1

The Future Role of the Bonneville Power Administration in 

Power Supply

Introduction and Summary

The crown jewel of the Northwest Power System is the federal Columbia River Power System 

(FCRPS). The FCRPS consists of 31 dams on the Columbia River and its tributaries. On 

average, it supplies approximately 45 percent of the region’s power. This federal hydropower is 

priced at cost and is sold by the Bonneville Power Administration primarily to publicly owned 

electric utilities. While construction of the FCRPS was financed by the federal government, the 

debt is repaid by Northwest electricity users. Interest rates on the federal debt are now equal to 

market rates. 

Despite the fact that Bonneville has not deferred any payments to the U.S. Treasury since the 

early 1980s, it is continually attacked by organizations like the Northeast-Midwest Institute1 and 

its congressional allies as being subsidized by the federal government. Critics advocate 

privatizing Bonneville or requiring Bonneville to sell its power at market prices to benefit U.S. 

taxpayers as opposed to selling at cost to Northwest consumers who paid for the system and are 

paying to restore fish and wildlife affected by the dams. While these proposals have not yet 

gained sufficient political support to move ahead, fighting them has been a continuing battle for 

the region’s utilities, governors, the Council and the congressional delegation. Moreover, each 

time Bonneville finds itself in financial difficulties with Treasury repayment at risk, the pressure 

for “reform,” such as privatization, intensifies. 

Over the last decade, the disparity between the cost of Bonneville’s power and the market rates 

for wholesale power frequently has not been large and, in fact, at some times has been 

disadvantageous to Bonneville’s customers. Nonetheless, the base of federal hydropower is 

likely to be a low-cost resource for many years to come. Preserving this benefit for the 

Northwest consumers who pay for it should be a high priority for the region. However,

preserving the benefit in the face of recurring financial crises at Bonneville will be difficult. 

Thus it is time to re-examine Bonneville’s role in regional power supply and whether that role 

can continue as it has in the past without jeopardizing the region’s legacy of reasonably priced 

power. 

This paper outlines the problems Bonneville and the region have faced in recent years. It 

appears these problems are likely to continue unless Bonneville’s role in regional power supply 

changes. The paper reviews the potential solutions developed through several public processes 

carried out over the last decade, including the Comprehensive Review of the Northwest Energy 

System, carried out in 1996, the follow-on Bonneville Cost Review and finally the Joint 

Customer Proposal and Regional Dialogue of 2002. One common element of these processes 

was the recommendation that Bonneville sell the federal power through long-term contracts (20 

years) to reduce uncertainty and help protect the region from external efforts to appropriate the 

benefits of the FCRPS. Another common recommendation was to limit Bonneville’s and the 

 

1

 E.g. see Rethinking Bonneville – Why BPA Must Be Reformed, Richard Munson, Northeast-Midwest Institute, 2001, 

http://www.nemw.org/rethinkingbonneville.pdf
2

region’s exposure to risks of the wholesale power market by limiting Bonneville’s role in serving 

loads beyond the capability of the FCRPS. This could be accomplished through bilateral 

contracts, in which customers bear the cost and risk of resources Bonneville has to acquire in 

order to augment the federal system and serve load. For various reasons, efforts to implement 

these and other recommendations developed in the public processes have stalled. 

The Council believes the region should address the question of Bonneville’s future role in the 

regional power supply now, before another crisis develops. The Governors of the four 

Northwest states have recognized that perpetuating uncertainty regarding Bonneville’s role risks 

the adequacy and economy of the region’s power supply. The Governors asked the Council and 

Bonneville to reinitiate the Regional Dialogue, which was suspended in 2002 while Bonneville 

addressed its most recent financial crisis. As a result, a number of discussions with 

representatives of customers, regulators, industry, and environmental interests were held. The 

major conclusion drawn from these discussions is that while some things may have changed and 

need to be reexamined, many of the basic elements of the 2002 Joint Customer Proposal still 

have regional support and could form the foundation for moving forward.

The Council proposes the following principles or characteristics to guide the region in addressing 

the question of Bonneville’s future role. These principles reflect 1) the Council’s understanding 

of circumstances that may have changed in the last year; 2) the perspectives expressed during the 

recent discussions; and 3) the Council’s review of the original Joint Customer Proposal and its 

subsequent December 2002 recommendations on the future role of Bonneville.2 

Proposed Principles for the Future Role of Bonneville

• The goal should be long-term contracts (20 years) both to protect the system from 

interventions from outside the region and to reduce uncertainty for both the customers 

and Bonneville. 

• Bonneville’s primary role, in addition to transmission, should be managing the operation 

and marketing the output of the Federal Columbia River Power System. The FCRPS is a 

multipurpose public resource and Bonneville has a record of real expertise in its 

operation and marketing. 

• Bonneville’s role in providing power beyond the capability of the federal base system 

should be limited to bilateral contracts or rate mechanisms that align the benefits and 

costs. This would limit Bonneville’s exposure to market risks and reduce the uncertainty 

regarding who will be acquiring additional resources thereby reducing an impediment to 

resource development.

• Bonneville’s role should be limited contractually. Although most customers’ contracts 

run through 2011, these changes need to be enacted as soon as possible so as to protect 

the regional resource from outside interference and clarify the outlook for resource 

development

• Customer agreement to long-term contracts will require at minimum that Bonneville: 1) 

provide customers and others greater openness regarding their costs, the factors driving 

 

2Final Recommendations on the Future Role of Bonneville, Council Document 2002-19, December 17, 2002. 

http://www.nwcouncil.org/library/2002/2002-19.htm
3

those costs and the decisions affecting them BEFORE decisions are made; 2) implement 

cost-reducing process improvements; and 3) rebuild trust with the customers and others 

that Bonneville is a good business partner. 

• Revising Bonneville’s role in acquiring and pricing the output of additional resources will 

require an allocation of the federal base system resources and benefits. Any allocation 

method for the FBS should be equitable and consistent with federal law while creating a 

broad constituency for Bonneville. 

• A significant amount of the system should be offered as a “Slice” product . The slice 

product effectively distributes hydro risk and, by virtue of more diverse decision-making, 

should reduce the impact of hydro variability on the market. 

• Benefits should be provided for the residential and small farm customers of the region’s 

investor-owned utilities in a way which is judged to be equitable by the parties and that is 

clear and transparent and not subject to manipulation by any of the parties.

• The question of service to the DSI’s must be addressed. If power is made available to 

DSIs, the amount and term should be limited and contracts should be structured to allow 

Bonneville to capture benefits of DSI load interruptibility and provision of reserves. The 

smelters should be encouraged to reduce dependence on Bonneville power in the longterm.

• Any solution must contain a mechanism for ensuring continued regional development of 

cost-effective conservation, as determined through the Council’s plans. While limiting 

Bonneville’s role to develop new power supplies to bilateral arrangements with 

customers is a major step in the right direction, it is not sufficient to ensure the 

development of cost-effective conservation given the disincentives to utility investment 

in conservation. Reliance on local implementation is appropriate so long as there is a 

focus on cost-effectiveness and accountability and a backup mechanism is included to 

ensure that conservation is implemented. A direct Bonneville role in implementation is 

appropriate where there are economies of scale or other benefits from Bonneville’s direct 

involvement. 

• Similarly, a mechanism is required for ensuring that cost-effective renewable and high 

efficiency resources are developed and that the ability of the hydropower system to 

support the development of intermittent renewable resources, through the flexibility of 

the hydropower system, should not be unduly impaired.

• Bonneville’s ability to implement its fish and wildlife obligations must not be impaired. 

Questions for Public Comment

The Council is interested in public comment on the following:

1. Do you think the analysis of the problems and issues presented in the paper is accurate? 

If not, how is it inaccurate?

2. Do you agree that a more limited role for Bonneville in power supply as described in 

principles is appropriate? If not, why?
4

3. Do you think the question of Bonneville’s future role in power supply needs to be 

addressed in the near future? If not, why?

4. Do you think the principles or characteristics proposed by the Council are appropriate 

guidance for consideration of Bonneville’s future role? If not, why?

Please submit comments on this issue paper and, specifically to the above questions, by the close of 

business Friday, December 12, 2003. Public comments also will be accepted at the Council’s November 

19, 2003 meeting in Coeur d’Alene, Idaho, and its December 10, 2003 meeting in Portland, Oregon. 

Please address all comments to Mark Walker, Director, Public Affairs, Northwest Power Planning 

Council, 851 S.W. Sixth Avenue, Suite 1100, Portland, Oregon, 97204. Comments will also be accepted 

via e-mail at comments@nwppc.org. Please indicate that you are commenting on Council document 

2003-18.
5

What’s the Problem?

The problem is that Bonneville is financially and politically vulnerable and, as a consequence, 

the region and its economy are also vulnerable. Bonneville’s financial vulnerability arises in part 

from its dependence on a highly variable hydroelectric base and the effects of a sometimes very 

volatile wholesale power market. Another source of vulnerability arises from the asymmetric 

nature of the obligations between Bonneville and many of its customers and how Bonneville has 

historically chosen to implement its obligations. Other vulnerabilities arise out of other choices 

Bonneville has made in serving other customers in the region. These vulnerabilities are 

exacerbated by Bonneville’s high fixed costs for its debt on the Federal Columbia River Power 

System and the three nuclear plants that were undertaken with Bonneville backing by the 

Washington Public Power Supply System, now Energy Northwest.3 At times, these 

vulnerabilities can cause Bonneville to incur high costs that must be passed on to customers and 

ultimately to the region’s consumers. If they are not, Bonneville risks being unable to make 

Treasury payments. Rate increases cause economic hardship in the region; not making a 

Treasury payment risks a political backlash from outside the region that could cause the 

Northwest to lose the long-term benefits of power from the federal system. 

Hydropower and Market Vulnerability

The FCRPS, also called the federal base system, includes the federal dams on the Columbia and 

its tributaries, the Columbia Generation Station nuclear plant operated by Energy Northwest, and 

some smaller power projects. The FCRPS supplies almost 8,000 average megawatts of energy 

under critical water conditions,4 6,800 average megawatts of which come from the hydroelectric 

system. 5 In years with extremely good water conditions, hydropower generation can be 

increased by over 3,500 average megawatts. However, the month-to-month shape of 

hydropower generation does not always match loads. Even under relatively good hydropower 

conditions, Bonneville can be in the market at certain times to purchase power. Under poor 

hydropower conditions, Bonneville can be in the market for a great deal of power and, depending 

on the overall resource situation, those conditions can drive up power prices. Unfortunately, the 

risks and benefits are not symmetrical. When Bonneville has ample non-firm power to sell, the 

availability of this power frequently drives wholesale market prices down. The more volatile 

power markets are, the more difficult managing these risks becomes. If prices are high and 

Bonneville has non-firm power to sell, it is accused of gouging. If prices are high and 

Bonneville is faced with poor water conditions and large purchase requirements, the costs can 

very quickly erode Bonneville’s financial condition. Hydropower and market risks played a 

large role in Bonneville’s financial crisis of 2002-2003.

Asymmetric Obligations

As noted above, another source of Bonneville’s financial vulnerability is the asymmetric, or 

unbalanced, nature of its relationship with its different customer groups. For example:

 

3

 Of the three plants, only one, Columbia Generating Station, is operating. The other two were terminated before construction was complete. 

However, Bonneville still has responsibility for paying off the debt incurred during construction. 

4

 Critical water is that pattern of stream flows that results in the lowest firm energy production from the hydroelectric system.

5

 Bonneville Power Administration 2000 Pacific Northwest Loads and Resources Study (Updated May 2002) 

http://www.bpa.gov/power/pgp/whitebook/2000/index.shtml
6

• Bonneville has a legal obligation to sell power to publicly owned utilities at cost if asked. 

However, Bonneville’s public customers do not have a legal obligation to buy from 

Bonneville until they have signed a contract.

• Bonneville does not have a legal obligation to sell to the direct-service industries, but 

there are powerful political pressures to do so.

• For investor-owned utilities, Bonneville has an obligation to provide benefits to existing

residential and small farm customers but has struggled to find a means of doing so that is 

satisfactory to all parties. It also has a legal obligation to meet the load growth of 

investor-owned utilities if requested although no such requests ever have been made.

While these customer obligations have existed for over 20 years, they have become increasingly 

problematic as the wholesale power market has become more competitive and volatile.

Public Customers

Bonneville is obliged to serve public agencies that choose to place their net power requirements 

on Bonneville.6 Public agencies can choose to put their net requirements on Bonneville and, 

although Bonneville can impose a waiting period to allow it sufficient time to acquire the 

resources to serve that load, it must serve that load. 

Bonneville is also required to sell its power at cost. It could, if it chose to do so, charge one costbased rate for the power from the existing system and another cost-based rate for the power from 

new resources it must acquire to serve new or growing loads (tiered rates).7 What the customers 

would pay in total wouldn’t necessarily be much different than what is paid under the current 

melded rate. Those whose loads are growing more slowly than the average should experience 

lower costs. In addition, customers would get a much clearer economic signal of the real value 

of the resource options that may be available to them, many of which may be local. However, in 

the face of opposition from its customers, Bonneville has never implemented such a rate 

structure. As a consequence, when Bonneville’s rate looks attractive relative to the market, 

customers have an incentive to place as much load as they can on Bonneville, even if Bonneville 

must acquire new resources to serve it. The costs of those new resources will be spread to all the 

customers in the region.

The effect of these policies was seen in 2000-2001, when public customers, many of whom had 

taken loads off of Bonneville in 1996, increased their loads on Bonneville by several hundred 

average megawatts for the new contract period beginning in October of 2001. At the time 

contracts were being signed, Bonneville power was expected to be very competitive relative to 

the market. Unfortunately, the timing was such that Bonneville was left with very little time to 

secure the necessary resources. Bonneville was forced to go to the market just when market 

prices were climbing to unprecedented levels. The high cost of the resources secured during that 

period have been a major contributor to the recent increases in Bonneville rates.

The reverse has also been true. When contracts are up for renewal, customers are free to not 

place load on Bonneville. In the mid-1990’s, customers petitioned Bonneville to be allowed to 

diversify their power supplies, i.e. purchase cheaper power on the market, even though there 

 

6

 Net requirements are the difference between the customer’s load and the capability of the customer’s own resources dedicated to their load. 

7

 Bonneville may have precluded itself from implementing tiered rates under the current contracts.
7

were several years left on their contracts. Although Bonneville could have tried to hold the 

customers to their contracts, it allowed them to diversify. The customers were required to pay an 

exit fee. While that may have been a good business decision for Bonneville in terms of its 

relationship with its customers, the decision to allow customers out of their contracts contributed 

to a period of financial instability for Bonneville.

Certainly all of Bonneville’s financial vulnerabilities cannot be attributed to its asymmetric 

obligations with respect to its public customers. But an important question for the future is 

whether Bonneville can continue to accommodate these risks as it has in the past and also 

preserve the long-term benefits of the federal system for the Northwest. 

Residential and Small Farm Customers of Investor Owned Utilities

One of the major reasons for the Northwest Power Act was to address the inequity of customers 

of publicly owned utilities in the region having access to low cost federal power while customers 

of the region’s investor-owned utilities did not. The remedy included in the Northwest Power 

Act is the so-called exchange provision of Title 16, Chapter 12, Section 839 c (c). Under these 

provisions, any Northwest utility, public or private, may sell power equivalent to the 

requirements of the utility’s residential and small farm load to Bonneville at the utility’s average 

system cost and purchase from Bonneville the same amount of power at Bonneville’s average 

system cost.8 Practically speaking, this is purely a financial transaction, with the exchanging 

utility receiving a payment equivalent to the difference between the utility’s average system cost 

and Bonneville’s, multiplied by the amount of power involved. The Act requires that this 

payment flow directly through to reduce the rates of the utility’s residential and small farm 

customers. 

Under this approach, if a utility’s average system cost were greater than Bonneville’s it could 

receive a payment. However, those with lower system costs would not receive payment. Several 

utilities have not received exchange benefits for this reason. Moreover, there is a rate test 

provision that is intended to ensure that Bonneville’s public agency customers do not pay more 

for power than they would have absent the Act. (Title 16, Chapter 12, Section 839 e (b)). The 

rate test, in effect, makes assumptions on what the world would have been like absent the Power 

Act, and Bonneville calculates what rates would have been under these assumptions. If rates are 

higher with the exchange, the exchange rate is capped at the lower rate.

Unfortunately, the exchange has been a constant source of dispute within the region. The 

methodologies for calculating the exchanging utilities’ average system costs and the rate test are 

established by Bonneville. Investor-owned utilities and their regulators have argued that 

Bonneville has manipulated these calculations to minimize the benefits their residential 

customers receive. Publicly owned utilities have argued that the exchange costs have been far 

too high and criticized the assumptions used in the rate test calculations.

When the current contracts were being negotiated, many in the region, including the investorowned utilities, state regulators and the Council, argued that rather than continue the exchange, 

Bonneville should negotiate an actual sale of power to the investor-owned utilities (IOUs). The 

 

8

 While publicly owned utilities are eligible to participate in the exchange, most of the benefits have flowed through to the residential and small 

farm customers of investor-owned utilities. 
8

rationale was that this would reduce controversy and would increase regional political support 

for Bonneville. Ultimately, Bonneville decided it could offer IOUs the equivalent of 1,800 

average megawatts of power for the 2002-2006 period, of which 1,000 would be in the form of 

an actual sale of power with the remainder in the form of either power or cash equivalent at 

Bonneville’s discretion. For the 2007-2011 period, the total was increased to 2,200 average 

megawatts. This compares to about 4,400 average megawatts of actual IOU residential and 

small farm load and about 1,800 average megawatts of IOU load that had actually been in the 

exchange program in the early 1990s. 

At the time, Bonneville believed this could be accomplished without an adverse effect on its 

rates. This assumption was challenged in court by publicly owned utilities. The price run-up in 

the Western electricity market quickly drove up the cost of providing power for the residential 

and small farm loads of the IOUs. Bonneville bought out part of the obligation, but certainly at a 

greater cost than planned. The IOUs, state regulatory commissions, and publicly owned utilities 

are, as of this writing, still trying to negotiate a settlement of the legal challenge for the 2007-

2011 period. 

The issue is not whether Bonneville should provide benefits for the residential and small farm 

loads of the IOUs. That’s the law, and most would agree that achieving equity in access to the 

benefits of the federal system is an appropriate goal. The question is how? Can the system that 

was set up in the Power Act be made to work in a way that is satisfactory to all participants? Or 

is there an alternative that is equitable, transparent and easy to understand and that does not 

expose Bonneville to extreme volatility in its costs?

Direct Service Industries

The direct service industries (DSIs) are primarily aluminum smelters. From 1981 through 2001, 

the DSIs had an undisputed right to Bonneville service. The Northwest Power Act authorized 

Bonneville to sell power to the DSIs and required that they offer initial 20-year contracts. Post 

2001, it would appear that Bonneville could offer DSIs contracts, but it is not legally required to 

do so. 

Most of the aluminum plants in the Northwest are older and less efficient than many competitors 

in the world aluminum market. This means they are extremely sensitive to the world price for 

aluminum and the price of electricity. In the 1980s, Bonneville instituted a variable rate that was 

tied to world aluminum prices. Bonneville’s DSI rate decreased when world aluminum prices 

fell below a low threshold and increased when aluminum prices rose above a high threshold. 

One interpretation was that this was an effort to bring greater stability to aluminum industry 

loads and Bonneville revenues. Others have referred to this as a subsidy to the industry. In any 

case, Bonneville assumed a significant amount of the risk involved in the direct service 

industries’ businesses. In recent years, the advent of new smelting capacity in other parts of the 

world and increases in Northwest electricity prices have resulted in most of the Northwest 

smelting capacity essentially being “swing” plants -- economic to operate only when aluminum 

prices are relatively high and electricity prices are relatively low.

With the expansion of the competitive wholesale power market in the mid-1990s and the low 

market prices of that period, many DSIs lobbied Bonneville to be released from their contracts so 
9

that they could take load off of Bonneville. Bonneville responded with a special deal that 

reduced DSI rates and gave the DSIs access to the transmission system and protection against 

stranded costs in return for continuing to purchase power from Bonneville until the end of the 

contract. Although the Secretary of Energy at the time initially tried to stop this deal, political 

support for the DSIs caused the Secretary to back down. 

With the approach of the expiration of those initial contracts in 2001, most believed that 

Bonneville was not required to sell to the DSIs after 2001, although it is authorized to do so. 

However, aluminum smelters are important to many local economies around the Northwest, and, 

as noted earlier, wield considerable influence. In addition, there are some possible benefits from 

having DSI load on the system. When operating, they are large loads that can be dropped almost 

instantaneously for short periods if necessary to maintain power system stability. They can 

provide a nighttime load to help maintain minimum flows on the river. And their load can be 

bought out for extended periods if necessary to deal with a hydropower-related energy shortage. 

With some ingenuity, DSI operations might be able to be curtailed for periods of a few hours a 

day to allow Bonneville to take advantage of high market prices for power. 

The current DSI contracts, which began in October of 2001, amount to about 1,425 average 

megawatts, about half of the potential DSI load in the region. These contracts are “take or pay” 

contracts, meaning that the DSIs must either take the power or pay liquidated damages -- the 

difference between what Bonneville would have received had the DSIs taken the power and what 

they did receive selling the power on the market. With the run up in market prices in 2000-01, 

Bonneville bought out as much of the DSI load as the DSIs would sell for a period of up to two 

years. The cost of the buyout was reasonable compared to the market price of power but a great 

deal more than no purchase at all. 

Today, most pot lines are idle, and at least two companies have declared bankruptcy. There are, 

however, DSIs that consider access to federal power at a melded rate essential to being able to 

operate after 2006. The pressures associated with importance of the DSIs to local Northwest 

economies and the resulting political influence the DSIs can wield cannot be discounted. 

However, the question going forward has to be whether some DSIs can be served in a way that 

helps minimize Bonneville’s financial risk and vulnerability, not increase them, while not 

placing undue costs on other Bonneville customers. 

Prescriptions

Over the years, several remedies have been prescribed for the problems discussed here. They 

include the 1996 Comprehensive Review of the Northwest Energy System, its follow-on Cost 

Review in 1988, the Joint Customer Proposal of 2002 and the Regional Dialogue that ensued. 

The prescriptions, the process by which they were developed and what happened as a result are 

described below.
10

The Comprehensive Review

The Comprehensive Review of the Northwest Energy System was initiated at the request of the 

four Northwest Governors.9 The Review steering committee included 20 members representing 

the electricity industry, government, regulators, other energy industries, and the environmental 

community. While Bonneville was not a member per se, a high-ranking executive served on the 

steering committee on an ex officio basis. The review committee worked for 11 months and held 

numerous public meetings. The Council staffed the Review, and both current and past-Council 

members were on the steering committee.

In its broadest sense, the Review was a response to the restructuring of the electricity industry 

that was under consideration at the time. However, its focus was primarily on the role of the 

Bonneville Power Administration. At the time, the West Coast was experiencing excess 

generating capacity and low natural gas prices. As a consequence, the market price of electricity 

was low and customers, both publicly owned utilities and DSIs, were clamoring to be allowed to 

diversify their power supply -- that is, buy more power on the market and less from Bonneville. 

This raised the specter of Bonneville experiencing stranded costs and being unable to make its 

Treasury payments in full. 

The Review stated the problem as follows:

“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 reduce its costs so that it can compete in 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 paying 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?”10

The steering committee’s goals for federal power marketing were 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-

 

9

 Comprehensive Review of the Northwest Energy System -- Final Report: Toward a Competitive Electric Power Industry for the 21st Century, 

Comprehensive Review Document CR 96-26, December, 1996. http://www.nwcouncil.org/library/1996/cr96-26.htm

10 Ibid. page 1. 
11

exempt status of Bonneville’s third-party debt; and 3) retain the long-term benefits of the system 

for the region. 11 

The Comprehensive Review’s key recommendations were:

• Bonneville’s power should be sold under long-term (20 year) “subscription” contracts, at 

cost. Shorter-term contracts would include an option fee for the right to extend their 

contracts.

• The priority order for subscription would be implemented in a sequential multiphase 

process. Publicly owned utilities would get first priority; direct service industries and 

representatives of residential and small farm customers of investor-owned utilities would 

get second priority; other regional customers, such as representatives of investor-owned 

utility commercial and industrial customers, would get next priority; and non-regional 

customers would get last priority. 

o In the event there is oversubscription, preference would be given to longer-term 

contracts. 

o Public utilities would be limited to the highest contractual entitlements of the two 

highest consecutive years between 1997 and 2000 with some additional power 

reserved for the load growth of small full-requirements utilities

o Each investor-owned utility customer subscription would be limited by the 

average total actual regional exchange load of its residential and small farm 

customers, again, in the two highest consecutive years between 1997 and 2001. 

o Each DSI would be limited by the average load in the two highest consecutive 

years between 1997 and 2001. 

• Bonneville would not acquire resources to serve its customers’ load growth 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: 1) 

supplement monthly firm hydro energy in meeting current firm loads, and 2) store water 

for flow augmentation to help rebuild fish populations. 

• A Customer Advisory Committee would be established that would consist mainly of 

subscribers, but also would include representatives of other interests. The committee 

would review Bonneville’s budget requests, overall capital budgeting levels and 

operating cost levels, rate setting, key marketing issues, and provide input into the powerrelated capital and operating cost decisions of the Corps of Engineers and the Bureau of 

Reclamation. It was also proposed that the contracts contain ability for subscribers to call 

for binding arbitration on specific power cost-related items that do not affect 

implementation of fish recovery measures.

The Committee also recommended that the Governors of Idaho, Montana, Oregon and 

Washington appoint a transition board to oversee implementation of these and other 

recommendations. In particular, the board should periodically determine whether the 

subscription process is making adequate progress or whether another approach is necessary.

 

11 Ibid. p. 10
12

The Cost Review

Following on the heels of the Comprehensive Review, in 1997 the Governors asked the Council 

to establish a “cost-control forum” to assist Bonneville in controlling the costs it recovers 

through rates. This was in preparation for the subscription process for the post-2001 period.12 

The actual subscription process was scheduled to begin in August of 1998. To accomplish the 

Cost Review, the Council recruited a “Management Committee” composed of 11 members. It 

was composed of four Council members, two Bonneville executives and five “outside” experts in 

management and cost control. The chairman of the Management Committee had also been the 

chairman of the Comprehensive Review Steering Committee. The principles from the 

Comprehensive Review that guided the Cost Review were:

• Market the power products of the federal system for relatively long terms (five years or 

more) to Northwest customers at cost-based rates through a subscription system. This 

recommendation is central to achieving the primary goal of the Comprehensive Review.

• Return Bonneville to its historic role of marketing and transmitting power produced by 

the FCRPS, rather than becoming an aggressive marketer of power products and services 

in the competitive marketplace;

• End Bonneville's responsibility to acquire resources to meet the load growth of 

customers, except on a bilateral basis where the customer accepts the risk and financial 

obligations associated with such acquisitions;

• Limit Bonneville's financial support of conservation acquisition to current contractual 

obligations and certain market development activities, provided they are self-sustaining 

by 1999. Also limit support for conservation market transformation in proportion to the 

share of regional firm loads served by Bonneville;

• Define Bonneville's responsibility for renewable resource development (beyond current 

wind and geothermal pilot projects) to limited research and development support, and to 

renewable resource purchases on the behalf of, and funded by, customer utilities; and

• Require Bonneville's transmission rates, terms and conditions to be designed and 

implemented in a manner that is comparable to those developed by investor-owned 

utilities (IOU) subject to Federal Energy Regulatory Commission (FERC) regulation.

The work of the Cost Review Management Committee was driven by the objective of achieving 

a high level of long-term Northwest subscription. The Committee believed that Bonneville's 

wholesale customers were facing a period of unprecedented uncertainty and risk. There were 

new suppliers and increased price competition in the marketplace. With the onset of retail 

competition, utilities were uncertain of their future loads. It was the Management Committee's 

view that these utilities were unlikely to buy power from Bonneville on a long-term basis unless 

they perceived Bonneville's price to be very low relative to these risks. Thus, the Management 

Committee believed that the key to a high level of long-term subscription was to reduce the costs 

as much as possible, consistent with the Comprehensive Review and sound business practices. 

 

12

 Cost Review of the Federal Columbia River Power System -- Management Committee Recommendations, Document CR 98-2, March 10, 

1998. http://www.nwcouncil.org/library/1998/cr98-2.htm
13

This, it was thought, should enable Bonneville to price its subscription products well below 

current market price expectations. Bonneville was working toward a cost structure that would 

allow it to compete successfully in a 2-cent-per-kilowatt-hour market.

The Management Committee challenged Bonneville and other agencies of the power system 

(U.S. Army Corps of Engineers (Corps), the Bureau of Reclamation (Bureau), and the 

Washington Public Power Supply System, now known as Energy Northwest) to beat that goal by 

a substantial margin. The Management Committee believed that the goal of pricing power well 

below market expectations would enable Bonneville to return to its roots as envisioned by the 

Comprehensive Review. Those roots are a focus on Bonneville's core missions of marketing and 

transmitting the firm power output of the FCRPS for relatively long terms to regional customers, 

and of meeting its environmental responsibilities. That is a role that the Committee believed was 

sustainable, both competitively and politically. While Bonneville would continue short-term 

marketing of nonfirm power, the emphasis on long-term firm contracts would allow Bonneville 

to reduce staff and expenses associated with many marketing and related support activities. In 

this environment, Bonneville would not be engaged in acquiring additional power resources to 

meet the load growth of customers. Nor would it have a large responsibility for the development 

of conservation and renewable resources. Staffing and other expenses related to these activities 

could be reduced. These directions all are consistent with the recommendations of the 

Comprehensive Review of the Northwest Energy System.

What Happened?

When the Final Report of the Comprehensive Review was completed and delivered to the 

Governors in December 1996, 19 of the 20 members signed the document. The 20th did not sign 

because he believed that the fish and wildlife considerations in the report were not adequate. 

However, the fact that almost all signed the document did not mean that each individual or the 

organizations they represented was committed to the implementation of each element of the 

recommendations. As the negotiation of the subscription contracts proceeded through the late 

1990s, there was a growing expectation of increased wholesale market prices while goal of “Two 

Cents in 2000” for Bonneville was widely touted. As a consequence, the contracts moved farther 

and farther away from the blueprint of the Comprehensive Review. 

The Governors established the Transition Board called for in the Review. However, with the 

exception of periodic reports, the Transmission Board generally left the development of the 

subscription contracts to Bonneville and the customers. The rationale was that because 

subscription was a contractual relationship between Bonneville and its customers, Bonneville 

should take the lead. In addition, the resources available to the Transition Board were not 

adequate to allow direct participation in the detail of all the negotiations. Moreover, the 

dominant concern of the day was more about whether or not Bonneville would secure enough 

contracts to cover its costs than the form of the contracts. The fact that growing numbers of 

customers were interested in longer-term contracts (although 10 years in duration rather than 20) 

probably served to encourage the Transition Board to “declare victory”. The Transition Board 

instead focused much of its effort on the broader policy question of the degree to which 

Bonneville’s transmission should be subject to the same regulation as that of most other 

transmission owners.
14

The cost target of the Cost Review was incorporated into Bonneville’s rate case for the 2002-

2006 period. However, the underlying assumptions about a more limited Bonneville role were 

not reflected in Bonneville’s organization. 

With the prospect of cheap Bonneville power (2 cents in 2000) and the expectation of increasing 

market prices, many customers who had taken load off of Bonneville in the mid-1990s wanted 

back on. And most wanted all their loads served as they had always been served, at a single, 

melded rate. The exceptions were a number of customers who opted for a new product, the 

“slice” product. With this product, customers agreed to purchase a percentage of the output of 

the system, whatever that might be, and accept the benefits and risks associated with that output. 

In a good water year, they would receive a percentage of the firm and non-firm power produced 

by the system and would be responsible for using or marketing that power; in a bad water year, 

they would receive very little non-firm power and might have to purchase additional power to 

meet their obligations. The slice product amounts to about 1,600 average megawatts out of 

6,600 average megawatts of public load. 

But Bonneville still had the responsibility for managing the variability and risk of the remainder 

of the federal system. In addition, as was noted earlier, the decision was made to serve 1,425 

average megawatts of DSI load and to provide 1,000 average megawatts of actual power to the 

region’s investor owned utilities as part of the benefit for the residential and small farm 

customers of the IOUs. The net effect, as has been well documented by Bonneville itself, is that 

Bonneville was faced with the necessity of “augmenting” its system by approximately 3,300 

average megawatts to serve the loads it was committed to serving during the October 2002 

through September, 2006 period.13 Moreover the timing of the signing of the new subscription 

contracts was such that Bonneville had little more than a year to contract for many of the 

necessary resources. Unfortunately, this coincided with the Western electricity crisis. 

Bonneville was in the market to augment the system at a time when electricity prices were at 

unprecedented highs. Bonneville attributes $3.9 billion of the higher costs it is experiencing 

during the 2002-2006 period to the costs of augmenting the system.14 

To take this a step farther, one could argue that the uncertainty regarding who was going to be 

serving those 3,300 megawatts was a contributing factor to the Western electricity crisis. Had 

the recommendations of the Comprehensive Review been followed more closely, there would 

have been much less uncertainty regarding responsibility for resource development and, 

perhaps, utilities would have committed to development of new resources that could have at least 

partially mitigated the price run-up of 2000-2001. Would this have prevented the crisis? No. 

Would it have lessened it? Yes, to some extent. 

The Joint Customer Proposal

In mid-2002, a group of Bonneville customers representing a majority of publicly owned utilities 

and all of the investor-owned utilities in the region unveiled an unprecedented proposal to 

change the future role of Bonneville in power supply. What was unprecedented about this 

 

13 What Led to the Current BPA Financial Crisis? A BPA Report to the Region, AKA “The Lessons Learned” report, Bonneville Power 

Administration, April 2003. p 10. 

14 Ibid
15

proposal was not so much its substance, which was in many ways reflective of the 

recommendations of the Comprehensive Review, but the fact that such a wide spectrum of utility 

interests had coalesced around it. In a narrow sense, this proposal was the product of an effort to 

settle the publicly owned utilities’ legal challenge to the benefits to be provided to the residential 

and small farm customers of the IOUs that were part of the 2001 contracts. In a larger sense, 

however, this was a response to the frustrations and concerns all had experienced with 

Bonneville, and, in particular the aftermath of the 2000-2001 Western electricity crisis.

The objectives of the Joint Customers were stated as follows:15

1. To create a common interest between Bonneville’s regional preference utility and 

investor-owned utility customers by allocating to such customers equitable, secure and 

long-term benefits of the federal power system.

2. To expose all Bonneville customers to the same risks and benefits of changes to the costs 

and output of the federal system.

3. To reduce Bonneville’s presence in the wholesale power market as a buyer and seller of 

power.

4. To enhance the ability of BPA to make its Treasury payments in full and on time across a 

broad range of possible futures.

5. To allocate the costs of procuring power for future load growth to the serving utility.

6. To reduce Bonneville’s need to augment the federal system and reliance on market 

revenues from the sale of secondary energy by shifting to utilities through expanded use 

of the “slice” product the obligation to procure resources to serve their load growth and 

the marketing of secondary energy.

7. To settle outstanding litigation in a manner that is fair to all parties and that avoids future 

litigation over the allocation of federal system benefits.

8. To implement the foregoing consistent with existing statutes without federal legislation.

Key elements of the proposal, in much abbreviated form, were:16

1. New 20-year contracts for power supply or financial benefits for regional utility 

customers. Power supply contracts would be on a take or pay basis.

2. Allocation of the net capability of the federal system to preference agencies based on 

their projected 2007 net requirements. Power would be allocated first to those customers 

that elect to take the “slice” service.17 with the remainder going to those who elect to take 

requirements service.18 

3. Slice customers would be responsible for all the costs associated with shaping their slice 

to meet loads and any load growth.

 

15 Investor-Owned Utility/Preference Utility Proposal For The Future Role Of The Bonneville Power Administration, October 29, 2002 Draft, p 1

16 Ibid, pages 2-22.

17 The slice customer would be contracting for a percentage of the output of the system and would be responsible for managing the variability in 

that output. Slice customers also would pay the costs of producing that output and would not pay any of the costs associated with providing 

requirements service.

18 In requirements service, Bonneville is obligated to serve the customers’ net requirements, including acquiring additional resources to do so, if 

necessary.
16

4. It was anticipated that there would be sufficient power available to serve the requirements 

customers’ initial loads with some power left over. Bonneville would manage the excess, 

with the costs and benefits going to the requirements custome rs. When additional 

resources were required to serve the requirements customers, the costs of augmenting the 

system were to go to those customers.

5. Investor-owned utilities were to receive a financial benefit for their residential and smallfarm customers in settlement of their statutory rights to residential exchange benefits and 

their rights to purchase their net requirements from Bonneville. The financial benefit was 

to be calculated as the difference between the cost of power from a hypothetical 

combined cycle combustion turbine and the cost of Bonneville power. 

6. The loads of newly formed public utilities up to 75 average megawatts would be served 

at a melded rate that includes Bonneville’s costs in serving its slice and requirements 

customers. Load above 75 average megawatts would be served at the cost Bonneville 

incurs in acquiring the necessary resources. 

7. Up to 650 average megawatts of DSI load could be served on a take-or-pay basis at a 

melded rate (600 average megawatts of smelter load, 100 megawatts per smelter, and 50 

average megawatts of non-smelter load) with the costs of the power required to serve this 

load melded into Bonneville’s costs. 

8. Conservation targets would be established through the Council’s periodic power plans. 

Bonneville would budget for the conservation associated with its loads, including the 

IOU load used in determining the benefits for residential and small-farm customers. 

Conservation would be implemented by utilities using funding from Bonneville under the 

Conservation and Renewables Discount program. A percentage of that would be used for 

funding renewables. Bonneville would administer the program, perform periodic audits 

and would be able to charge utilities that do not do their share and use those funds to 

implement conservation and renewables. Bonneville would continue to fund low-income 

weatherization, market transformation, and research, demonstration and development. 

9. A requirement for some mechanism to ensure that the commitment made by the 

customers to Bonneville’s financial security under the new, long-term contracts is 

matched by an enforceable ability to ensure that rates the customers pay are based only 

on necessary and legitimate costs. 

10. Fish and wildlife costs would continue to be legitimate costs of the system to be paid by 

the customers. 

The Regional Dialog

In response to the Joint Customer Proposal (JCP), the Council and Bonneville held a number of 

public meetings throughout the region during the early fall of 2002. This process was dubbed 

the Regional Dialogue. The purpose of these meeting was to get public input on the JCP and 

alternatives to the JCP to define the future role of Bonneville in power supply. After the 

conclusion of these meetings, the Council reviewed the oral and written testimony received and 

developed its own set of recommendations to Bonneville.19 Bonneville was to use these 

 

19 Northwest Power Planning Council Recommendations on the Future Role of Bonneville in Power Supply, Council Document 2002-19, 

December 17, 2002. http://www.nwcouncil.org/library/2002/2002-19.htm
17

recommendations and the other information received during the Regional Dialogue to develop its 

own proposal that would be noticed in the Federal Register and be the subject public hearings. 

The Bonneville administrator’s decision would then establish policy for the development of new 

contracts. 

In general, the Council’s recommendations endorsed the direction of the JCP with some changes. 

The Council identified a number of problems that Bonneville faces. The Council viewed these 

problems as the consequence of a mismatch between how Bonneville is called upon to operate 

and the realities of the evolving electricity system. The problems include:

• Periodic lack of clarity regarding load-serving responsibility and the uncertainty that 

creates for the development of new resources;

• Lack of clear economic signals to many parties in the region regarding the true costs of 

new power supplies and the value of alternatives;

• Exposure of Bonneville to high electricity market risks resulting from the periodic ability 

of customers to place load on or take load off of Bonneville; 

• A perception of inequality in the distribution of the benefits of the federal power system 

within the region.

• The financial risk to the U.S. Treasury and the resulting political risk to the long-term 

interests of the region if at some time Bonneville is unable to absorb the risks of uncertain 

loads, a highly variable hydroelectric system and a potentially volatile wholesale market.

The Council’s recommendations can be summarized as follows:

• Support for 20-year contracts because they will provide contractual protection from the 

efforts of those outside the Northwest to appropriate the benefits of the federal Columbia 

River system; demonstrate regional commitment to the federal system and buffer 

Bonneville and thereby the Treasury from the risks of losing or gaining loads with shorter 

contracts. 

• Support offering the slice product and expanded use of that product. This product meets 

the needs of some customers; it results in greater diversity in the electricity market; it 

lessens Bonneville’s impact on the market and its exposure to market and hydropower 

risk; it improves the liquidity of the power market; and, it provides clarity with respect to 

responsibility for meeting load growth and clear economic signals regarding the cost of 

serving load growth.

• Support for Bonneville offering a requirements product, as it meets the needs of many 

customers in the region. However, the Council is concerned about the lack of clarity 

regarding responsibility for meeting load growth once any surplus federal power 

resources have been absorbed. The Council recommended that Bonneville clearly 

indicate that the load growth of customers receiving this product will be served by tiered 

rates or the equivalent that charges the cost of the new resources needed to meet load 

growth. To do otherwise would perpetuate conflict between growing and non-growing 

utilities and not send appropriate price signals to the customers.

• Support for Bonneville providing a block power product independent of the slice product. 

However, the Council believes that the block power product should be conditioned as 
18

described in the Joint Customer Proposal – that the costs Bonneville incurs in shaping 

power to the blocks be passed on to the block customer and that the block product not 

contain a load growth element. This is essential to aligning benefits and risks, providing 

clarity with regard to load responsibility and clear economic signals regarding the cost of 

load growth.

• Support for settling the issue of the level of benefits provided the residential and small 

farm customers of investor-owned utilities. To do so will reduce intra-regional 

animosities and give a broader cross-section of the region direct involvement in the well 

being of the federal system. While the Council did not endorse any particular formula, 

the Council supported the idea of a transparent approach that was not subject to 

manipulation. 

• The Council supported limited service to DSIs at Bonneville’s industrial rate in an 

amount not to exceed 600 megawatts. It recommended that contracts allow Bonneville to 

capture benefits of DSI load interruptibility and provision of reserves to offset the cost of 

DSI service to other customers. The Council also recommended contract provisions to 

help maintain aluminum plant operation during periods of low aluminum prices and 

adequate electricity supplies, provided this can be accomplished without imposing 

additional costs on other customers. The smelters were encouraged reduce dependence 

on Bonneville power in the long-term.

• The Council insisted that Bonneville’s role in power supply include a realistic approach 

to ensuring that the region develops cost-effective conservation. The thrust of the 

customer proposal that makes more customers responsible for meeting their load growth 

is a major step in the right direction. It is, however, not sufficient given the disincentives 

to utility investment in conservation, even though it is a lower-cost resource. 

The Council supported establishment of Bonneville’s conservation budgets based on the 

Council’s Northwest Power Plan and load served by Bonneville. However, the Council 

also asserted that Bonneville has the obligation and authority to establish conservation 

targets and to develop mechanisms to ensure conservation is captured for the entire load 

of its preference customers, not just the portion served by Bonneville and that Bonneville 

should use its authorities to the fullest extent possible to ensure the region attains 

conservation goals established for the entire retail load of customers that can place load 

on Bonneville. The Council supported the use of a mechanism like the Conservation and 

Renewables Discount to support local implementation in concept. However, the existing 

mechanism must be redesigned to ensure cost-effective acquisitions, encourage best 

practices and minimize the cost of acquisition consistent with achieving the savings. The 

mechanism also must limit expenditures on activities that do not clearly support the 

development of tangible savings and ensure accountability. 

The Council asserted that a broader range of conservation activities should be carried out 

by Bonneville at the regional level than is envisioned in the customer proposal. This is 

because there are a number of activities that can be carried out more effectively if they 

are approached on a coordinated regional basis with local implementation.

• The Council emphasized the important role that Bonneville has played in research, 

development and demonstration for renewables and recommended a continued role for 

Bonneville in that area. In general, the Council supported some level of acquisition of 
19

renewable resources at costs higher than the market price of electricity where such 

acquisition is justified by the additional environmental and risk mitigation values that 

renewables can bring to the power system. The Council is currently developing its Fifth 

Power Plan. The Council’s plan should guide renewable resource development in the 

region.

• The Council supported the joint customers’ intent that the combination of 

slice/block/requirements operations not affect the determination and implementation of 

Bonneville’s fish and wildlife obligations. Under the proposal, Bonneville, the Corps of 

Engineers and the Bureau of Reclamation will continue to meet the federal government’s 

Indian trust and treaty responsibilities. Furthermore, greater clarity with respect to load 

responsibility should result in more timely development of new resources and reduce the 

potential periods of resource inadequacy. This should reduce the frequency with which 

the region would be forced to compromise fish operations on the hydropower system to 

maintain power supply adequacy.

Where are we now? 

Bonneville’s process for developing a response to the input received during the regional dialogue 

was essentially put on hold while Bonneville and its customers wrestled with proposed rate 

adjustments. During tha t time, some things appear to have changed. Many public customers 

may no longer be willing to turn in their existing contracts for new contracts that begin in 

October 2006. With the exception of the DSI contracts and about 600 average megawatts of 

public utility load, most contracts do not expire until October 2011. Under a normal timeframe, 

this would mean that the negotiation of new contracts for most of Bonneville’s loads would be 

put off until 2008 or 2009. This would mean perpetuating the uncertainty about Bonneville’s 

future role in power until well into the period in which decisions about resource development 

may have to be made. In addition, the discussions between public customers and the investorowned utilities appear to have shifted away from the search for a long-term solution to the 

question of the benefits to the residential and small farm customers of the IOUs to a shorter-term 

solution for the 2006 – 2001 period. On a more positive note, Bonneville and its public utility 

customers have made some progress toward providing a greater measure of openness regarding 

Bonneville’s costs.

The region’s Governors have recognized that perpetuating uncertainty regarding Bonneville’s 

role in power supply risks the adequacy and economy of the region’s power supply. At their 

June meeting, the Governors made the following recommendations:

“We stress the importance of achieving a role for BPA that is sustainable for the long term. The 

Council’s recommendations provide direction and include: 

1) Long-term contracts to demonstrate a continuing commitment to meet the costs of the 

federal power system and related stewardship obligations. Committing to long-term 

contracts will help preserve these benefits for the Pacific Northwest; 

2) A limited role for BPA in serving the load growth of its customers. In most cases when 

BPA accepts the obligation to meet load growth, it should be on a bilateral basis with 

customers bearing the full cost of resources acquired to meet their needs; 

3) Fulfillment of existing fish and wildlife obligations; and 
20

4) Pursuit by BPA of regionwide conservation and renewable resource opportunities. 

Until we accomplish these objectives construction of resources to meet new load growth will be 

delayed, placing the region at risk of another electricity crisis.”20

The Governors asked the Council and Bonneville to reinitiate the Regional Dialogue. A number 

of discussions with representatives of customers, regulators, industry, and environmental 

interests have been held. The major conclusion drawn from these discussions is that while some 

things may have changed and need to be re-examined, many of the basic elements of the original 

Joint Customer Proposal still have regional support and could form the foundation for moving 

forward.

Proposed Council Principles for the Future Role of 

Bonneville in Power Supply

The Federal Columbia River Power System remains important to the region’s economy. It can 

continue as such only if the Bonneville Power Administration can successfully navigate the risks 

and uncertainties, both economic and political, that have confronted the agency for the past few 

years and will continue to face the agency in the future. Many of these risks and uncertainties 

are linked to Bonneville’s role in power supply and how it chooses to implement that role. In 

addition, the uncertainty regarding Bonneville’s role is an impediment to the timely development 

of power and conservation resources in the region. The Council believes the region needs to 

move forward with the definition of Bonneville’s future role now, rather than waiting until the 

expiration of existing contracts is close at hand. The following principles or characteristics are 

proposed a guide. These principles reflect 1) the Council’s understanding of circumstances that 

may have changed in the last year; 2) the perspectives expressed during the recent discussions; 

and 3) the Council’s review of the original Joint Customer Proposal and its subsequent 

December 2002 recommendations on the future role of Bonneville.

Proposed Council Principles for the Future Role of Bonneville

• The goal should be long-term contracts (20 years) both to protect the system from 

interventions from outside the region and to reduce uncertainty for both the customers 

and Bonneville. 

• Bonneville’s primary role, in addition to transmission, should be managing the operation 

and marketing the output of the Federal Columbia River Power System. The FCRPS is a 

multipurpose public resource and Bonneville has a record of real expertise in its 

operation and marketing. 

• Bonneville’s role in providing power beyond the capability of the federal base system 

should be limited to bi-lateral contracts or rate mechanisms that align the benefits and 

costs. This would limit Bonneville’s exposure to market risks and reduce the uncertainty 

 

20 Recommendations of the governors of Idaho, Montana, Oregon and Washington for protecting and restoring Columbia 

River fish and wildlife and preserving the benefits of the Columbia River power system, June, 2003, p 12. 

http://www.nwcouncil.org/library/2003/4governors.pdf
21

regarding who will be acquiring additional resources thereby reducing an impediment to 

resource development.

• Bonneville’s role should be limited contractually. Although most customers’ contracts 

run through 2011, these changes need to be enacted as soon as possible so as to protect 

the regional resource from outside interference and clarify the outlook for resource 

development

• Customer agreement to long-term contracts will require at minimum that Bonneville: 1) 

provide customers and others greater openness regarding their costs, the factors driving 

those costs and the decisions affecting them BEFORE decisions are made; 2) implement 

cost-reducing process improvements; and 3) rebuild trust with the customers and others 

that Bonneville is a good business partner. 

• Revising Bonneville’s role in acquiring and pricing the output of additional resources will 

require an allocation of the federal base system resources and benefits. Any allocation 

method for the FBS should be equitable and consistent with federal law while creating a 

broad constituency for Bonneville. 

• A significant amount of the system should be offered as a “Slice” product . The slice 

product effectively distributes hydro risk and, by virtue of more diverse decision-making, 

should reduce the impact of hydro variability on the market. 

• Benefits should be provided for the residential and small farm customers of the region’s 

investor-owned utilities in a way which is judged to be equitable by the parties and that is 

clear and transparent and not subject to manipulation by any of the parties.

• The question of service to the DSI’s must be addressed. If power is made available to 

DSIs, the amount and term should be limited and contracts should be structured to allow 

Bonneville to capture benefits of DSI load interruptibility and provision of reserves. The 

smelters should be encouraged to reduce dependence on Bonneville power in the longterm.

• Any solution must contain a mechanism for ensuring continued regional development of 

cost-effective conservation, as determined through the Council’s plans. While limiting 

Bonneville’s role to develop new power supplies to bilateral arrangements with 

customers is a major step in the right direction, it is not sufficient to ensure the

development of cost-effective conservation given the disincentives to utility investment 

in conservation. Reliance on local implementation is appropriate so long as there is a 

focus on cost-effectiveness and accountability and a backup mechanism is included to 

ensure that conservation is implemented. A direct Bonneville role in implementation is 

appropriate where there are economies of scale or other benefits from Bonneville’s direct 

involvement. 

• Similarly, a mechanism is required for ensuring that cost-effective renewable and high 

efficiency resources are developed. In particular, the ability of the hydro system to 

support the development of intermittent renewable resources, through the flexibility of 

the hydro system, should not be unduly impaired. 

• Bonneville’s ability to implement its fish and wildlife obligations must not be impaired.
22

Questions for Public Comment

The Council is interested in public comment on the following:

1. Do you think the analysis of the problems and issues presented in the paper is accurate? 

If not, how is it inaccurate?

2. Do you agree that a more limited role for Bonneville in power supply as described in 

principles is appropriate? If not, why?

3. Do you think the question of Bonneville’s future role in power supply needs to be 

addressed in the near future? If not, why?

4. Do you think the principles or characteristics proposed by the Council are appropriate 

guidance for consideration of Bonneville’s future role? If not, why?

________________________________________

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