not be diminished during interim.
6.3. Funding Conservation, Renewables, Low Income Energy Services – Beyond 2001:
6.3.1. By 2001 states should implement a meters charge to fund regional conservation, renewables, low income weatherization.
6.3.1.1. Distribution access charge equivalent to approximately $1/mo. /household (commercial, industrial meters charged proportionately) – charge is a statutory CAP.
6.3.1.2. Not volumetric – does not distort marginal price signal.
6.3.1.3. Charge adjusted annually by GDP deflator.
6.3.1.4. Target amount approximately $100 million/year.
6.3.2. Funding Safety Net – Legislation directing FERC to authorize a Transmission Access Charge as backup in case states are unable to implement meters charge by 2001.
6.3.2.1. Distribution companies or direct access consumers in region charged for access to deliveries from the transmission system – no charge for transactions not destined for end-uses in region.
6.3.2.2. Access charge equivalent to the meters charge.
6.3.2.3. Collected by IGO.
6.3.3. Utilities should maintain their current low income energy assistance at current levels until such time as these activities are picked up by general purpose government funding.
6.4. Regional Conservation & Renewables Entity:
6.4.1. A regional entity administers the revenues from the charge for the purposes of:
6.4.1.1. Market Transformation – activities designed to effect permanent changes in the markets for targeted energy efficient products or services.
6.4.1.2. Regional conservation (acquisition best carried out at regional level e.g., multiple-facility industries; chains and franchises).
6.4.1.3. Renewable and distributed generation research (e.g., resource confirmation activities); limited demonstration (e.g., direct application renewables).
6.4.1.4. Backup of green marketing efforts of current wind projects (i.e., make up difference between revenues and cost) As these projects are successfully marketed through green marketing, the freed-up money will be used for additional renewables RD&D.
6.4.1.5. Low-income weatherization.
6.4.2. Regional entity also responsible for:
6.4.2.1. Providing information and establishing goals for conservation and renewables – INFORMATIONAL NOT REGULATORY.
6.4.2.2. Tracking progress.
6.4.2.3. Conducting a public review of effectiveness of regional efforts every 5 years.
6.5. Local conservation –
Additional local conservation may be undertaken by consumers in response to the market or by local utilities or retail service providers for their own reasons – there is no regional requirement or funding for such conservation.
7. Federal Power Marketing
7.1. Goals and Givens:
7.1.1. Align long-term risks and benefits of federal power.
7.1.2. Should not increase risk to tax-payers or compromise security tax-exempt status of third party debt.
7.1.3. Consistency with emerging competitive markets and regional transmission solutions.
7.1.4. Solution should be robust under uncertain future conditions.
7.1.5. Maintain reliability.
7.1.6. Preserve benefits of the federal base system for the region.
7.1.7. Maintain public and regional preference.
7.1.8. Market federal power at cost.
Note: The drafters believe there are fundamental inconsistencies between preference-based, market-at-cost systems and an open, competitive retail market. This proposal is an attempt to bridge those inconsistencies.
7.2. The proposal – the Megawatt Subscription Version:
7.2.1. Long-term subscriptions to the firm power output of the federal base system at cost consistent with public and regional preference:
7.2.1.1. Rights to long term benefits.
7.2.1.2. Responsibility for costs including risks of weather, market, most fish & wildlife actions.
7.2.2. Greater customer budget authority over federal power marketing.
7.2.3. Limitation on risk of degradation of power system performance due to additional fish and wildlife measures.
7.2.4. Bonneville does not acquire resources to serve load growth except on a bilateral contract basis where the customer absorbs the risk.
7.2.5. The implications of this proposal for the tax-exempt status of third party bonds need to be examined.
7.3. Greater customer budget authority over power marketing:
7.3.1. Bonneville should be reconstituted as a federal corporation authorized to borrow from private debt markets. It could transition to a private corporation/co-op as the Supply System and federal debt is repaid and the majority of the debt is privately held.
7.3.2. A subscriber budget board should be elected by subscribers. Votes by subscribers for board members should be proportional to firm MW subscribed.
7.3.3. Board will have authority over the budget requests of non-fish related overall capital budgeting levels and operating cost levels, and power-related capital and operating cost decisions of the Corps and Bureau.
7.3.3.1. Appropriation authority remains with Congress.
7.3.3.2. The board will have authority over private-market borrowing decisions.
7.3.4. The board would have authority over decisions regarding the operation or termination of non-hydro elements of the Federal system.
7.4. Regional public policy board –
a regional policy board would provide the Bonneville Corporation with public policy oversight. The policy board would:
7.4.1. Provide regional oversight of system reliability.
7.4.2. Provide regional oversight of the transition to competitive markets:
7.4.2.1. Market power issues.
7.4.2.2. Degree of competition.
7.4.2.3. Consumer protection issues.
7.5. River governance and its relationship to customer budget authority over power marketing:
7.5.1. A river governance entity should be created having decision-making authority over fish operations and budgets. The effects on power costs borne by the subscribers is described in G below.
7.5.2. Beyond this, river governance is unspecified. The governors need to address this question immediately.
7.5.3. Until this question is resolved, fish policy will be decided by existing institutions under existing authorities.
7.6. Disposition of Federal power:
7.6.1. Processes for disposition of federal power should be completed by 2001, so the results can be in place when existing Bonneville contracts expire.
7.6.2. There should be an initial subscription for firm power:
7.6.2.1. Firm power should be offered first for 30-year terms, at cost, take or pay, to all takers, in priority order (preference customers, representatives of IOU domestic and small farm load, other regional customers, non-regional customers):
7.6.2.1.1. “Preference customers” are existing public agency customers. Contracts are limited to contractual load rights on Bonneville as of January, 1995.
7.6.2.1.2. DSIs may participate with preference customers IF they agree to participate with preference customers in the “Backup” system described below. Contracts are limited to contractual load rights on Bonneville as of January, 1995.
7.6.2.1.3. “Representatives of IOU domestic and small farm load” could be IOUs or non-utility aggregators that have Northwest residential load or small farm load as certified by state regulators. In the case of IOUs or aggregators, the subscription is limited by the load of the qualifying consumers.
7.6.2.1.4. “Other regional customers” means IOUs, existing DSIs, and aggregators for other Northwest consumers, with no priority among them. The subscription is limited by the load of the qualifying consumers.
7.6.2.1.5. Out of region customers.
7.6.2.2. Subscriptions will first be offered to all regional entities in priority order. If still under-subscribed, regional entities would be offered another opportunity to subscribe for additional amount, again in priority order.
7.6.2.3. If there is over-subscription, there will be an allocation. The allocation sequence is by priority order (above). For regional entities, the allocation will be pro-rata shares of subscriptions within the priority class on the margin. For non-regional entities serving non-regional loads, bids will be for cost plus some offer.
7.6.3. The firm power subscription:
7.6.3.1. Firm power should be subscribed to by month, allowing subscriptions to build up to the desired annual load shape. The subscriber is responsible for deviations from that load shape.
7.6.3.2. The threshold amount of firm power for subscription should be some large fraction, e.g., 95 percent of the firm output of the federal system (the total available from both the federal hydro projects under river operations in place at the time of the subscription plus the capability of the non-hydro projects included in the federal system). This should be estimated as a safe amount given the various possibilities for future changes in output for any reason. At the time of subscription, and based on their current river operations, a base fish cost will be defined.
7.6.4. Recall – contracts are not subject to any recall once signed.
7.6.5. Resale – subscribers may resell the power or the subscription.
7.6.6. Remaining firm power and other products should be sold at market whenever possible and revenues used to reduce costs to the subscriber. If FERC determines there is not a competitive market for a product, that product may have to be sold at cost.
7.6.7. Backup System:
7.6.7.1. If the total subscription is less than the threshold amount offered, the subscription process is void and a default assignment system is implemented:
7.6.7.1.1. A federal corporation is formed and a budget board of the assignees created with the same powers as in the subscription system.
7.6.7.1.2. All power is sold on the market for any term that would maximize the revenue.
7.6.7.1.3. Any remaining net cost above market (stranded cost) should be assessed as a meters charge or a directed transmission charge to the preference customers prorated in proportion to contracted load on Bonneville as of January 1995.
7.6.7.1.4. Any net benefits, subject to the benefit sharing for fish described below, should be directly assigned to the same entities, as an annual lump sum rebate.
7.6.7.2. Existing DSIs can be included in the first priority for subscriptions if, and only if, they submit themselves to the backup procedures described above.
7.6.7.3. There should be provision for a one-time buyout of the net stranded cost obligation.
7.6.7.4. Increased costs resulting from a greater than 15 percent reduction from the annual sum of the firm monthly power capability of the federal hydro projects (under river operations in place at the time of the subscription) due to modification of river operations for fish would not be eligible for stranded cost recovery under the backup system.
7.7. Fish cost risk mitigation – fish cost risk must be defined and predicted and constrained appropriately given the level of benefit under the contracts. The intent is to create a system analogous to FERC regulation of hydropower facilities:
7.7.1. Subscribers accept the risk of increased fish and wildlife program costs and capital costs, except those costs associated with projects that would reduce the annual sum of the hydro system firm monthly capability under river operations in place at the time of the subscription by more than 15 percent.
7.7.2. A reduction of 15 percent in the annual sum of the hydro system firm monthly energy capability under river operations in place at the time of the subscription would give subscribers the option of release from their take or pay obligations.
7.7.3. Whenever market prices are above the subscribed cost including base fish costs, 30 percent of the benefit (market prices less the subscribed costs) will be a dividend for fish and wildlife. Market prices should be determined by some commonly accepted index, short or long term, available by 2001.
7.8. Low density discount:
7.8.1. Should be replaced by a one-time buyout at the present value over the 10 years after 2001 of the current level of the discount or $100 million, whichever is less.
7.8.2. The buyout should be limited to existing low density discount customers, and individually limited by their distribution and local transmission system debt as of January, 1996.
7.9. Bonneville should not sell directly to new retail loads:
7.9.1. Bonneville may sell to intermediaries subject to state and local jurisdiction.
7.10. There are no changes to any subsidies from power users to non-power users of the system. Any modification of these subsidies would be the responsibility of the Subscriber Budget Board.
8. Federal Power Marketing - Dividend Subscription Version
This version is a response to concerns about the difficulty and inflexibility of the MW subscription version in a very rapidly changing market environment and an attempt to deal with the inconsistency of marketing federal power at cost in a competitive market environment. The underlined italic text highlights the features that are different from the MW subscription version.
8.1. Goals and Givens:
8.1.1. Align long-term risks and benefits of federal power.
8.1.2. Should not increase risk to tax-payers or compromise security and tax-exempt status of third party debt.
8.1.3. Consistency with emerging competitive markets and regional transmission solutions.
8.1.4. Solution should be robust under uncertain future conditions.
8.1.5. Maintain reliability.
8.1.6. Preserve benefits of the federal base system for the region.
8.1.7. Maintain public and regional preference.
8.1.8.
Market federal power at cost.
Key features: Bonneville and its board operate the federal system and market its products (at wholesale only) to maximize its net revenues. Subscribers contract for the long-term right to dividends from the net revenues (after all obligations, including Treasury payments, are met) and assume long-term obligations for any net costs, on the same basis. Bonneville sells at market-based prices and there is no obligation to purchase from Bonneville associated with subscriptions.
8.2. The proposal:
8.2.1. Long-term subscriptions to the dividends based on net revenues (positive or negative) from the federal base system consistent with public and regional preference.
8.2.1.1. Rights to long term benefits.
8.2.1.2. Responsibility for costs including risks of weather, market, most fish & wildlife actions.
8.2.2. Greater subscriber budget authority over federal power marketing.
8.2.3. Limitation on risk of degradation of power system performance due to additional fish and wildlife measures.
8.2.4. Bonneville does not acquire resources to serve load growth except on a bilateral contract basis where the customer absorbs the risk.
8.2.5. The implications of this proposal for the tax-exempt status of third party bonds need to be resolved.
8.3. Greater subscriber budget authority over power marketing:
8.3.1. Bonneville should be reconstituted as a federal corporation authorized to borrow from private debt markets. It could transition to a private corporation/co-op as the Supply System and federal debt is repaid and the majority of the debt is privately held.
8.3.2. A subscriber budget board should be elected by subscribers. Votes by subscribers for board members should be proportional to the shares of the net revenues subscribed.
8.3.3. Board will have authority over the budget requests of non-fish related overall capital budgeting levels and operating cost levels, and power-related capital and operating cost decisions of the Corps and Bureau:
8.3.3.1. Appropriation authority remains with Congress.
8.3.3.2. The board will have authority over private-market borrowing decisions.
8.3.4. The board would have authority over decisions regarding the operation or termination of non-hydro elements of the Federal system.
8.4. Regional public policy board –
a regional policy board would provide the Bonneville Corporation with public policy oversight. The policy board would:
8.4.1. Provide regional oversight of system reliability.
8.4.2. Provide regional oversight of the transition to competitive markets:
8.4.2.1. Market power issues.
8.4.2.2. Degree of competition.
8.4.2.3. Consumer protection issues.
8.5. River governance and its relationship to customer budget authority over power marketing:
8.5.1. A river governance entity should be created having decision-making authority over fish operations and budgets. The effects on power costs borne by the subscribers is described below.
8.5.2. Beyond this, river governance is unspecified. The governors need to address this question immediately.
8.5.3. Until this question is resolved, fish policy will be decided by existing institutions under existing authorities.
8.6. Disposition of Federal power:
8.6.1. Processes for disposition of federal power should be completed by 2001, so the results can be in place when existing Bonneville contracts expire.
8.6.2. All power products should be sold at market whenever possible to maximize net revenues and revenues used to generate dividends to be distributed to subscribers in proportion to their shares. If FERC determines there is not a competitive market for a product, that product may have to be sold at cost.
8.6.3. There should be an initial subscription for shares of the net revenues:
8.6.3.1. Contracts for shares of the net revenues should be offered first for 30-year terms, at cost, to all takers, in priority order (preference customers, representatives of IOU domestic and small farm load, other regional customers, non-regional customers).
8.6.3.1.1. “Preference customers” are existing public agency customers. Contracts are limited to the share that a subscriber's contractual load rights on Bonneville as of January, 1995 were of the total regional load on Bonneville.
8.6.3.1.2. DSIs may participate with preference customers IF they agree to participate with preference customers in the “Backup” system described below. Contracts are limited to the share that a subscriber's contractual load rights on Bonneville as of January, 1995 is of the total regional load on Bonneville.
8.6.3.1.3. “Representatives of IOU domestic and small farm load” could be IOUs or non-utility aggregators that have Northwest residential load or small farm load as certified by state regulators. In the case of IOUs or aggregators, the subscription is limited by the share that the load of the qualifying consumers is of the total load of such qualifying customers in the region.
8.6.3.1.4. “Other regional customers” means IOUs, existing DSIs, and aggregators for other Northwest consumers, with no priority among them. The subscription is limited by the share that the load of the qualifying consumers is of the total load of such qualifying customers in the region.
8.6.3.1.5. Out of region customers.
8.6.3.2. Subscriptions will first be offered to all regional entities in priority order. If still under-subscribed, regional entities would be offered another opportunity to subscribe for additional an additional share, again in priority order.
8.6.3.3. If there is over-subscription, there will be an allocation. The allocation sequence is by priority order (above). For regional entities, the allocation will be pro-rata shares of subscriptions within the priority class on the margin. For non-regional entities serving non-regional loads, bids will be for cost plus some offer.
8.6.4. The firm power subscription
8.6.4.1. Firm power should be subscribed to by month, allowing subscriptions to build up to the desired annual load shape. The subscriber is responsible for deviations from that load shape.
8.6.4.2. The threshold amount of firm power for subscription should be some large fraction, e.g., 95 percent of the firm output of the federal system (the total available from both the federal hydro projects under river operations in place at the time of the subscription plus the capability of the non-hydro projects included in the federal system). This should be estimated as a safe amount given the various possibilities for future changes in output for any reason.
8.6.5. Recall – contracts are not subject to any recall once signed.
8.6.6. Resale – subscribers may resell their contracts for rights to receive dividends and the obligation to pay costs.
8.6.7. Backup System:
8.6.7.1. If the total subscription is insufficient to cover all of the shares, the subscription process is void and a default allocation of net revenues is implemented:
8.6.7.1.1. A federal corporation is formed and a budget board of the assignees created with the same powers as in the subscription system.
8.6.7.1.2. All power is sold on the market for any term that would maximize the revenue.
8.6.7.1.3. Any remaining net cost above market (stranded cost) should be assessed as a meters charge or a directed transmission charge to the preference customers prorated in proportion to contracted load on Bonneville as of January 1995.
8.6.7.1.4. Any net benefits, subject to the benefit sharing for fish described below, should be directly assigned to the same entities, as an annual lump sum rebate.
8.6.7.2. Existing DSIs can be included in the first priority for subscriptions if, and only if, they submit themselves to the backup procedures described above.
8.6.7.3. There should be provision for a voluntary one-time buyout of the net stranded cost obligation.
8.6.7.4. Increased costs resulting from a greater than 15 percent reduction from the annual sum of the firm monthly power capability of the federal hydro projects (under river operations in place at the time of the subscription) due to modification of river operations for fish would not be eligible for stranded cost recovery under the backup system.
8.7. Fish cost risk mitigation – fish cost risk must be defined and predicted and constrained appropriately given the level of benefit under the contracts. The intent is to create a system analogous to FERC regulation of hydropower facilities:
8.7.1. Subscribers accept the risk of increased fish and wildlife program costs and capital costs, except those costs associated with projects that would reduce the annual sum of the hydro system firm monthly capability under river operations in place at the time of the subscription by more than 15 percent.
8.7.2. A reduction of 15 percent in the annual sum of the hydro system firm monthly energy capability under river operations in place at the time of the subscription would give subscribers the option of release from their subscription.
8.7.3. Whenever net revenues are positive, 30 percent of the net revenues will be a dividend for fish and wildlife.
8.8. Low density discount:
8.8.1. Should be replaced by a one-time buyout at the present value over the 10 years after 2001 of the current level of the discount or $100 million, whichever is less.
8.8.2. The buyout should be limited to existing low density discount customers, and individually limited by their distribution and local transmission system debt as of January, 1996.
8.9. Bonneville should not sell directly to new retail loads:
8.9.1. Bonneville may sell to intermediaries subject to state and local jurisdiction.
8.10. There are no changes to any subsidies from power users to non-power users of the system. Any modification of these subsidies would be the responsibility of the Subscriber Budget Board.
Revised 7/29/96
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