Council Home 
Energy
Comprehensive review archive
Documents
Draft Final Report for Steering Committee Review
Comprehensive Review of the
Northwest Energy System
Final Report
Toward a Competitive Electric Power Industry for the 21st Century
Introduction
Why Are We Doing This?
The electricity industry in the United States is in the midst of significant restructuring. This restructuring is the product of many factors, including national policy to promote a competitive electricity generation market and state initiatives in California, New York, New England, Wisconsin and elsewhere to open their retail markets to competition. This transformation is moving the industry away from the regulated monopoly structure of the past 75 years. Today we are served by individual utilities, many of which control everything from the power plant to the delivery of power to our homes or businesses. In the future, we may have a choice among power suppliers that deliver their product over transmission and distribution systems that are operated independently as common carriers.
There is much to be gained in this transition. Electricity consumers are already benefiting from competition in a number of significant ways. Competition in the natural gas industry has helped lower the cost of electricity from gas-fired generating plants. Competition among manufacturers and developers of combustion turbines has contributed to less expensive, more efficient power plants that can be built relatively quickly. Surplus generating capacity on the West Coast combined with increasing competition among wholesale suppliers has reduced the price utilities must pay for power on the open market. Broad competition in the electricity industry that extends to the all consumers could result in lower prices and more choices about the sources, variety and quality of their electrical service.
But, there are also risks inherent in the transition to more competitive electricity services. Merely declaring that a market should become competitive will not necessarily achieve the full benefits of competition or ensure that they will be broadly shared. It is entirely possible to have deregulation without true competition. Similarly, the reliability of our power supply could be compromised if care is not taken to ensure that competitive pressures do not override the incentives for reliable operation. How competition is structured is important.
It is also important to recognize the limitations of competition. Competitive markets are about economic efficiency, not fairness or other social or environmental goals such as providing low-cost electricity to rural areas, conservation and renewable resources, and fish and wildlife recovery. To the extent that the citizens of the Northwest want their electricity system to deliver these social and environmental benefits, special attention will be required to accomplish these goals during and after the industry’s transition.
In some respects, the transition to a competitive electricity industry is more complicated in the Northwest because of the presence of the federal Bonneville Power Administration. Bonneville is a major factor in the region’s power industry, supplying, on average, 40 percent of the power sold in the region and controlling more than half the region’s high-voltage transmission. Bonneville benefits from the fact that it markets most of the region’s low-cost hydroelectric power. It is hampered by the fact that it has high fixed costs, including the cost of past investments in nuclear power, and the majority of the costs for salmon recovery. As a wholesale power supplier, Bonneville is already fully exposed to competition and is struggling to keep its costs close to the market. The transition to a competitive electricity industry raises many issues for the Bonneville Power Administration and the region. In the near term, how can Bonneville continue to meet its financial and environmental obligations in the face of intense competitive pressure? In the longer term, when market prices rise and some of Bonneville’s debt obligations have been retired, how can the Northwest retain the economic benefits of its low-cost hydroelectric power when the rest of the country is facing market prices? And finally, what is the appropriate role of a federal agency in a competitive market? The question is not only whether Bonneville can compete in the near term but also, should it be a competitor?
Without Regional Consensus...?
The federal power system in the Pacific Northwest has conferred significant benefits on the region for 50 years. The availability of inexpensive power at cost has supported strong economic growth and helped provide for other uses of the Columbia River such as irrigation, flood control and navigation. The renewable and non-polluting hydropower system has helped maintain a high quality environment in the region.
While the power system has produced significant benefits, these benefits came at a substantial cost to the fish and wildlife resources of the basin. Salmon and steelhead populations have been reduced to historic lows and many runs are or are about to be listed under the Endangered Species Act. Resident fish and wildlife populations have also been impacted. Native Americans and fishery-dependent communities, businesses and recreationists have suffered substantial losses due in significant part to construction and operation of the hydroelectric generation and transmission system. The region’s ability to sustain its core industries, support conservation and renewable resources, and restore salmon runs is clearly threatened if we cannot reach a consensus regional position to bring to the national electricity restructuring debate. Without a sustainable and financially healthy power system, fish and wildlife restoration funding and activities could be jeopardized.
The governors’ charge to the comprehensive review and the steering committee’s deliberations recognized that the electricity industry is changing whether we like it or not. The comprehensive review is not an initiation of change, but a response to change. It is an effort to shape that change, to the extent shaping is possible, to ensure that the potential benefits of competition are achieved and equitably shared, environmental goals are met, and the benefits of the hydroelectric system are preserved for the Northwest. The region’s ability to shape the change in the Northwest electricity industry depends on its ability to develop a regional consensus. If the comprehensive review process fails to result in a consensus for regional action, the electricity industry will restructure regardless. A return to the historical industry structure is not an option. Many of the comments received during the public hearing process made it clear that this is not a widely appreciated fact. This section suggests the likely evolution of the regional electricity market in the absence of effective regional consensus.
For the wholesale power markets, federal policy is already in place. The Energy Policy Act of 1992 and FERC Order 888 express a strong commitment to a competitive wholesale power market. Transmission will remain a FERC regulated activity and will be strictly separated from generation to ensure that transmission owners cannot interfere in the efficient operation of the wholesale power market. In the region, utilities are already in the process of forming an independent transmission grid operator (INDEGO). The purposes of the independent transmission grid operator are to ensure adequate separation of generation and transmission and to align incentives to ensure efficient and reliable operation of transmission. Bonneville is participating in the INDEGO discussions and has already administratively separated its transmission activities from its energy marketing. This activity will continue regardless of the comprehensive review.
Given the strong federal policy commitment to a competitive wholesale power market and an intensifying need for federal revenues, it is likely that without strong regional support for a different outcome, Bonneville’s power would be eventually sold at market prices. Further, the incongruity of a federal agency as a full participant in a competitive market could result in limitations on Bonneville’s market presence. This could be done in many different ways, including auctioning the power, requiring Bonneville to market its power at prices that are tied to a market index, or limiting Bonneville’s marketing of products and services. However it is done, any cost-based regional benefits that are derived from public or regional preference are likely to be reduced.
Current electricity policy at the federal level reserves retail market competition decisions to the states. However, recent Congressional initiatives leave the degree of future state control in question. In any case, the pressure for retail access and its momentum are not in question. In the absence of either fairly strong federal legislation or coordinated regional policy, individual states are likely to move at different rates toward various forms of retail access policy with large power consumers tending to get first access. Unless adequate safeguards are in place to ensure that the owners of monopoly distribution systems cannot unfairly influence consumers’ retail energy service choices, the development of competitive retail energy service markets for all consumers will be inhibited. Inconsistent policies among states within an integrated electricity market will lead to market advantages for some areas, a less efficient market, and arbitrage opportunities for electricity traders and marketers.
Integrated utilities under competitive pressure to retain their customers will find it difficult to support the various social and environmental goals that they have supported in the past. Competitive markets will support some social and environmental activity, and recent legislative proposals in Congress suggest that some programs could be mandated at the national level. However, absent action to place the funding of such activities with the separate and regulated elements of the market (transmission or distribution), emphasis on conservation, renewable energy sources, and low-income support will decline. The greater the differences among states and utilities in the funding of these activities, the more distorted and less efficient will be the electricity markets.
THE COMPREHENSIVE REVIEW
To seize the opportunities and moderate the risks inherent in the transition to competitive electricity markets, the governors of Idaho, Montana, Oregon and Washington convened a "Comprehensive Review of the Northwest Energy System." The governors appointed a 20-member steering committee that is broadly representative of the various stakeholders in the power system to study that system and make recommendations about its transformation. The members of the steering committee are listed in Appendix A. Each governor has a representative on the steering committee to make certain the public is educated about and involved in the Comprehensive Review. In establishing the review, the governors stated:
"The goal of this review is to develop, through a public process, recommendations for changes in the institutional structure of the region’s electric utility industry. These changes should be designed to protect the region’s natural resources and distribute equitably the costs and benefits of a more competitive marketplace, while at the same time assuring the region of an adequate, efficient, economical and reliable power system."
Since January 1996, the steering committee has
held 292 days of meetings. In addition, almost 400 people have
been involved in more than 100 meetings of various work groups
reporting to the steering committee. Hundreds of citizens
attended the ten public hearings that were held throughout the
region on the Committee’s draft report. Over a thousand
written comments were received. This draft
report is the initial product of that work. It
is a proposal for restructuring the Northwest electricity
industry to meet the challenges and seize the opportunities
inherent in the competitive transition.
The Steering Committee members are
issuing this draft report to solicit and stimulate public comment.
All proposals are preliminary. There is not consensus on the
Steering Committee on many aspects of this report. Neither the
Steering Committee nor the governors have endorsed this report or
any of its parts in advance of hearing and fully considering the
views of the region’s citizens. Your comments on this draft
report will help frame a final report to the governors to be delivered
in December of this year. That, in turn, will be the basis for
recommendations from the governors to the Northwest Congressional
delegation and the state legislatures as appropriate.
The Steering Committee’s goals for federal power marketing are to 1) align the benefits and risks of access to existing federal power; 2) ensure repayment of the debt to the U.S. Treasury with a greater probability than currently exists while not compromising the security or tax-exempt status of Bonneville’s third-party debt; and 3) retain the long-term benefits of the system for the region. The proposal is also intended to be consistent with emerging competitive markets and regional transmission solutions.
The Bonneville Power Administration is a federal power marketing agency charged with marketing the power output of the federal dams on the Columbia and its tributaries. It is a wholesale supplier, marketing power to utilities that, in turn, sell power to retail consumers. The only exceptions are the DSIs which historically have been served directly by Bonneville. On average, Bonneville markets about 40 percent of the firm power in the Northwest and substantial, but varying, amounts of nonfirm power. Bonneville is required to sell its firm power (the power that can be counted upon even under poor water conditions) at cost under contracts to public agency customers (e.g., municipal utilities, public utility districts, cooperatives) and DSIs. Only when it cannot sell all its power within the region is it allowed to market outside the region. As a result of the Northwest Power Act of 1980, Bonneville also has the responsibility of acquiring new resources to meet the loads of those customers who choose to place their growing load requirements on Bonneville.
Historically, Bonneville has been a low cost supplier of electricity. In recent years, however, Bonneville’s power has lost its price advantage. This has been the result of a combination of factors including low natural gas prices, surplus generating capacity on the West Coast; the opening of the competitive wholesale electricity market and the resulting decline in electricity prices. Bonneville has also experienced increased costs resulting from requirements for salmon recovery, resource acquisition costs and other factors. Bonneville’s ability to reduce costs is hampered by the fact that a large part of its costs are fixed. These fixed costs include repayment of debt to the U.S. Treasury for the construction of the hydroelectric and transmission systems and repayment of the debt for three Washington Public Power Supply System nuclear power plants.
The opening of wholesale electric competition has put great stress on Bonneville. Bonneville’s utility and DSI customers now have a greater degree of choice under amended or new power sales contracts, and current power sales contracts will expire in 2001. Bonneville has been struggling to determine its future competitive role and to secure sufficient sales to cover its costs and make its payments to the Treasury and the Supply System. The ultimate risk, should Bonneville be unable to cover its costs, lies with the Treasury. While this is occurring, many of Bonneville’s traditional customers, particularly those without generating resources, continue to look to the agency as their primary or exclusive power supplier.
In the future, however, conditions are likely to change. Many industry observers expect that gas prices and the market price of electricity will eventually rise. In addition, Bonneville’s fixed costs can be expected to fall as debt is paid off. When this happens, the price of Bonneville’s power would be very attractive. Whether the Northwest will be able to retain these future benefits has been brought into question, in part due to legislation that would sell federal power marketing agencies. Even if Bonneville is not privatized, the revenues that a low-cost power producer could generate could be very attractive to future Congresses, particularly if the Treasury has been called upon to bear the risks of that power producer when conditions are not so favorable. In this context, a long-term solution that retains the benefits of the system in the Northwest would be highly desirable.
Finally, there is the question of the appropriate role of a federal agency in a competitive market. Right now, Bonneville is struggling to compete. In the longer term, as restructuring proceeds and the electricity industry becomes more and more competitive, the question may no longer be "can Bonneville compete?" but "should Bonneville compete?"
The proposal is to institute a subscription-based system for marketing the power produced by the federal system. The subscription process would maintain the principles of public and regional preference to the output of the Bonneville system at cost. The proposal is designed to facilitate a fully competitive bulk power market and freedom of action by customers. Simultaneously it is intended to better balance risk and rewards between customers, BPA and the US Treasury. The subscription system is central to aligning the risks and benefits of the federal power system, and to reducing the risk faced by the Treasury. Treasury currently faces the risk of market prices below cost, but does not receive the benefit when market prices are above costs.
Subscribers would contract to purchase power
from the system at cost, take or pay, for the period of their
subscriptions, including periods similar to what we are now
experiencing when costs are above market prices. Subscribers
would also be able to purchase at cost when costs are below market
levels. The power product contracted for could vary depending on
the requirements of the customer. One product could be
provided for customers with predictable loads, or ones that acquire
load shaping services from another entity. Alternatively,
Bonneville would offer a take-and-pay arrangement for customers
that want to rely upon Bonneville to serve their actual monthly
loads. The latter service would cost more in order to cover the
revenue uncertainty that Bonneville would face as a consequence.
| The deleted section in the previous paragraph was moved to "Disposition of Federal Power". |
Bonneville would not acquire additional resources to serve load growth except on a bilateral contract basis, where the customer absorbs the risk. However Bonneville could offer short-term products and services that are responsive to variations in loads from planning estimates to those customers willing to pay for such services. Moreover, if the system is fully subscribed, there would be no need for Bonneville to market to retail loads.
No remedy is possible unless Bonneville can
effectively manage and control its costs. In this proposal, Ssubscribers
would gain advisory influence over power-related costs and would
have the ability to call for binding arbitration on certain cost
issues under their contracts.
While the Committee was unable to agree on a specific stranded cost mechanism, it did agree that FERC should have an enhanced role in making this determination and that any stranded cost mechanism should be maximally consistent with Order 888. Several provisions of the subscription process are specifically intended to provide benefits to the Treasury and preclude the need for stranded cost mechanisms.
The Committee recommended an implementation board appointed by the governors, to oversee the subscription board and report to the governors on its prospects for success, among other potential tasks.
The proposal emphasizes long-term
contracts. To make such contracts salable, customer responsibility
for any additional fish related costs above existing levels would
be specified on a shared basis up to a ceiling. In turn, when
Bonneville costs are below market, a portion of the difference
between market and cost is returned to the U.S. Treasury.
Long-term subscriptions provide stability to
Bonneville, the Treasury and customers. However, a number of
customers, particularly those without generating resources, may
want to contract for much of their load in shorter-term intervals
as they make the adjustment to new competitive markets. For
purposes of this proposal, long term is considered to be 30
years, similar to a license for a generation project. Short term
is considered to be 5 years. The firm energy capability of the federal
system subject to some form of allocation is about 8,000 average
megawatts. For overall stability, a minimum of 5,000 average
megawatts needs to be longer-term contracts, representing more
than 60 percent of the entire system.
The core or basic product of federal power marketing is energy from the federal system. Depending upon limitations of availability, contracts for this product should be available to regional customers at cost. Customers may then purchase other services that are individually priced by BPA to change this energy into a product that meets their needs, or alternatively they may provide it themselves. In addition, customers may be willing to purchase the energy for differing periods of time or with different obligations placed on BPA. This impacts the degree of risk Treasury is absorbing, and in turn should be reflected in price the customer is required to pay.
One product could be provided for customers with predictable loads, or ones that acquire load shaping services from another entity. Alternatively, Bonneville would offer a take-and-pay arrangement for customers that want to rely upon Bonneville to serve their actual monthly loads. The latter service would cost more in order to cover the revenue uncertainty that Bonneville would face as a consequence.
| The preceding paragraph was moved from the "Summary" in the Draft |
Long-term subscribers get the right to purchase power at cost for the term of the contract, up to 3020 years. While the cost of the power from the federal system is currently somewhat above market prices, the cost is generally expected to be below market prices in the future. For potential subscribers to make a long-term commitment to Bonneville, particularly at a time when the agency’s rates are above market, Bonneville needs to take actions that push the envelope of cost reductions. In addition to the agency’s own initiatives in reducing costs, long-term contracts need to be structured in a manner that is very explicit regarding the limitations on the customer’s obligation to pay.
Short-term subscribers also get the right to
purchase power at cost, paying the same general costs as the
long-term customers. For at least the short term following
2001, renewable contracts of shorter duration place an element of
potential risk on the Treasury, associated with customers leaving
if BPA costs became significantly higher than market.However Because
of this, the short-term subscribers are required to pay an
option or subscription fee if they want to reserve the right to
re-subscribe at cost after the contract expires. The option fee
would enable the customer to either extend their cost-based
contract, or to reduce or terminate loads on Bonneville at the
end of the existing contract commitment. The option fee is a
premium payment reflecting the risk to the system and to the
Treasury of shorter-term contractssome degree
of customer instability.
The option fee should be priced to reflect its
value, while at the same time not making it economically and
competitively prohibitive. Using a range of market conditions
and assumptions regarding Bonneville costs, BPA and the Power
Planning Council staff have identified a sliding scale option fee
ranging from 0 mills/kWh for longer term 15 to 20 year contracts
to 2 mills/kWh for 5 year contracts. BPA should prospectively
develop competitively priced tools that balance risks and rewards
between shorter term and longer term load commitments and that
reflect the overriding purpose of compensating the Treasury for
the risk associated with shorter term contracts. An
option fee of 1 mill per kilowatt-hour or slightly more (about 5
percent of the projected power cost) has been proposed.
Short-term subscribers could continue to purchase short-term in
the future by purchasing subsequent option fees, or they could
convert to long-term power for the balance of the
long-term contracts period
without subsequent option fees.
The subscribers assume a greater level of risk than in the current system. For example, if we were to experience lower than expected market prices that are below Bonneville costs for an extended period of time, the long-term subscribers would still be obligated to pay Bonneville’s costs. Short-term subscribers would be able, at the end of their subscription period, to let their subscriptions lapse, but may elect to stay, hoping to realize the longer-term savings associated with the system. There would be a higher level of annual probability of Treasury payments, placing more risk on the subscribers from the effects of year-to-year variations in weather, future power system cost increases (e.g., the cost of generator rewinds and other necessary maintenance and upgrades) and changes in market conditions.
The process for the disposition of federal power should be completed by 2001, so that the results can be in place when Bonneville’s existing contracts expire. The term of the contracts would be determined by the individual subscribers, during their initial subscriptions for firm power. Although 20 years would provide maximum contract certainty for BPA under current law, it is in the Agency's best interest not to have all contracts expire at the same time, as is the case in 2001. Firm power would be subscribed for by month with appropriate ancillary delivery services. Any remaining firm power and other products should be sold FERC regulated prices or at competitive prices, where FERC determines that competitive markets exist, and the revenue used to reduce costs to the subscribers.
At the end of the contracts, long-term
purchasers and those who have continuously renewed their short-term
contracts would have the first right of refusal to renew
contracts for subsequent terms. The initial subscription, and any
subsequent ones, would follow a specific priority order. Any power
that is freed up as a result of non-renewal of contracts would be
offered at cost through the same priority structure to
all long-term subscribers within the priority structure
described below. Subscribers who have let their
subscriptions lapse would not be guaranteed the ability to buy at cost
in the future.
Priority for Subscriptions
The priority order for subscriptions would be
implemented in a sequential multiphase process. Customers could
elect to split their subscriptions between long- and short-term
contracts subject to constraints. The phases are
structured so that publicly owned utilities get first priority,
DSIs and representatives of residential and small farm customers
of IOUs get second priority, other regional customers such as
representatives of IOU commercial and industrial customers get third next priority
and non-regional customers get last priority. Within this overall
framework, there is an emphasis on long-term subscriptions, so
that, to the extent there is a conflict due to over-subscription
within a phase, subscription term would be the tie-breaker.
Customers should have broad rights, except as specified or
constrained elsewhere in this document, to extend, renew or
convert their contracts to longer terms, up to 20 years, at any
time during the contract life, independent of the length of the
existing contract.In the early phases, subscriptions
are limited to loads placed on Bonneville, while in later phases,
subscriptions are expanded to total regional loads, even if
currently met by other resources (which could then be resold,
even if the subscriptions cannot be) and, in the last phase, if
power is still available, subscriptions are completely unlimited.
| Broad "evergreen" rights inserted above. |
Phase 1
In the first phase, loads of regional public
utilities and cooperatives would subscribe with no limitations on
the term, within the current 20-year maximum. The first phase
would be reserved for publicly owned utilities to subscribe up to the
average of the contractual entitlements of the highest two
consecutive years of the 1997-2001 contract period plus some
provision for minor load growth. The public utilities
would be split into two groups based on their end-use loads, regardless of
supply source: 1) utilities with loads 50 average megawatts and over
and 2) utilities under 50 average megawatts. Each group would
subscribe first for long-term contracts and then for short-term
contracts, with no priority between the two groups of utilities.
For the over-50 average megawatts group, the long-term
subscriptions would have to be at least 60 percent of the total subscribed
load being placed on Bonneville by this group (not the
subscribers’ total load) and for the under-50 average
megawatts group the long-term subscriptions would have to be at
least 40 percent of the total subscription.
| Provision for "minor load growth" inserted above, conflicts with limit on the amount that could be subscribed in existing language and may conflict with provision for no resale except for customer load loss. |
These thresholds apply to each group as
a whole. As long as the group meets the subscription target,
individual utilities within the group do not need to. However,
the two groups (over- and under-50 average megawatts) are treated separately.
If a group do not meet its collective target, the individual utilities within
the group that do not meet the targets must adjust their subscriptions, either
by switching short-term to long-term, or by reducing their short-term subscriptions
until the group meets its target.
When this first subscription has been
accomplished, all the public utilities have the opportunity to subscribe
again, before going to other classes of customers. The utilities
must start from their previous final positions, with the same
rules for proportions of long- and short-term subscriptions applying
to the final set of subscriptions. The same load limits and
process for adjusting excess short-term subscriptions also
applies.
Phase 2
During the second phase, the DSIs and the
residential and small farm customers of the IOUs (through their
representatives, described below) would be allowed to subscribe with
no limitations on term, within the current 20-year maximum. The
DSI subscriptions would be limited by the average of the contractual entitlements
of the highest two consecutive years of the 1997-2001 contract period.
The IOU customer subscriptions would be limited by the average
total regional load of their residential and small farm
customers, again, in the two highest consecutive years between
1997 and 2001. If there is over-subscription, subscription
term will serve as the tie breaker, with the longer term having priority.There
would be no priority between these two groups. The process would
be the same as for the two groups of public utilities described
in Phase 1. Each group would subscribe first for long-term and
then for short-term subscriptions. For both groups, 60 percent of
the subscribed load must be long-term.
Individual subscriptions need not meet
the threshold requirement as long as each group’s total meets
the threshold. If either of the collective subscriptions (DSIs as
a group, IOU customers as a group) did not meet the threshold,
the non-conforming customers in the group would have to adjust,
by switching short-term to long-term, or by reducing the amount
of short-term, until the group proportion met the threshold. If
more firm power was subscribed to than was available for subscription
in Phase 2, subscriptions would be reduced, pro rata on the basis
of loads, within Phase 2.
For the purposes of the subscriptions, IOU residential and small farm customers could be represented by IOUs or other entities that serve Northwest residential or small farm loads, as certified by state regulators. The benefits of purchases for these customers would have to be passed through to the end users.
Phase 3
The third phase would be for other regional
wholesale and DSI load. Phase 3 is for long-term subscriptions
only. Each subscription is limited by the subscriber’s total
regional load. To the extent there is over-subscription in
this phase the longer-term subscription will have priority.Subscriptions are
made available, first to publicly owned utilities (including new
ones), second to DSIs, and third to IOUs and other regional
wholesale suppliers for regional loads. Pro rata allocations on
the basis of the desired subscription amount would be applied at each
step if necessary.
Phase 4
Phase 4 is for short-term subscriptions
only. Each subscription is limited by the subscriber’s total regional
load. Subscriptions are made available first to publicly owned
utilities (including new ones), second to DSIs, and third to IOUs
and other regional wholesale suppliers for regional loads. Pro rata allocations
on the basis of the desired subscription amount would be applied
at each step if necessary.
Phase 4
5
In the fourth phase, Bonneville could sell
to regional wholesale and DSI loads at market prices for those
who wish to buy only at market prices in the future. In addition
Bonneville could sell "excess" federal power for
periods up to 7 years to out-of-region customers.
"Excess" is a defined term in recent legislation. Power sold
in this phase would be sold subject to current law.The fifth
phase of subscriptions is for non-regional entities and
non-regional loads. It does not have any limits on subscriptions
and allows either long- or short-term subscriptions. Public
preference would apply outside the region, and pro rata
allocation would apply, first among public utilities, if
necessary, and then among all other subscribers, if necessary.
The power would be priced at cost.
Subsequent Subscriptions
To the extent firm power becomes available as a
result of non-renewal of contracts, the remaining power will be
offered for long-term subscription through the
same multiphase process described above. Customers who elect not
to subscribe to Bonneville, or who subsequently allow short-term subscriptions
to lapse would be served at market prices not be
guaranteed the right to new subscriptions or to purchase at cost
in the future. Contracts would not be subject to recall, for preference
or other reasons, once signed.Contracts subject to
recall for public preference under current law would be subject
to recall only for loads of new public utilities and after a
waiting period of five years from formation of the utility.
Resale of Power
Subscribers may resell the power for which they
have subscribed in cases of loss of load. The Steering
Committee seeks comment on whether resale of power should be
allowed under other circumstances as long as the dollar benefit
(i.e., the difference between the sale price and the cost) of the
resale stays in the region. Power purchased on behalf
of residential and small farm customers of investor owned
utilities may be resold by them or their representatives under arrangements
that direct the monetary benefits to such customers. The resale transactions
shall be subject to conditions imposed by state public utility commissions,
including, but not limited to, allocating all of the monetized
benefit to the distribution system serving such residential and
small farm customers or directly to such customers.
Resale of Options
The Steering Committee did not reach consensus on whether options should be resalable and specifically seeks comment on this question.
| No decision was made by the Steering Committee on resale of options. |
Issues Regarding Resale
There are several pros and cons that
apply to both resale of power and to resale of options. Arguments
against resale are the following:
·Resale weakens the argument that we are retaining benefits in the region.
·Resale could be seen as selling preference rights (this argument only applies to sales by preference customers).
Arguments in favor of resale are the
following :
·Greater benefits are likely to be generated through flexible remarketing to the widest possible market. These financial benefits will remain with the region.
·Resale does not interfere (by adding inflexible requirements to use power) with creation of retail access for all customers, including those of preference customers.
·Resale allows a simple mechanism for passing through benefits to IOU residential and small farm customers without requiring IOUs to buy unneeded power (they would simply pass through the proceeds from resale of the power or the option).
The Exchange
As a result of the Northwest Power Act of 1980, Northwest utilities have the right to sell to Bonneville an amount of power equal to that required to serve their residential and small farm customers at the utilities’ average system costs and receive an equal amount of power at Bonneville’s average system cost. In reality, this is an accounting transaction. No power is actually delivered. This was intended to be a mechanism to share the benefits of the low-cost federal hydropower system with the residential and small farm customers of the region’s investor-owned utilities. As a result of decisions made by Bonneville in its most recent rate case, those benefits have been reduced. The Steering Committee acknowledges that the residential and small farm consumers of exchanging investor-owned utilities will be adversely affected by the reduction of exchange benefits. Congress intervened for one year to stabilize the exchange benefits. However, on October 1, 1997, there will be rate increases to the residential and small farm customers of the exchanging utilities. The Steering Committee encourages the parties to continue settlement discussions and to explore other paths to ensuring that residential and small farm loads receive an equitable share of the benefits of the federal base system.
Treatment of Fish Recovery Cost Risk
to SubscribersFish and Wildlife
The committee recognizes that fish and wildlife restoration and mitigation obligations exist and expressly intends that none of its recommendations should be implemented in a way that alters, amends, diminishes or repeals the trust obligations of the federal government, the treaty and other rights of the tribes, including those rights associated with tribal hunting and fishing, water and other natural resources.
| Two paragraphs from the fish language adopted Nov. 21-22 were moved to the "Columbia River System Governance" section at the end. |
The Committee recognizes that the cost of additional fish and wildlife restoration investments beyond those currently contemplated in the fish and wildlife Memorandum of Agreement is unknown. Additional costs could be incurred particularly if the measures are undertaken to restore riverine conditions in some segments of the Columbia River Basin. The committee believes that the region will need to provide the bulk of those fish and wildlife restoration funds. At the same time, the committee emphasizes the importance of an energy industry restructuring package that shares the future benefits of the power system among the parties in the region. The committee believes that the federal government should provide additional assistance and share the costs in the restoration effort, particularly given the provisions of the US/Canada Pacific Salmon Treaty, the Endangered Species Act and the fact that federal land and water management practices have had an adverse effect on fish and wildlife populations that are being protected and restored with regional ratepayer funds.
The committee further recommends that flexible but detailed multi-year fish and wildlife budgets are essential to the accountability and fiscal management of the restoration effort and should be developed in government-to-government consultations by the federal, state and tribal sovereign governments on a rolling five-year basis. Budgets of this kind will help discipline the restoration efforts and will help provide relative certainty for the power system and fish and wildlife managers.
This proposal assumes that sufficient information will be available before 2001 to prepare a five year fish recovery budget, and that the input from this process could be incorporated into BPA rate projections. This should provide shorter term customer certainty regarding fish costs, and the opportunity for five year rates, as BPA is currently offering through 2001.
In order for Bonneville to effectively
market long-term contractual commitments to customers who are
required to pay all costs as specified in their power sales contracts,
there need to be parameters established in advance on the degree
of financial risk to subscribers for potential additional fish
recovery measures. This is particularly true if the measures
imposed are beyond the control of the subscribers. However,
establishing a maximum level of funding for fish measures may be
politically or legally unacceptable and could be an impediment to recovery.
Customer responsibility for fish and
wildlife costs is limited through 2001 by a "fish cap"
in the inter-agency Memorandum of Agreement on Bonneville’s
fish and wildlife budget. The Steering Committee is not proposing
any changes in fish and wildlife measures or funding. These
matters will be addressed in other forums.But in the context of a
new Bonneville role and new power contracts, there should be
consideration given to a new contingency funding mechanism to share
additional fish and wildlife costs that might be imposed.
This proposal is built upon the premise
that the costs of any additional measures, beyond the National
Marine Fisheries Fisheries Service 1996 Biological Opinion and
and the Council’s fish and wildlife program, that could be
financial obligations on Bonneville beyond the current fish cap should
be shared between the subscribers and the U.S. Treasury. Many
alternative approaches are available for cost sharing. It could
be dollar for dollar or it could be a sliding scale where
customers pay a higher percentage of the initial measures and a declining
percentage to a capped figure at a lower percentage. For ease of understanding,
it is proposed that customer expenditures above the existing fish cap
be shared on a 50-50 basis with Treasury up to the limit of the
customers’ responsibility.
The limit or cap on the customers'
responsibility would be approximately $225 to $250 million per year
above the existing fish cap (in today’s dollars). If reached,
this cap would reflect substantial additional costs that could be imposed,
if justified, above the costs of current measures. The cap would
be reached if total fish recovery costs (customer and Treasury
shares combined) increased by $450 to $500 million above the cost
of current measures. Further fish recovery costs above this amount
would be the responsibility of the U.S. Treasury. It is assumed
that any contributions by Treasury will come in the form of
appropriations or forgiveness of other Bonneville obligations. In summary, Treasury
would agree that in each year of the contract they would pay 50 percent
of additional fish recovery measures, and the full amount above an agreed-upon
ceiling.
The following figure illustrates this
sharing for five different examples of total fish recovery cost, starting
with a case where there are no added fish recovery costs beyond
the existing level of the fish cap, moving through a 50/50
sharing with the Treasury as additional costs are incurred, and ending
with an example where the Treasury’s share continues to
increase while the subscribers’ share is limited by the new
cap in the proposal.
| Chart Deleted |
To the extent that, over the
30-year period, there are major changes in the size of the
generation revenue requirement, or increases in market prices compared to
Bonneville costs due to the effects of inflation, the issue of
the cap may have to be periodically revisited, as long as the
rules of doing so are known in advance and spelled out in the
contracts.
Ownership Benefits for Treasury
Currently the overall "risk taker" regarding BPA's responsibility to meet financial targets is the US Treasury, as the recipient of anticipated annual payments from BPA. To the extent that BPA secures revenues to cover all costs including Treasury payments, there is no actual or incurred liability to Treasury. However, in the event that BPA's revenues are not sufficient to cover its costs, including Treasury obligations, the shortfall would be handled as a deferral, or roll forward into the future, of any difference between the Treasury obligation and the actual payment.
It is financially unstable and politically undesirable to anticipate a Federal power marketing agency operating in an environment in which the Treasury faces either excessive financial risk, and/or a probability that there will be a deferral of obligations on a recurring basis.
During the last 13 years BPA has not deferred a Treasury payment. Also, with newly adopted rates BPA is not projecting a deferral for the five year period through 2001. However, the amount of money involved is significant, which in turn makes the risk to the Federal government significant. Between 2002 and 2006 BPA is scheduled to make in total $2.063 billion in Treasury payments, with a net present value of $1.661 billion. Over a 25 year period these amounts are $11.848 billion with a net present value of $5.029 billion.
BPA faces a 2001 environment in which customer contracts expire, markets may be lower than Agency costs, and there is uncertainty regarding fish mitigation measures. In the longer term, market conditions should change to BPA's favor, but not necessarily by 2001. A solution needs to be found that both improves Treasury's position from the status quo, and over time offers an incentive to the Federal Government to continue operating BPA. Four actions are recommended to address this situation.
1. As referenced in other sections, BPA needs to pursue all actions possible in the short term to cut costs, thereby giving the agency the best opportunity to either meet or come close to the competitive market with cost based products, thereby retaining a strong customer base. .
2. To the extent that there is a deferral of any portion of the Treasury payment in any year, this should become an immediate repayment obligation when BPA's costs fall below market. When BPA has an opportunity to adjust rates and there is a projected positive difference in BPA's favor between market and cost, the next set of rates would remain at market for a sufficient period to fully recover any obligations that had been deferred from the previous period. As noted in the section on "Disposition of Federal Power - Priority for Subscription", returning customers may have an obligation to repay existing customers who collectively paid all the deferrals that were due before returning customers decided to return.
3. As described in the section on "Disposition of Federal Power", shorter term subscriptions will pay an option fee or other higher price that would prospectively reimburse the Treasury for losses or deferrals due to the short term of their subscriptions. This revenue would be used by Treasury to accelerate repayment of Bonneville’s debt.
4. When BPA's cost based rates are below market, customers would agree that subsequent rates would contain an additional share, for example, 20 percent, of the difference between an indexed market rate and cost based rates. This share would be paid to Treasury as a "repayment acceleration payment" as a supplement to each annual obligation. The customers still benefit to the extent that these funds are being applied against BPA Treasury payments, which will reduce their future costs over time. The US Treasury benefits in that it is receiving cash that is otherwise not due until a future date. This provision would apply to the extent that market prices exceed cost-based rates where the costs include any repayment of past deferrals due to the previous provisions.
| Does the Steering Committee want a specific number (e.g., 20 percent) in or not? |
Since the Treasury has the potential in
this proposal of taking on additional risk associated with fish recovery
costs, there needs to be an incentive for its participation.
Because Bonneville's rates are currently above market, there may be
few financial incentives immediately available. However, there is
a high likelihood that Bonneville's costs will fall below market,
and that major savings will be available with the retirement of
Bonneville's third-party debt, making the second half of a 30-year
period look extremely attractive. In years where Bonneville's
cost-based rates are below market, it is proposed that 20 percent of
the difference between cost and market be returned to the
Treasury as a supplemental payment, beyond all other Bonneville
obligations. In essence, customers would be agreeing in their
contracts that Bonneville could recover through rates an additional
20 percent of the difference between an indexed market rate and a
cost-based rate (when lower).
Treasury also has another element of
risk. To the extent short-term customers decide not to renew contracts,
due to fish costs or other reasons, while Bonneville's costs are
above market there is an opportunity for some shortfall in revenue.
This shortfall is the difference between Bonneville's costs and
the revenues they would receive from selling this abandoned power
in the open market. This risk is in part contained based upon the
assumption that at least 60 percent of the system will be allocated
to long-term subscribers. To the extent there is a shortfall
associated with non-renewal of contracts, any such accumulated
shortfall should be repaid to the Treasury. The mechanism to make this
repayment would be the rates charged to the eventual subscribers who
sign up for the abandoned power.
Stranded Cost
The Committee believes that the recommendations in this report, prudently implemented, should dramatically reduce any risk that Bonneville would need to seek stranded cost recovery. Nevertheless, Bonneville, like other Northwest utilities, faces the prospect of load loss due to increased competition associated with greater customer choice at the wholesale and retail levels. It is this Committee’s expectation that Bonneville will do all that it can to first manage costs and take other appropriate actions prior to implementing a stranded cost charge.
While the Committee was unable to agree to a specific stranded cost mechanism, it did agree that FERC should have an enhanced role in making this determination and that any stranded cost mechanism should be maximally consistent with the principles of FERC Order 888.
Customer Advisory Committee
Customers, particularly those signing up for long-term commitments, need to have an effective mechanism to assure them that Bonneville's revenues and costs over time reflect the intent of their power sales contracts. Existing federal legislation allows for appointments of advisory committees to assist agencies such as Bonneville, without exercising formal governance responsibilities. The Bonneville administrator would still technically report to the Department of Energy, but would receive strong customer input through an advisory committee. The committee would consist mainly of subscribers, but also would include representatives of other interests. The committee would have oversight of the budget requests, of overall capital budgeting levels and operating cost levels, rate setting, key marketing issues, and input into the power-related capital and operating cost decisions of the Corps of Engineers and the Bureau of Reclamation. The committee would provide input to decision-making authorities on fish-related matters. However, it is assumed that final determinations regarding fish measures are within the purview of the existing or future mechanisms for river governance.
Although the advisory committee should be helpful in establishing policy direction for the power operations of Bonneville, it is not the primary or exclusive mechanism for subscribers to determine their business relationship with Bonneville. New power sales contracts will define the nature of the business relationship between Bonneville and individual customers. These contracts will have common features and unique characteristics depending upon the types of services the customer is buying from Bonneville. It is proposed that the contracts contain an ability for subscribers to call for binding arbitration on specific power cost-related items.
Bonneville in the Competitive Market
BPA should plan to achieve sufficient net revenue from unsubscribed products to meet Treasury payments and maintain cost-based rates to subscribers. Speculative risk to Treasury and subscribers should be minimized. To the extent consistent with its obligation to repay Treasury, BPA should return to its historic role of marketing power generated by the FCRPS, rather than becoming an aggressive marketer of products and services in the emerging competitive power market. Unbundled products should be sold at market where competitive markets exist. A quantitative plan for marketing should be presented to an implementation board reporting to the Governors.
The proposal would have the effect of disposing of much if not all of the firm power available from Bonneville on a long- or intermediate-term basis. The fact that most of Bonneville’s power would be subscribed at cost would limit Bonneville’s market role. Any remaining firm power and other power products would be sold at FERC-regulated prices or at competitive prices, where FERC determines that competitive markets exist. This approach is intended to provide means for Bonneville to meet its financial obligations, but Bonneville’s role in competitive markets must be further defined to respond to concerns about a governmental entity as a participant in these markets.
In addition, Bonneville would not acquire resources to serve load growth of its customers except on a direct bilateral basis, where the customer takes on all the risk of the acquisition. However, Bonneville would be making spot market power purchases sufficient to both 1) supplement monthly firm hydro energy in meeting current firm loads, and 2) store water for flow augmentation to help rebuild fish populations. The proposal distinguishes these purchases, which are not necessarily required to be on a bilateral contract basis, from purchases to meet load growth, which are required to be on a bilateral contract basis.
Finally, Bonneville would not sell directly to new retail loads, beyond the existing DSI loads, though it may sell through intermediaries whose transactions would be subject to state or local jurisdiction.
Implementation of the Federal Power Marketing Recommendations
To ensure public accountability, regional acceptance and prompt implementation of the committee’s recommendations, the governors should appoint a high-level board. This board shall be known as the Northwest Energy Review Oversight and Implementation Board. The Board should remain in place only until the recommendations of the Review are implemented.
The principal tasks of the Board will be to oversee the subscription process and provide liaison with the Northwest congressional delegation and affected constituencies. The Board periodically should determine whether the subscription process is making adequate progress or that it is not likely to succeed on a timely basis and another approach is necessary. The Board should report its findings to the governors.
The oversight Board could work with BPA on issues of cost control, development of a new administrative process for offering products and services, plans for marketing abandoned and non-firm power, and assisting the region in responding to federal legislation that is detrimental to the Northwest’s interests.
In addition, the Board should be responsible for determining the appropriate means for implementing other recommendations made by the Review. The means may include voluntary, administrative, legislative or regulatory actions.
Columbia River System Governance
Perhaps the central challenge the governors of our four states have given the Comprehensive Review is to advise them as to how the many benefits of the Columbia River System can best be preserved. The Steering Committee has struggled with this challenge and has made considerable progress. At a time when the electricity industry is already engaged in monumental regulatory and related changes, the challenges the river system faces bring an additional dimension of instability which is particularly unsettling. We cannot expect to achieve both the degree of cost stability the electricity industry requires to maintain the benefits of the Columbia River Power System for the region and achieve sustainable fish restoration unless we ensure predictability, accountability and effective governance for the fish and wildlife interests of the river. In short, an effective conclusion of our effort is not possible without an improved system of river governance that pursues fish restoration as a high priority
The Steering Committee’s focus has
been primarily on the electricity industry. The river’s
assets, liabilities and obligations, however, involve a host of sovereigns
and a complex web of other interests. There is not a consensus on the Steering
Committee on the matter of river governance. The electric industry
is an important stakeholder with a vital interest in the river
governance issue and must participate in resolving the problem,
but it cannot dominate the process.
The electric power industry recognizes
the importance of paying its fair share of the costs of effective
river stewardship. But money alone will not solve these complex
problems. Fish restoration requires a significant financial
investment to fund effective programs ensuring the survival of
the fish. Equally important, however, the region must be assured
of a governance structure that can make effective decisions and
quickly resolve disputes over the operation of the river. Without it,
there cannot be the cost stability that will encourage the
region’s electric utilities to reinvest in Bonneville Power
Administration resources, the cost for all will increase, and,
more importantly, fish populations likely will continue to erode.
The Steering Committee was asked by the Northwest governors to focus on the restructuring of the electricity system and to address the financial stability of the federal power system. We have done our best to recommend changes to the federal system that accomplish that goal. We fully recognize that there are other important, related issues and decisions, including those affecting fish and wildlife, that must be resolved before a truly comprehensive package can be achieved. As the Governors consider the Steering Committee’s recommendations, they should use the opportunity to consult with the appropriate federal, state, and tribal authorities and urge that the fishery issues move forward in the same level of zeal and dispatch in a parallel process on the same schedule as implementation of these recommendations. Addressing both power and fish concerns will help achieve a consensus in the region that will benefit our efforts as federal restructuring legislation advances.
The Steering Committee considered a number of matters related to the governance of the river and the power system. The role of the Power Council in river governance was not addressed but needs to be. River governance is a fundamental part of any effective response to changes in the electric utility industry. Until governance deliberations move forward in a government to government consultation among federal, state and tribal authorities, the prospects for a consensus on the regional response to utility restructuring are diminished and controversial.
The region may need a new (and
expeditious) look at the questions of river governance. Representatives
of the region’s tribal, state and federal governments and
perhaps others would need to be involved for there to be any
chance of success.
For some, the issue of river governance appears as intractable as any the region has ever faced. However, there is reason for hope. Many of the stakeholders have been working together in various forums. We believe consensus is possible and believe it is important to pursue it on a schedule that ensures that the issue can be addressed expeditiously.
The Steering Committee may
requests the governors to initiate a broadly based discussion
of improvements in the river system’s governance mechanisms
that would provide for more effective decision making for this complex
ecosystem and all of its competing uses.
Cost Allocation at Federal Projects
As market pressures increase on the
federal power system, its ability to pay for non-power purposes
of the federal projects has become increasingly problematic, and
will likely become worse in the absence of a comprehensive solution
to the federal power marketing issues in the Pacific Northwest.
In particular, the historical allocation of costs to electricity
customers for the portion of the federal dams devoted to
irrigation has stirred debate.
It is not possible to determine whether
these cost allocations should continue or be altered without further
information. The Steering Committee may ask the governors to
request that the Northwest congressional delegation ask the General
Accounting Office to investigate whether the cost allocations contained in
the authorizations for the Federal Columbia River Power System projects still reflect
the appropriate and accurate allocation of costs and benefits
among the various purposes of the projects. This study should
also recommend whether the current repayment responsibilities for
those costs among the various public purposes should be continued
or be altered.
Bonneville and other federal entities
should maintain an accounting system that will show the various
non-power and power costs and payment responsibilities among the
public purposes of the Columbia River projects.
Conservation, Renewable Resources and Low-Income Energy Services: Reflecting the Values and Meeting the Needs of Northwest Citizens
Goals
Three clear goals are proposed for conservation, renewable resources and low-income energy services:
- Conservation – to ensure that all cost-effective electric efficiency opportunities are captured in a manner consistent with increasingly competitive electricity markets.
- Renewable resources – to continue to develop renewable resources in the region.
- For residents of the Northwest who must live on limited incomes – to ensure low-income consumers are adequately, affordably and fairly served in a competitive electricity market.
The goals for conservation and renewable
resources should be achieved by relying, wherever possible, on
market forces to accomplish cost-effective conservation and
renewable resources. However, the Steering Committee recognizes
that the market for energy efficiency services may not capture
all cost-effective conservation. Similarly, potentially valuable
renewable resource technologies, not currently economically
competitive, may benefit from regional investments that reduce
their future costs. The Steering Committee also recognized that
competitive markets are unlikely to provide households with limited
incomes with means to meet their basic electricity services needs
at the same level and quality they currently enjoy. The proposal
concludes that during the transition to a competitive electricity
market, the region’s retail power suppliers should commit three
percent$210 million per year (1995$) of
their retail revenues to facilitating the development of
cost-effective conservation and appropriate renewable resource
options, and sustaining appropriate low-income energy services.
It is proposed that tariffs to collect these funds should be implemented
simultaneously with implementation of open retail access.
Background
Conservation
For nearly two-decades electric utilities in the Northwest have been the dominant force behind the development of conservation. The rationale for their active pursuit of conservation stemmed from the fact that, until quite recently, the cost of new power generation exceeded the price charged consumers for electricity. Individual consumers were not paying the full cost of new generation, so acquiring new generating resources to serve new loads raised everyone’s rates. When utilities acquired conservation at a lower cost than new generation, the total cost of electricity for all consumers was less.
Conservation faces a different environment today than it did just a few years ago:
- The costs avoided by conservation are lower, leaving fewer conservation measures cost-effective.
- Retail electricity prices for many consumers are currently above the marginal cost of new generation. This means that these consumers have greater economic incentive to invest in conservation than do utilities.
- Competitive pressures, particularly retail access, make it more difficult for utilities to include the cost of conservation programs in their rates. If a utility adds the cost of conservation invested in one customer’s home or business to the rates charged to all its customers, some customers may seek an alternative supplier whose costs do not include conservation.
Despite these changes, conservation that costs less than alternative sources of power remains available for development in the region. For example, in its 1996 draft power plan, the Northwest Power Planning Council estimated that approximately 1,500 average megawatts of conservation would be cost-effective to develop in the region over the next 20 years. This is roughly equivalent to the electricity demand of a city half again as large as Seattle. There is some controversy about these estimates. The Steering Committee has not independently verified the Council’s draft estimates, nor does it endorsed them. However, even if their estimates are significantly reduced, the amount of cost-effective conservation remaining to be developed appears large enough to warrant efforts to ensure that it is developed.
There is currently some momentum behind conservation development in the region. This momentum is created by existing utility activities, and the funding already committed to those activities, as well as the market forces. This momentum could prompt the development of approximately one-third of the region’s cost-effective conservation potential over the next few years. By the year 2000, however, competitive pressures on utilities and persistent market barriers could cause the rate of conservation development to decline below the rate necessary to capture all of the region’s cost-effective conservation potential. On the other hand, utility customer service efforts and the actions of the market could result in an adequate pace of conservation development. Today, we do not know how much conservation will be developed by the market or by utility efforts, nor do we know what the true nature of the utility business will be in the future.
The Steering Committee is concerned about what happens during the transition and about what conditions will prevail after the turn of the century. Many of the market barriers to development of conservation resources still exist: lack of reliable information; different economic incentives for owners and renters, and manufacturers and consumers; and energy prices that do not fully reflect the environmental costs of that energy. The Committee expects the competitive market for efficiency products and services to be stimulated by the opening of competition. However, the market for efficiency services is still immature. The development of this market should be closely monitored, particularly in the industrial and large commercial sectors where most of the conservation potential is thought to exist. The experience thus far from countries that have already opened up their electricity markets to competition seems to indicate that the market for efficiency products and services will not develop quickly without special attention.
Renewable Resources
Renewable resources can offer unique social and energy system benefits. These benefits include environmental value, such as the avoidance of carbon dioxide emissions that may be contributing to global climate change; resource diversity; and local economic benefits. Some applications of renewable resources, for example, the use of solar photovoltaics in remote locations, are cost-effective today. However, utility-scale solar, wind and geothermal technologies still are more expensive than gas-fired combustion turbine alternatives and current market prices. For example, several renewable resource projects designed to confirm various technologies under Northwest conditions are being developed by Northwest utilities and Bonneville. As a result of recent declines in the price of new power generation, these projects are anticipated to produce electricity that is from one and one-half to four times more costly than gas-fired combustion turbine alternatives. In an increasingly competitive electricity market, additional renewable resources may not be developed unless their economics improve or consumers demonstrate a willingness to purchase their power at somewhat higher prices because of their environmental benefits.
Though few renewable resources are cost-effective in the near-term, ensuring that renewables are available for future development may have appreciable economic value. An unexpectedly rapid rise in natural gas prices and/or the adoption of carbon dioxide control measures could favorably alter the economics of renewables. For instance, although such estimates are inherently uncertain, it has been estimated that the imposition of a carbon tax of $40 per ton in the year 2005 could increase the lifetime benefits of developing renewables in the Northwest to just under $1 billion compared to $28 million in the no-carbon-tax case.
Low-Income Energy Services
Programs to ensure that low-income consumers are adequately and fairly served include 1) energy efficiency services, 2) energy assistance, and 3) customer service practices. Energy efficiency services include traditional weatherization, creative efficiency programs, and consumer education. Energy bill assistance includes emergency assistance, rate discounts, percentage of income payment plans, fuel funds, traditional payment assistance programs such as the federal Low Income Heating Energy Assistance Program (LIHEAP), and integration of services with other social service agencies.
It is estimated that approximately 14 percent of the households in the Northwest have incomes below 125 percent of federal poverty guidelines. This amounts to 540,000 households. About 55 to 65 percent of the dwellings occupied by low-income households that are heated with electricity have yet to be fully weatherized. This translates into between 165,000 and 235,000 electrically heated homes, apartments and mobile homes that are not as energy efficient as they should be given current and expected future electricity costs. This means higher electricity bills for those who can least afford them.
Historically, low-income energy service programs have been funded from a combination of federal, state and utility sources. In 1995, roughly $19 million per year was provided for low-income weatherization assistance in the region. The region’s utilities and Bonneville are providing about 40 percent ($7 million) of these funds. Also in 1995, approximately $39 million was provided for bill payment assistance of some type. The region’s utilities provided about 40 percent ($16 million) of this assistance, with all of the remaining funds coming from federal sources.
In recent years, there has been a substantial reduction in the level of federal contribution to these programs. For example, federal funding of LIHEAP in Washington State was reduced by 42 percent between 1994 and 1995. State and utility contributions have not been increased to offset the reduction in federal funding.
Proposal
To ensure that cost-effective conservation,
renewable resource development and low-income weatherization are
sustained during the transition to competition and beyond, the
proposal recommends that, by July 1, 1997, $210 million per
year 3 percent of the in revenues
from the sale of electricity services in the region be dedicated in
aggregate over the region to those purposes for a period of
10 years.(1) Based on 1995 revenues, this amounts to approximately $210
million per yearthree percent of the region’s
electricity revenues. This $210 million is 65 percent of what
was spent for these purposes in 1995 by the region’s
utilities and Bonneville.
The Steering Committee recommends that each of the Northwest state adopt legislation that ensures that all electric utilities operating within its borders are contributing to the development of conservation and renewable resources and providing weatherization and energy efficiency services to low income consumers. The legislation should set forth a minimum standard for retail distribution utility investments in conservation and renewable resources and the provision of weatherization and energy efficiency services to low income consumers. The legislation should also provide for the assessment of a uniform system benefits charge that ensures the collection and investment of funds for these purposes, should this minimum standard not otherwise be met by July 1, 1999. Due to the rapid emergence of competitive pressures, the Committee strongly recommends prompt legislative action.
The Steering Committee believes that the majority of these funds are most appropriately used at the local level. Consequently, the proposal recommends that as much as 83 percent and at least two-thirds of the funds be retained by local distribution utilities to carry out locally-initiated cost-effective conservation and low-income weatherization and energy efficiency services. A greater proportion of the funds would be retained by local distribution utilities to the extent they chose to exercise the option to develop renewable resources or provide incentives for renewable resource marketing.
Some conservation and renewable resource activities may, however, benefit from regional planning and coordination. The proposal recommends that not less than one-sixth nor no more than one-third of the funds be used by a regional non-profit agency with utility, government and public interest membership. Its functions would be to bring about changes in the markets for targeted energy efficiency and renewable resource products and services that will improve their market share; to plan and contract for research and limited demonstration of renewable energy technologies; and to support the development of renewable generating capacity. The Steering Committee also believes that retail distribution utilities should have the option of supporting the use of renewable resources through local initiatives and has made provisions for this alternative in its recommendations.
A Regional Technical Forum would be established to develop standardized protocols for verification and evaluation of energy savings, to track regional progress toward the achievement of the region’s conservation and renewable resource goals and to provide feedback and suggestions for improving the effectiveness of conservation and renewable resource development programs in the region. The approximate allocation of funds to different purposes is shown in Table 1. The specific proposals are described in detail in the following sections.
Table 1
Annual Allocation of Funds to Conservation, Renewable Resources, and Low-Income Energy Services
Purpose |
Percent of electricity revenues |
Percent of Public Purpose Funding |
$ Millions based on (1995$) electricity revenues |
| Local Conservation | 1.6% |
52% |
$110 |
| Low-Income Weatherization | 0.4% |
14% |
$30 |
| New Renewable Resources | 0.0% - 0.49% |
0.0% - 16% |
$0 - $34 |
| Total – Local Administration and Implementation | 2.0% - 2.49% |
67% - 83% |
$140 - $174 |
| Conservation Market Transformation | 0.43% |
14% |
$30 |
| Renewable N |
0% - 0.49% |
0% - 16% |
$0 - $34 |
| Renewable Resource Research | 0.014% |
>1% |
$1 |
| Renewables Development and Demonstration | 0.071% |
2% |
$5 |
| Total – Regional Administration and Implementation | 1.0% |
17% - 33% |
$36 - $70 |
| Total | 3.0% |
100% |
$210 |
Conservation
Conservation was divided into two areas for action: local and regional conservation. "Local conservation" covers those actions designed to influence on-site consumer efficiency choices. Local conservation also includes low-income weatherization activities. Regional actions include the establishment of a "regional technical forum" and a non-profit entity to carry out conservation market transformation.
Local Conservation, Including Low-Income Weatherization
The proposal recommends that the region’s
retail distribution utilities commit to allocateing
at least $140 million per year 2 percent of the
revenues from sales of electricity and distribution services toward
the development of cost-effective conservation and low-income
weatherization and energy efficiency services for the next
10 years. Tariffs to collect these funds should be
implemented simultaneously with implementation of open retail
access. Based on current electricity revenues, this is
anticipated to generate It is recommended that approximately
$110 million per year be allocated to in
local conservation investments and $30 million per year be
allocated for local investments in low-income weatherization
in the region. Retail distribution utilities Large customers
may be credited for documented conservation investments made in by their facilities. customers. Such credits
should not include their contribution to regional market
transformation and renewable resource research and demonstration
efforts and low income weatherization and energy efficiency service
costs. It is proposed that these customers have the
option of receiving credit for documented conservation
investments in their facilities up to the equivalent of their
share of the local distribution utility’s revenue commitment
to conservation, excluding low-income weatherization. The
proposal recommends that local conservation efforts and
low-income weatherization funding be provided through direct
contributions from the region’s retail distribution utilities. Similar
to the new Bonneville/State agreement, utilities are encourage to
use the existing State/Local Agency low-income weatherization system
as a means of accomplishing this work to avoid duplication.
For purposes of tracking regional progress on conservation and low-income weatherization, it is proposed that all retail distribution utilities and State and local low income weatherization service providers adopt and publish an annual report of their conservation and low-income weatherization achievements. This report should identify at least the amount of conservation achieved by economic sector, the number of dwellings occupied by low-income households that were weatherized and level of utility investment in these areas. The proposal also recommends that utilities make this report available to the non-profit entity to be established to carry out regional market transformation for conservation and renewable resources so that regional efforts can be effectively and efficiently coordinated with local efforts.
Regional Technical Forum
The proposal calls for the establishment of a
Regional Technical Forum (RTF). The Congress directed
Bonneville and the Northwest Power Planning Council to establish
a forum to develop standardized protocols for verifying and evaluating conservation
savings. The Steering Committee recommends that the RTF forum should
track progress toward achievement of the region’s goals for conservation and
renewable resource development and provide feedback and suggestions
for improving the effectiveness of conservation and renewable resource development
programs. The RTF should also conduct periodic reviews of the region’s
progress toward meeting its conservation and renewable resource
goals at least every five years. The RTF would be composed of representatives
of utilities, other electricity services providers, government
and public interest groups.
Market Transformation
The proposal calls for the region’s retail
distribution utilities to, as soon as possible, mount a coordinated
effort to transform markets for efficient technologies and
practices. The intent of market transformation is to undertake
activities that will increase the market share of targeted efficiency
products and services that will be sustained after incentives or
other support are withdrawn. A successful example is the effort
to improve the efficiency of manufactured housing in the
Northwest. Utilities initially paid significant incentives for
the construction of very efficient manufactured homes. As a
consequence, the demand for such homes was so great that it was possible
to remove the incentives while still capturing a high percentage
of the market. Because markets invariably cut across utility and
jurisdictional boundaries, it makes most sense to pursue these
efforts at a regional scale. This effort should establish a
non-profit entity to manage conservation market transformation
ventures for the region. This entity’s governing body should consist
of utility, government and public interest representatives. This
entity should have a planned life of at least 10 years in
recognition of the time required to permanently transform markets
and the range of markets or end-uses to be targeted. Efforts
are already under way to establish such The recent
formation of the Northwest Energy Efficiency Alliance, an
entities y with whose initial funding
is coming from approximately equal contributions by Bonneville
customers through Bonneville’s rates and the region’s
investor-owned utilities appears to be consistent with the Steering
Committee’s recommendations. The proposal
recommends that long-term funding of the region’s market
transformation ventures for conservation should be provided by
direct contributions from the region’s retail distribution
utilities of 0.43 percent of electricity revenues. This It
is anticipated to provide that
approximately $30 million per year (1995$) should be allocated
for conservation market transformation.(3)
Renewable Resources
The Steering Committee also considered a range of options for meeting its goal for developing renewable resources in the region. The Committee’s draft recommendations for renewable resources are described below.
Existing Renewable Resource Projects
The proposal calls for the sponsors to complete
the current wind and geothermal demonstration and pilot projects.
Funding these projects is the responsibility of the respective
project sponsors and is not included as part of the 0.49
percent of revenues to be committed to the development
of new renewable resources.
New Renewable Resource Projects
The proposal also recommends that renewable
resource market transformation activities be planned and carried
out by the newly established non-profit entity charged with
conservation market transformation. Alternatively, retail
distribution utilities may dedicate the equivalent of their share
of the regional renewable resource market transformation funds to
locally initiated programs. Such funds should be earmarked toward
defraying the above market costs of renewable resources. Among
many options, the utility could use its share to provide
incentives for green marketing programs, acquire renewable
resources or have marketers bid to leverage the utility’s share
to yield the greatest value for its customers. Regardless of
whether regionally sponsored or locally initiated Iit
is proposed that renewable resource market transformation
activities focus initially on the development of "immature" new
renewable resource technologies, including solar, wind,
geothermal, hydroelectric (outside of protected areas as defined
by the Council, and other federal or state agencies and statutes)
and low-emission organic, non-toxic biomass. Depending on the
success of "green marketing" to consumers in the
region, additional renewable resource development may occur. Long-term
funding (next 10 years) of the region’s market
transformation ventures for renewable resources should be
provided by direct contributions from the region’s retail
distribution utilities of approximately 0.49 percent of their
retail revenues. It is anticipated that this
will provide approximately $34 million per year (1995$)
should be allocated for these purposes.(4) in
contributions from retail distribution utilities.
Renewable Resource Research, Development and Demonstration
The proposal calls for the region’s retail distribution utilities to allocate $1 million per year for research, and $5 million per year for development and demonstration of distributed renewable resources.(5) These funds would be used by the non-profit entity established to carry out market transformation for conservation and research, development and demonstration of renewable resources.
Green Marketing
The proposal recommends that retail distribution utilities should provide for "green marketing" (i.e., the sale of power from qualifying renewable resources) to individual consumers in advance of full retail open access. Retail distribution utilities may accomplish this by offering their retail consumers "green resources" or by permitting other energy service providers to sell "green resources" to their retail consumers.
Low-Income Energy Services
Low Income Energy Assistance
The proposal calls for utilities to maintain
their current level of low-income energy assistance (estimated
to be at least $16 million/year) until such time as states
adopt alternate mechanisms for providing these services. It
is estimated that total regional need for low-income energy
assistance is in the range $60 to $107 million per year. The
report proposes that states consider alternatives for providing
this assistance. These alternatives should ensure that
electricity prices are as low as possible and that energy
efficiency and consumer services, such as level payment
mechanisms, remain in place until they are supplanted by other approaches. The
report recognizes and affirms the energy system’s historic
role in providing energy assistance and proposes that states now provide
this assistance by Examples of these alternative
approaches include: establishing a Universal
Electrical Service Fund. This approach establishes
a "Universal Electrical Service Fund" to provide energy
bill assistance. This fund could be supported by a
retail distribution system access fee (meters charge),general purpose
government funding, including federal LIHEAP funds, state
or local government funds, other funds and/or by a retail
distribution system access fee or meters charge, Qualified
low-income (i.e., incomes 125 percent or less of the federal
poverty level) customers would be entitled to receive from all
electricity suppliers the bill assistance or rate discount needed to
ensure that they do not pay more than a fixed proportion (e.g., 5
percent) of their income for electric energy services. All
electricity suppliers could draw from the "Universal Electrical Service
Fund" to provide the bill assistance needed to serve each
qualified low-income customer, plus a standard administrative
cost. Existing retail distribution utility low-income energy assistance
program expenditures could should be
credited towards any required contributions to the Universal
Electrical Service Fund.
Portfolio Standard for Low-Income Service -This approach attempts to vest low-income customers with "market value" rather than being a burden to be avoided. Under this approach all licensed electricity suppliers would be required to serve a minimum proportion of qualified low-income (e.g., 125 percent of federal poverty level) customers as a condition of maintaining their license.(6)Electricity suppliers who served more than the minimum share could be permitted to sell their excess as "service credits" to other suppliers who had yet to achieve the minimum. In this approach, the cost to serve the minimum proportion of low-income customers would be internalized as a cost of doing business as an electricity supplier. How the supplier recovered any additional costs to serve low-income customers would be left to the supplier, as would how they managed to maintain their minimum proportion of low-income customers. If the supplier failed to maintain service to the minimum, their license could be suspended.
Exemption from Charges
It is proposed that qualified
low-income consumers be exempted from paying local distribution utility
charges that are adopted to support conservation, renewable
resources and low-income energy services.
Collecting and Allocating the Funds
This proposal relies on the voluntary
commitment of utilities and regulatory commissions to authorize
and carry out the collection, disbursement and appropriate use of
funds. State or federal legislation to require collection and
allocation of the funds to support regional market transformation
efforts for conservation and renewable resources, regional
research, development and demonstration of distributed renewable
resources, local conservation and low-income energy services is
not proposed at this time. The Steering Committee believes that a
voluntary, local adoption system will work. During the public
comment period on the draft proposal, the Steering committee will
test the quality of utility commitment. Actions such as tariff
filings, board resolutions or ordinances would be helpful in
providing evidence of such commitment. If it is determined to be necessary,
mandatory alternatives could be pursued. The Steering
Committee believes that a new mechanism is needed to ensure
adequate and stable funding for conservation, renewable resources and
low income energy efficiency services. This mechanism must be
compatible and consistent with a competitive market. The
committee proposes each Northwest state enact legislation that:(7)
- Establishes a minimum standard for electric distribution utility investments in conservation, renewable resources and the provision of weatherization and energy efficiency services for low income consumers. This standard should apply equally to publicly owned and investor-owned utilities.
- Determines the minimum annual investment per utility based on the utility’s share of the region’s total electrical use and a total regional investment target of $210 million (1995$).(8) Public utilities as a group should be encouraged to allocate their investments according to Table 1, above.
- Permits each distribution utility to determine how it collects revenues sufficient to meet this minimum standard in accordance with its existing regulatory structure, while recommending that allocations be based on cost of service standards.
- Requires that utilities demonstrate compliance with the minimum investment standard on or before July 1, 1999, and annually thereafter. Individual publicly-owned utilities should be provided the option of demonstrating compliance with the minimum investment standard "in the aggregate" by participating in collaborative/consortia efforts with other utilities. States should establish mechanisms to determine utility compliance with its minimum investment standard.
- Authorizes the imposition of a non-bypassable, local distribution system access charge (meter fee) on customers served by any distribution utility that fails to satisfy the minimum investment standard. This fee should collect revenue equivalent to that distribution utility’s minimum standard for annual investment in conservation, renewable resources and the provision of weatherization and energy efficiency services for low income consumers.
The tariffs to collect these funds Steering
committee recommends that legislation establishing the minimum
requirements set forth above should be implemented simultaneously
with legislation implementingation
of open retail access.
The Steering Committee is concerned that, due to competitive pressures, utility investments in conservation, renewable resources and low income weatherization and energy efficiency services are being reduced. In order to ensure a smooth transition and to provide an early indication of potential problems, the Committee recommends that each utility provide evidence that it is prepared to meet the minimum standard described above by July 1, 1997. Evidence could take the form of tariff/rate filings, adoption of a rate ordinances, budget resolutions by the utility’s governing board, or other affidavits that specify the funding level to be dedicated to these purposes. If utilities representing at least 90 percent of the regional end-use loads do not provide such evidence by July 1, 1997, then the Steering Committee recommends that the region seek federal backup to take effect July 1, 1999.
However, tThe Steering
Committee’s proposal makes no recommendations as to how
individual utilities should collect the funds, i.e., through a
charge based on volume of kilowatt-hours sold, through a
distribution access charge that is independent of or less
directly related to kilowatt-hour sales, or some other method.
The proposal relies on the appropriate regulatory bodies to
establish an appropriate method of collection. The Steering
Committee is mindful, however, of the fact that how the charge is
collected can have effects on both equity between customers and
the competitive balance between different suppliers or fuels. The
Committee is also aware that significant differences in how the
charge is collected between distribution systems can alter the competitive balance between
systems. The Steering Committee believes that regulatory bodies
will find it preferable to collect these charges in ways that do not
distort competitive balance.
Recommendations on the Scope of the Bonneville Power Administration's Energy Efficiency Services
Due to controversy regarding the proposed scope of Bonneville’s "Energy Services Business" (ESB), Congress has asked the Comprehensive Review Steering Committee to address the competitive implications of ESB activities; the appropriate level of capitalization for these activities; and provisions to minimize "cross-subsidies" from power marketing and transmission revenues.
By way of background, Bonneville has proposed that its future energy efficiency efforts be comprised of three elements:
- Declining support for its historical ("legacy") programs.
- Support for regional market transformation efforts.
- "Market development" activities designed to augment the market for energy efficiency services, particularly in federal facilities and through bi-lateral contracts with its wholesale power customers.
Currently, these activities are grouped together as Energy Services. The first two activities are not at issue. The market development activities have raised two primary concerns:
- The original proposal for an "Energy Services Business" included a variety of activities that were perceived to put Bonneville in competition with private sector energy efficiency business in a finite market.
- Various parties were skeptical that the market development activities could be self-supporting, particularly to the extent that safeguards were put in place to prevent Bonneville from competing with private energy efficiency providers.
To resolve the first of these concerns, Bonneville worked extensively with the Northwest Energy Efficiency Council (a trade organization representing energy efficiency businesses) and other regional parties to develop principles that would focus Bonneville’s market development activities on increasing the market for privately-delivered energy services, rather than competing in that market. In the following recommendations we expand upon those principles.
To respond to the second concern, we propose to limit Bonneville’s net spending and capital borrowing during the rate period to levels substantially below Bonneville’s October 31 proposal. We have concerns about Bonneville’s ability to control costs in the long run. However, the Steering Committee has neither the time nor the inclination to micro-manage Bonneville’s staffing and accounting methodologies. Rather, we propose to resolve these concerns by putting tight limits on Bonneville’s net expenditures on this activity.
Recommendations
- Bonneville’s energy efficiency activities are not a "business." The purpose of these activities is to serve Bonneville’s statutory directive to promote cost-effective energy efficiency investments. We consider it unlikely that these activities will completely recover their costs without unduly competing with private enterprises. To address concerns about the net cost of these activities, we propose borrowing and spending caps in items 11 and 12 listed below.
- Bonneville’s role in market development should be structured and managed to enlarge energy efficiency markets beyond that which is being profitably captured by private business.
- Bonneville’s market development activities should be limited to markets or individual situations that are not currently accessible, viable, or profitable for the private sector energy efficiency industry.
- Bonneville’s market development activities should be designed and implemented to take full advantage of private sector energy goods and services. These activities should not favor one competitor over another.
- Bonneville will act primarily as a facilitator/aggregator of transactions for services provided by its partners.
- Specific Bonneville market development activities will be discontinued when they become viable and profitable for the private sector energy efficiency business.
- An advisory board should be established immediately to monitor Bonneville’s compliance with these restrictions. The advisory board should consist, among others, of private businesses that could be adversely affected by Bonneville’s failure to comply with these restrictions as well as power and transmission customers. Bonneville should consult with and report to this board at regular intervals, and the board should report concerns to the Regional Council.
- Bonneville’s market development activities should be limited to its regional power sales contact customers and federal agencies. Bonneville should provide energy efficiency services for federal agencies in cooperation with the serving utility or when the serving utility cannot or elects not to provide those services itself.
- Agencies and customers contracting for market development services should repay the full cost of those services, including repayment of loans at the appropriate Treasury rate.
- Any Bonneville organizational unit or activity currently named "Energy Services" should be renamed "Energy Efficiency." This is intended to clarify that previous proposals to undertake a broad spectrum of other retail services have been dropped, and to preclude Bonneville support for load-building activities that are inconsistent with Bonneville’s conservation directives.
- Bonneville’s use of Treasury capital should be limited to $5 million per year and restricted to Federal projects. This represents a reduction of roughly 50% relative to Bonneville’s October 31 proposal, and a reduction of $71 million relative to the final rate case figure. Capital borrowed from Treasury should be repaid in full by the participating federal entity. All third party borrowing shall be non-recourse to Bonneville.
- Bonneville’s net costs for market development activities should not exceed $8 million for the FY 97-2001 rate period. Bonneville’s energy efficiency activities should be self-supporting by September 30, 1999 or these activities should be terminated.
- Bonneville should revise its October, 1995 record of decision for Firm Non-Requirements Products and Services Contracts by replacing the "Energy Services" section with an "Energy Efficiency" section that incorporates a final plan for energy efficiency’s activities consistent with the restrictions herein. The energy efficiency plan should not include activities listed in the original ROD "Energy Services" section except those directly related to energy efficiency. Other new activities listed in the original ROD "Energy Services" section should not be offered by any part of Bonneville in competition with the private sector.
Consumer Access to the Competitive Market: Ensuring the Benefits of Competition for All
Goal
The goal of the comprehensive review steering committee recommendations on retail markets and customer choice is to encourage a more efficient power system, lower electricity costs, and increased product choice and greater product innovation for all consumers. These were adopted subject to a commitment to maintain the reliability and safety of the electrical power system. The steering committee concluded that this goal could best be accomplished by putting in place a competitive electricity market that is driven by consumer choice. This section describes the background of facts and trends which led to this decision, then describes the recommended vision of a competitive retail electricity market driven by consumer choice, and finally lays out several steps that should be taken to accomplish a transition to this competitive market by 2001.
Background
The steering committee decisions about competition and customer choice in the retail electricity markets were made in the context of the changes already occurring in regulation, legislation, and electricity markets themselves. The changes that affect retail markets are more recent than the changes in the wholesale markets, but they are a natural extension of those changes. FERC Order 888 will force open the wholesale markets for electric power, but that order left decisions about retail electricity markets to the states.
During the past year, most states have initiated processes to address the question of retail competition. A variety of conclusions have been reached. Some states, such as California, have established schedules and passed legislation for moving to retail competition. Others, such as New Hampshire and Illinois, have developed pilot programs to test the feasibility of retail competition in electricity. Others have allowed retail wheeling rates for large customers on a case-by-case basis. There is enough action at the state level on retail competition to establish a perception of tremendous momentum toward a more competitive retail electricity market. "It’s inevitable", was a phrase heard often during the comprehensive review process.
In spite of the high level of state activity in this area, or perhaps because of the uneven progress by states, national legislation has been introduced to require retail competition in electricity markets nation wide. Rep. Dan Schaefer (R-CO) introduced a bill entitled "The Electricity Consumers’ Power to Choose Act". This bill would give all consumers the right to choose their electric service provider by December 2000. A similar bill, the "Electric Power Competition Act of 1996", has been introduced by Representative Edward Markey (D-MA).
The strong momentum toward retail competition reflects the current feasibility of some large consumers acquiring their own electricity supplies in the wholesale market. Prices of wholesale power often are below the price industries are paying their local utility and the potential savings are an important factor in businesses’ bottom lines. Large users are quick to point out that they buy almost nothing at retail except for electricity. Similarly, power marketers are anxious to provide power and services to large customers. Both energy marketing companies and large users support more open retail power markets.
Opening up retail markets only to large users, however, is highly controversial and would, in all likelihood, limit the potential benefits that could be gained from more active competition. The major concern is that additional costs would fall on small captive customers as a result of large consumers acquiring their electricity elsewhere and leaving stranded costs behind. Without some agreement on how to recover stranded costs, there is a clear temptation to pass those costs on to captive customers.
The surest way to prevent shifting of costs to small captive customers is to free them to acquire their power supplies from alternative sources, just like the large consumers. When consumers have choice among electricity suppliers it is very difficult to subsidize other consumers at their expense. However, unlike the wholesale market, there is currently no well developed competitive retail electricity market. There are many important issues to be addressed and several technical problems to be solved before a widely available retail electricity market can be developed.
One of the major concerns raised is that of continued universal service at affordable prices. Reliable electricity supplies are a fundamental component of modern lifestyles and public safety. Some are concerned that few competitive electricity suppliers will come forth to serve small consumers, especially low income consumers, at affordable rates. There may be increased need for consumer protection standards and information and education to help consumers make decisions about a product that is invisible, but essential to modern life. Some form of oversight may be needed to ensure a truly competitive retail market and to keep separate the regulated and competitive portions of the electricity system. And more sophisticated billing and metering systems will be needed to keep track of the vastly increased number of participants in the market.