February 6, 2002 1

Issues for the Fifth Northwest Power Plan

February 6, 2002

Introduction

The Council is beginning development of its fifth power plan. As required by the 

Northwest Power Act, the Fifth Northwest Power Plan will incorporate 20-year forecasts 

of demand for electricity, assess resource strategies to meet those demands at the lowest 

cost to the region and make recommendations for implementing those strategies. The 

development of a new power plan also provides the Council with the opportunity and the 

responsibility to address important issues that can affect the achievement of the Act’s 

dual goals of an adequate, efficient, economic and reliable power supply and protection, 

mitigation and enhancement of the fish and wildlife resources of the Columbia River 

Basin. Through the process of developing the plan, the Council hopes to engage the 

region on these issues and influence their resolution in ways that are beneficial to the 

region. The purpose of this paper is to discuss the issues we intend to address in the plan 

and to seek public comment on them.

The Act requires a 20-year time frame, calling explicitly for 20-year forecasts of demands 

and of the resources required to meet those demands. While this time frame was largely 

a result of the long lead-time, highly capital-intensive resources and fully regulated 

electricity markets of the 1970s, there remain important longer-term issues affecting the 

objectives of the Northwest Regional Power Act. Given the relatively short-term focus of 

the current electricity market, the Council is one of the few organizations able to take a 

long-term perspective.

That said, the reality of much shorter lead-time, lower capital-cost resources and more 

competitive electricity markets leads to a shorter-term focus. This shorter-term focus 

cannot be ignored. Moreover, we believe there are a number of important issues that will 

have to be addressed over the next five to seven years. Consequently, we plan to focus 

much of our attention on the initial five to seven years of the 20-year, 2002 –2021 

planning horizon.

The experience of the past year and a half, with its extremely high and volatile prices, the 

threat of blackouts, and the need to resort to emergency hydropower operations suggests 

that electric ity markets in the West are not functioning as efficiently and effectively as 

most market participants would desire. While there are many factors that contributed to 

this situation, electricity market structure is a significant one. That structure might be 

termed a “mixed” market. By a mixed market, we mean that the wholesale and retail 

parts of the market are not directly connected for most consumers within the region, or 

for that matter, in the rest of the West. The wholesale power market is a loosely

regulated “competitive” market in which prices are determined through market 
February 6, 2002 2

transactions, and the development of new resources is largely undertaken by private 

developers responding to market signals. Those signals are typically a combination of 

spot market prices and the prices that can be negotiated for longer-term bilateral 

contracts. In the retail market, most customers are buying from regulated utilities, either 

regulated by state commissions or local governing bodies. Retail rates are generally 

established in rate proceedings that lag the wholesale market. Rate structures generally 

do not provide “real time” signals of the current value of power. While there are some 

retail customers who are directly exposed to market signals, they are, for the most part, 

larger customers, and this situation is by no means universal even for them. 

For many reasons, we think this general structure will persist for at least the next five to 

seven years. We think it is unlikely that states in the region will move farther down the 

road to retail competition beyond those steps already taken, and there is some possibility 

that some steps toward retail competition will be reversed. On the other hand, we think it 

is unlikely that there will be any significant reversal of national policy encouraging 

wholesale competition. As a practical matter, the important issue is not restructuring 

power markets in any overall sense. It is, we think, seeking improvements within this 

mixed market structure that will allow it to function more efficiently and effectively. We 

recognize that many utilities and others in the region feel they are fully occupied in 

dealing with the aftereffects of high power prices and other consequences of the recent 

electricity crisis. However, if we fail to address these issues over the next few years, the 

chances of a repeat of the power supply and price problems experienced over the last year 

are greatly increased. 

Addressing the problems of the current market structure would benefit the Council’s fish 

and wildlife responsibilities as well. As we saw this year, severe shortages in the 

electricity market can also affect the region’s ability to achieve its fish and wildlife 

mitigation goals.

In this paper, we describe some of the issues raised by the current market structure and 

other issues that we think should be addressed in the Fifth Northwest Conservation and 

Electric Power Plan. They include:

• Incentives for Development of Generation-- The current market structure 

appears to have failed to provide adequate and timely incentives for adding new 

capacity to ensure power supply adequacy and to moderate price volatility. The 

Council proposes to assess existing incentives and disincentives for development 

of new generation and examine options available to encourage development that 

will moderate potential supply-demand imbalances and price volatility. Options 

will be analyzed to determine their effect on prices, system cost, adequacy and 

reliability. If appropriate, the plan may recommend measures to address 

systematic problems or improve signals for market development. 

• Increasing the Price Responsiveness of Demand -- Most analyses of the 2000-

2001 electricity situation agree that the lack of a demand response to wholesale 

prices worsened supply problems and price volatility. The Council proposes to 
February 6, 2002 3

evaluate alternatives for increasing the price responsiveness of demand. The 

analysis would address the effects of various mechanisms on system cost, 

reliability and prices. If appropriate, the plan may make recommendations for 

implementing measures to improve the price responsiveness of demand.

• Sustaining Economically Efficient Investment in Efficiency -- Over the past 

several years, investment in energy efficiency has followed a “roller coaster”

pattern – investment at below cost-effective levels when market prices were low 

followed by “crash” programs when prices exploded. The Council proposes to 

assess the strengths and weaknesses of different approaches to achieving 

economically efficient levels of investment in energy efficiency in a more volatile 

electricity market and, if appropriate, suggest ways in which these programs 

might be improved.

• Information Requirements for Assessing Power Supply Adequacy and 

Market Performance -- The 2000-2001 electricity situation highlighted the need 

for timely information for assessing both power supply adequacy and reliability, 

and market performance. Some information that used to be readily available is 

now closely held. The Council proposes to evaluate the data needed to perform 

its planning and market assessment functions, and to investigate and make 

recommendations on how best to obtain such data if it is not currently available.

• Fish Operations and Power -- During the 2000-2001 electricity crisis, tradeoffs 

were made between hydro operations for fish and operations for power. These 

tradeoffs were important in maintaining an adequate power supply but came at 

some cost to the survival of juvenile salmon and steelhead. If many of the issues 

described above can be successfully resolved, the power system should be better 

able to provide the operations desired for fish even in low water years or times of 

financial crisis while the region also enjoys a more reliable power system. The 

Council’ s 2002 mainstem amendments to the Fish and Wildlife Program are 

intended to lead to river operations that provide for both fish recovery and 

enhancement and an adequate, efficient, economical and reliable power system. 

However, conflicts are likely to always exist. There remain incentives to deviate 

from prescribed fish operations when supplies are tight and prices soar. The 

Council proposes to investigate operational strategies and potential incentives to 

minimize impacts on fish recovery from deviations from prescribed fish 

operations and the options available to mitigate these impacts. 

• Transmission and an Adequate, Efficient, Economic and Reliable Power 

System – Transmission policy and planning have become even more critical to 

the goal of an adequate, efficient, economic and reliable power system since the 

restructuring of the electricity industry to achieve functional separation of 

transmission and generation. The issue is how the mix of independent power 

developers, transmission owners, load serving entities, and consumers make 

coherent decisions about what to build and where to build it in a vast 

interconnected system. How these decisions are made can have a significant 
February 6, 2002 4

effect on power system costs, reliability, and the environment. While many of the 

issues are being addressed in the RTO West process, it will be some time before 

the Regional Transmission Operation (RTO) is in place if ever. In the meantime, 

Bonneville and others will be making decisions about transmission policy and 

planning. Consequently, the Council proposes to address alternatives with respect 

transmission pricing, planning, and policy as they affect the Council’s mission of 

an adequate, efficient, economical and reliable power system. 

• Value of and Barriers to Resource Diversity -- The new generation that is 

under construction or in the development process in the region is heavily 

weighted toward natural gas-fueled combustion turbine technologies. Some 

observers have raised the concern that the Northwest and, even more so, the West 

Coast, is becoming overly dependent on natural gas and that the region should 

strive to increase the diversity of resources being added to the system. The 

Council proposes to assess the benefits of resource diversity and the potential 

barriers to increasing it. These include the issues associated with integrating 

intermittent resources into the system and pricing, transmission and distribution 

system issues raised by alternative resources and distributed resources. The plan 

will evaluate the prospects for achieving benefits from diversity, intermittent 

resources and distributed generation. We will attempt to identify barriers to the 

achievement of benefits and assess approaches to resolving the issues. 

• Future Role and Obligations of the Bonneville Power Administration -- The 

Bonneville Power Administration is legally obligated to serve the loads placed on 

it by public agencies at cost, even if it must acquire additional resources to do so. 

Many believe that in a competitive wholesale power market, this obligation 

exposes the Northwest to some risk of losing continued preferential access to the 

output of the Federal Columbia River Power System (FCRPS). In addition, it 

distorts the market for new resources both from the standpoint of Bonneville’s 

large presence in the market and the price signals sent to its customers. However, 

if Bonneville were unable to acquire additional resources, some means of 

allocating its existing resources among competing interests would have to be 

found. There are currently discussions ongoing among different customer groups 

that are focused on the question of allocation of existing Bonneville power in the 

post-2006 rate period and to some degree Bonneville’s role in resource 

acquisition. If these discussions bear fruit, the Council would analyze the 

proposal or proposals to develop the pros and cons with respect to resource 

development, power system adequacy, reliability, cost, market dynamics and the 

ability of the region to retain the benefits of the federal system. The purpose of 

this analysis would be to help the public and regional leaders reach decisions 

about the appropriateness of the proposals. In the absence of such proposals, the 

plan will evaluate alternative roles and practices for Bonneville and develop as 

fully as possible the pros and cons associated with the alternatives. 

• Global Climate Change Risks to the Power System -- A preponderance of 

scientific opinion asserts that the earth is warming and that this warming is largely 
February 6, 2002 5

the result of increased production of carbon dioxide and other greenhouse gasses 

due to human activities. Because of the widespread use of fossil fuels to produce 

electricity, the electric power industry is a principal contributor to the growing 

atmospheric concentration of carbon dioxide and will be affected by any 

initiatives to reduce carbon emissions. Furthermore, the production of electricity 

from hydropower, so important in the Northwest, may be affected by climate 

change if historical precipitation patterns change. The Council proposes to review 

the status of the global climate change issue, including the current understanding 

of possible effects on the Northwest hydropower system, the effects of possible 

greenhouse gas emissions control policies on the relative cost-effectiveness of 

resources available to the Northwest, and the value of strategies to address climate 

change impacts.

While these issues have been presented as discrete, many are clearly highly interrelated. 

The plan will analyze these interrelationships. Background on the issues and the 

Council’s proposed treatment of them is described in more detail in following sections.

Opportunities for Public Comment

The Council is interested in comment on this issue paper. This comment will help define 

the issues agenda addressed in the Fifth Power Plan. Specifically, the Council would 

appreciate comment on the following questions:

1. Are the issues described in this paper important to be addressed in the Fifth Power 

Plan? If not, why not?

2. Are the issues described accurately? If not, how should they be described?

3. Are the ways in which the Council proposes to address these issues appropriate? 

If not, how should they be addressed?

4. Are there other issues not included here that should be addressed in the Fifth 

Power Plan and, if so, what are they?

5. How should consideration of these issues be sequenced? Should some be 

addressed before others?

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

the close of business Friday, March 15, 2002. Public comments also will be accepted at 

the Council’s March 6, 2002, meeting in Eugene, 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 2002-01.
February 6, 2002 6

Adequate Incentives for Development of New 

Generation 

A competitive wholesale electricity market has a far different set of incentives and 

rewards for investing in new generation than did the regulated environment. An issue 

that has concerned the Council for some time is whether competitive wholesale markets 

as currently structured are likely to provide the level of power supply adequacy and 

reliability desired by most consumers. 

How is the Development Decision Currently Made?

Most, although not all, new generation is being developed by independent developers. Of 

a total of 6,679 megawatts developed between 1994 and 2003, 4,735 megawatts (71 

percent) is owned by independent generating companies. 1,629 megawatts (24 percent) 

is "conventional” investor- or publicly-owned utility generation. The remaining 315 

megawatts is industrial. Of the 13,000 megawatts that have been permitted or are 

currently in the permitting process, independent power producers sponsor 93 percent. 

Simplistically, the decision to build new generation on the part of an independent 

developer operating in a competitive market depends on a combination of the developers 

expectations about future spot market prices and the willingness of potential customers to 

enter into long-term power purchase contracts. If the combination of these factors is such 

that the developer believes investment criteria can be satisfied and financing obtained, the 

development will proceed. This calculation is fraught with risk under any circumstance. 

Slowdowns in the economy and milder than normal weather both pose risks to the 

developer. Here in the Northwest in particular, and, to a lesser extent, in the rest of the 

West, the risk is compounded by the uncertainty introduced by the hydroelectric system. 

The annual generation of the hydroelectric system can be almost plus or minus 4,000 

average megawatts about the mean of 16,000 average megawatts in a Northwest system 

where annual average loads are approximately 22,000 average megawatts. Thus, a period 

of near-average or better water conditions could hold down prices and destroy the 

profitability of a power plant. Conversely, a low-water year or two can result in large 

profits. This added element of risk could adversely affect the amount and timing of 

investment and, therefore, the adequacy and reliability of the power supply. 

Recent Experience

Figure 1 shows the pattern of generation development in the Northwest from 1994 

through 2003. The data for 2002 and 2003 are the generation that is currently under 

construction and scheduled to be completed in those years 
February 6, 2002 7

Figure 1 – Generation Development in the Northwest

-500

0

500

1000

1500

2000

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Capacity (MW)

Black Liquor Coal

Fuel Oil Hydro

Landfill Gas Natural Gas

Pet Coke Refinery Gas

Wastewater Gas Wind

Wood Residue Fuel Oil

Hydro Natural Gas

Wood Residue

As these data show, there was little investment in new capacity in the early years of 

restructuring. During the mid to late 1990s, prices were low as large capacity margins 

were worked off and several good hydropower years added to supply. Regulatory 

uncertainty (e.g., will there be retail competition or not?) and environmental concerns 

probably contributed to a reluctance to make commitments to generation, but the 

overwhelming factor was that prices were too low to support new development, even 

with steady growth in demand. 

In the summer of 2000 and carrying on through much of 2001, poor hydro conditions 

revealed the underlying tightening capacity margins. This unmasked the shortcomings in 

California’s market design and led to the rolling blackouts, high prices and volatility of 

2000-2001. These high prices also triggered tremendous development activity. Figure 1 

shows approximately 4,500 megawatts of capacity coming online in the Northwest from 

2001 through 2003. This is a small fraction of the 31,000 megawatts of capacity 

reportedly under construction within the area of the Western Systems Coordinating 

Council.1 This development, plus a return to more normal hydropower conditions and 

the effect of the slowed economy, has already meant a return to low market prices. On 

the one hand, this is good news for consumers. On the other, this may set us up for 

another period of volatility, high prices and short supplies in a few years if further 

development is put on hold.2

 

1

 Data Base of Proposed Generation Within the Western Systems Coordinating Council, 

California Energy Commission, available at: 

http://www.energy.ca.gov/electricity/wscc_proposed_generation.html

2

 Simulation Scenarios for the Western Electricity Market -A Discussion Paper for the California Energy 

Commission Workshop on Alternative Market Structures for California, Prof. Andrew Ford, Washington 

State University. Available at: http://www.wsu.edu/~forda/FordCECPaper.pdf
February 6, 2002 8

Volatility is normal in most commodity markets. Marketers, retailers and large 

consumers typically deal with it through longer-term bilateral contracts that limit 

exposure to price volatility and through the use of price hedging instruments. Spot 

market volatility plays an important role in market corrections and in creating risk 

mitigation products to shift volatility risks from consumers to parties that wish to take 

more risk. 

An issue for electricity markets is that inadequate investment in generation and 

conservation may lead to not just price volatility, but also actual electricity supply 

shortage and interruptions and the attendant economic disruptions. This risk arises from 

the instantaneous nature of supply-demand balance in electricity markets, the limited 

ability to store electricity, and a mismatch between the short time it takes to trigger a 

period of volatility (e.g. the transition period from a wet year to a dry year) and the longer 

time it takes to develop new generation. 

Because of these factors, we believe it is important to examine the options available to 

moderate volatility and potential supply-demand imbalances in the electricity market. 

What are some of the options?

Some of the options might include:

• Do nothing and let the mechanisms for hedging the risk of volatility develop. The 

premiums paid for such mechanisms can support the development of resources to 

guarantee supply and, as a consequence, moderate volatility.

• Provide some form of capacity payment to provide an incentive for a greater level 

of investment in generation. There are several potential designs for a capacity 

payment, each with its strengths and weaknesses. Such a mechanism also 

requires some entity of sufficient scope to implement the payment and recover the 

costs.

• Empower some entity to construct resources to ensure maintenance of a particular 

capacity margin. 

• Establish a regulatory requirement on load serving entities to maintain a certain 

capacity margin. 

It is the Council’s intent to try to examine mechanisms like these for their effect on 

prices, system cost, and reliability. 

Increasing the Price-Responsiveness of Demand

The role of price responsiveness in disciplining the market

In most commodity markets, consumers’ responses to changes in price serve to discipline 

prices. If prices get too high, consumers find substitutes, use the product more 

efficiently, shift the use to periods when it is less expensive or curtail the activity that 

uses the product. It can be argued that electricity is different in that it is a necessity of 

modern life and there is a limited ability to substitute for it. On the other hand, we are all 

aware of opportunities to reduce our use of electricity, use it more efficiently or shift our 
February 6, 2002 9

use to different periods. Price-responsive demand yields benefits directly to those who 

are able to reduce their power costs. It also yields benefits more broadly. Through the 

interaction of supply and demand, price-responsive demand can reduce the marketclearing price of power. For example, some studies have shown that wholesale prices can 

decline by a factor of 10 from high-price levels, so that a reduction of peak demand by 

2.5 percent at a high-price hour can result in a wholesale price decline of 25 percent.3

There were a number of factors that contributed to the Western electricity market 

upheaval in 2000 and early 2001, not the least of which was the design of the California 

market and the market behaviors that design engendered. However, the Council and 

most other analysts agree that the crisis was heightened and prolonged by the lack of 

response of electricity demand to the growing shortage and increasing price of electricity. 

This lack of demand response resulted from the isolation of consumers from the market 

price of electricity. In California, this was because retail rates were frozen while stranded 

costs were recovered. In other parts of the West, it was a result of a continuing mix of 

regulated retail markets with little attention to what is needed in order to allow the 

competitive wholesale market to work effectively. 

As with the increase in prices, there are a number of factors that contributed to the 

dramatic reductions in power prices in the summer of 2001. A major factor was response 

of demand to prices, albeit much delayed. Here in the Northwest, this was primarily from 

buyouts of the aluminum industry loads. In total, this amounted to over 2,200 megawatts. 

Unfortunately, it took quite some time to get all these load reductions in place, allowing 

very high prices to persist for several months. It is possible that if these load reductions 

could have been put in place more rapidly, the high prices could have been attenuated 

more rapidly. Now that last years high prices have worked there way into retail rates, 

many utilities of the region are now seeing their demands respond to prices. 

Unfortunately, it is too late to affect the wholesale power prices that made it necessary to 

raise rates in the first place. If the region is to avoid similar consequences in the future, 

now is the time to begin to put in place the mechanisms to increase the responsiveness of 

retail demand to wholesale prices. 

Options for achieving price responsiveness in a mixed market

We believe there are several opportunities for increasing the price responsiveness of 

demand even in the context of the mixed power market we think will persist in this 

region. They include:

• Real-time pricing for those who are capable of managing their loads. There are 

many primarily larger customers who are capable of managing their use of 

electricity in response to prices. There are clear benefits to being on the market 

when prices are low. If these customers can manage their consumption when 

prices are high, they could experience overall benefits. While it is typically 

thought that this is limited to larger industrial customers or industries with 

 

3

 Braithwait, Steven, Christensen Associates, Lessons from California, The Role of Demand Response; 

Institute for Regulatory Policy Studies, May 17, 2001. In the case of California circa 2000-2001 this could 

have saved California consumers $700 million in summer wholesale costs. 
February 6, 2002 10

substitute fuel or self-generation capability, it may also include larger commercial 

buildings, particularly those with sophisticated energy management systems. 

• Alternative rate designs. Most consumers probably do not want all their 

electricity use exposed to the market and the volatility that can entail. They 

might, however, benefit from alternative rate designs where a base amount of 

consumption is charged at regulated rates and everything over that is at the market 

rate. 

• Expanded and more routine load buybacks such as Demand Exchange. The flip 

side of market pricing is the opportunity to receive a market price-based payment 

in return for reducing load. This is the concept behind the Demand Exchange 

programs run successfully by Portland General Electric, Bonneville and others. 

The load-serving entity makes an offer to the customer on a day-ahead basis to 

pay for load reduction at a rate based on a share of the savings from not paying 

the market price for that power. The customer is free to accept or reject the offer. 

If the customer accepts, it is paid on the basis of delivered load reduction. While 

this has been primarily limited to very large industrial customers, there may be the 

opportunity to expand this approach

• An explicit role for the Direct Service Industries (DSIs) in supporting reliability. 

Most of the load reduction achieved over the last year was from the Direct Service 

Industries, primarily aluminum smelters. The question of future service to the 

DSIs from Bonneville beyond the current contract period is very much an issue. 

A consideration in the resolution of that issue may be the reliability and price 

mitigation benefits that may be derived from the ability to displace DSI load 

under certain conditions. 

Prerequisites – metering and information

There are some necessary preconditions for significant expansion of mechanisms for 

achieving price-responsive demand. Primary among these are metering and information. 

Metering that can resolve actual consumption on the time scales of interest is essential. 

This will require investment in new technology, but it is an investment that will need to 

be made. This investment will yield benefits beyond reliability and price mitigation (e.g., 

automated meter reading can reduce billing costs) and set the stage for the next 

generation of electricity services. 

Similarly, information about market prices on the same time scales is important. This 

may prove to be more difficult. There is not at present a formal day-ahead or real-time 

energy market in the Northwest that can provide price transparency to all market 

participants. The Federal Energy Regulatory Commission staff has recently released a 

discussion paper laying out its vision of what is required for a well-functioning wholesale 

power market.3 Included is a voluntary day-ahead market, noting that such a market 

would, among other things, facilitate demand responsiveness. The FERC staff envisions 

this as a function of a Regional Transmission Organization (RTO). It is not clear what 

the resolution of the RTO question will be in the Northwest or whether an RTO, if 

 

3 Concept Discussion Paper for an Electric Industry Transmission and Market Rule, staff of the Federal 

Energy Regulatory Commission, December 17, 2001
February 6, 2002 11

formed, will incorporate a day-ahead energy market. Absent such a market, there are a 

number of market indices that provide on- and off-peak period prices that might be used. 

However, because there can be significant variation in prices from hour to hour, intra-day 

prices would be much preferred. 

The Council believes that increasing the responsiveness of demand to wholesale prices is 

important and intends to evaluate the alternatives discussed above or other alternatives 

for increasing the price-responsiveness of demand. The analysis would address the 

effects on system cost, reliability and prices.

Achieving Economically Efficient Investment in 

Efficiency

The Conservation Roller Coaster

Just as investment in generation withered in the late 1990s, investment in conservation 

was also well below the level the Council had determined to be cost effecting in its 

Fourth Power Plan (Figure 2). Of course, the performance of individual utilities varies 

widely. Some pursued conservation aggressively while others did not. There are many 

reasons for the aggregate fall-off in development including, for example, 1) the 

uncertainty surrounding the direction of industry restructuring and the concern that 

investment in efficiency could become a stranded cost, 2) Bonneville’s concerns about 

being competitive in the wholesale market and 3) the low market prices that made the 

front-loaded investment in efficiency look unnecessary. 

For many years, the Council asserted that one of the benefits of conservation was its 

flexibility – it could be “ramped up” and “ramped down” as needs dictated. However, 

many believe that the flexibility is overrated. Much of the conservation industry is made 

up of local contractors for whom ramping up and ramping down is problematic. In many 

instances these local businesses are also the primary marketing element for conservation 

programs. Their inability to present a consistent picture to their customers hampers their 

marketing efforts. 

The prospect for continued volatility in electricity prices also suggests a rethinking of the 

flexibility of conservation implementation. In this environment, it may be that sustained 

investment in conservation at long-term cost-effectiveness levels makes more sense than 

ramping up and down with the latest swing in electricity prices. For example, the costeffective conservation that was not done in the late 1990s and 2000 would have almost 

entirely paid for itself at the market prices that existed between June of 2000 and June of 

2001 and would have had on average, 13 years of useful life remaining. 
February 6, 2002 12

Figure 2 – Annual Utility Conservation Development

0

20

40

60

80

100

120

140

Savings (aMW)

19901991199219931994199519961997199819992000

Actual Council Plan

Evaluation of Sustained Investment vs. Market Price-Driven 

Investment

To evaluate a sustained investment in conservation, alternative investment scenarios will 

be evaluated against a number of future electricity price futures incorporating different 

timing and levels of price volatility. The effects on total system cost, prices and 

reliability will be evaluated.

Options for Implementing Sustained Investment

If sustained investment in conservation is justified, there are a number of alternative ways 

in which it might be done, several of which are being tested here in the Northwest. They 

include the different forms of public benefits charges being tried in Montana and Oregon 

and “tariff riders” being employed by several investor-owned utilities. There are 

probably others. The Council will assess the strengths and weaknesses of different 

approaches and, if appropriate, suggest ways in which these programs might be 

improved.

Information Requirements for Assessing Power Supply 

Adequacy and Market Performance

The changing electricity markets have also changed the focus of the Council’s planning 

work. In the past, the Council’s focus was on long-term resource needs and composition. 

Recently, the Council’s focus has shifted to shorter-term adequacy and reliability 

assessment and assessment of the performance of electricity markets. To some extent, 

these changes in focus are also under way at other regulatory and oversight agencies. 

These changes entail different data and information needs than in the past. In assessing 

the problems in electricity markets over the last couple of years, the Council has found 

that the data that is needed to adequately evaluate markets for adequacy and reliability is 

not readily available. Even the data that has traditionally been used to assess longer-term 
February 6, 2002 13

market trends is becoming less available and reliable since the electricity markets have 

begun restructuring.

For example, information on electricity consumption is typically collected from 

individual utilities reporting to agencies that compile the data into estimates of 

consumption by sector (residential, commercial, industrial, etc.) on an annual basis. This 

data is becoming less comprehensive as independent electricity marketers serve some 

large loads. In any event, the availability of this data lags at least a year behind current 

information. More current monthly and hourly data on electricity loads is not amenable 

to sectoral or geographic analysis. Thus it is difficult to analyze many of the basic 

determinants and trends in demand and how demand might be affected by emergency 

actions during an electricity shortage.

Increasingly, electricity adequacy and reliability are issues for the entire western 

interconnected power system, not just the region. However, most sources do not organize 

data on this basis. The Western Systems Coordinating Council (WSCC) does, but there 

are difficulties with the availability, scope and accuracy of the WSCC data. Electric 

reliability agencies like WSCC are being transformed to function more appropriately in 

today’s electricity markets, and there may be opportunity to shape the data collection role 

of these organizations to facilitate market assessment and analysis and to provide 

information that will enhance competition in the market.

As a part of the power plan, the Council intends to evaluate the data needed to perform its 

planning and market assessment functions, and to investigate how best to obtain such 

data if it is not currently available.

Fish Operations and Power 

During 2000-2001, fish assistance programs and power system reliability came into 

conflict. Decisions were made to risk compromising the survival of juvenile salmon and 

steelhead by reducing or eliminating spill in order to ensure adequate supplies of power 

and to manage the economic impact of the high market prices of power. If many of the 

issues described above can be successfully resolved, the power system should be better 

able to provide the operations desired for fish even in low water years or times of 

financial crisis while the region also enjoys a more reliable power system. The Council, 

in its 2002 mainstem amendments to the fish and wildlife program, intends to identify 

operations that are effective for fish and to begin to describe what changes will be 

required in the power supply system to ensure operations for fish can be provided in 

nearly all circumstances. During that process, the Council will be weighing the benefits 

to fish from alternative main stem operations (the timing, quantities and locations of flow 

and spill) against the effects on the power system. This is intended to lead to more costeffective river operations. 

But conflicts between the value of hydro operations for fish and for power will probably 

always exist to some degree. A significant problem is that the dollar value of power 

operations is easily quantifiable whereas the value of the fish operations to meeting 
February 6, 2002 14

recovery goals is not. There remain incentives to deviate from prescribed fish operations 

when power supplies become tight and prices soar. 

It may be possible, through careful consideration of the relative priorities of different 

operations for fish and power, to better manage the operational interaction to minimize 

the adverse effects for fish while achieving increases in power production and storage 

during power emergencies. Some argue, however, that fish operations should be viewed 

as firm environmental compliance requirement similar to air and water quality standards. 

Otherwise continued financial incentives to maximize power operations will overcome 

the incentives to operate for fish, particularly under financial or power emergencies. This 

would suggest penalties for deviations from prescribed fish operations. Alternatively, it 

may be possible to structure a system of sharing of the monetary benefits of deviations 

from prescribed fish operations to permit mitigation of the effects on fish. 

The Council proposes to investigate both operational strategies and potential incentives to 

minimize impact on fish from deviations from prescribed fish operations and the options 

available to mitigate these impacts.

Transmission and an Adequate, Efficient, Economical 

and Reliable Power System

Perhaps as a consequence of the functional separation of transmission and power, 

transmission policy and planning has become even more critical to achieving an 

adequate, efficient, economical and reliable power supply than in the past. It is no longer 

a question of a vertically integrated utility determining how best to serve its loads and 

building the mix of generation, transmission and demand side solutions required. The 

issue is how independent power developers, transmission owners, load serving entities 

and even consumers make coherent decisions about what to build and where to build in a 

vast interconnected system. Those decisions can have significant consequences in terms 

of the costs to consumers of the region, the distribution of those costs among various 

parties, the adequacy and reliability of the power supply, and the quality of the 

environmental. 

Many of these issues are being addressed in the context of the development of the filing 

with FERC for the formation of RTO West. That filing, however, will not end 

consideration of these issues. In addition, Bonneville will be confronted with these issues 

as it considers upgrades to its transmission system and establishes new transmission rates 

that will take place before an RTO is in operation.

Consequently, the Council proposes to address transmission policy and planning issues as 

they affect the Council’s mission of assuring an adequate, efficient, economical and 

reliable power supply. The bookends of the ongoing debate are a market approach which 

relies on creating a system of price signals to influence the choices between a “wires”(i.e. 

building transmission) and “non-wires” (e.g. load-center generation, demand 

management and efficiency) solutions to specific load/resource issues; and a planning 

approach in which a central authority somehow makes those tradeoffs and implements 
February 6, 2002 15

solutions. Given the reality of the mixed market system in which we are in, the answer 

may lie somewhere between. 

Specific questions the Council may want to address include:

• What is the Council’s position on traditional postage stamp rates vs. locational 

pricing? 

• How do you make the right trade-offs between adding generation or Demand-Side 

Management (DSM)/efficiency improvements to reduce the need for transmission 

investment or making the transmission investment? 

• How can least cost planning processes be implemented in an institutionally 

disaggregated world? 

• If transmission expansion relies mostly on market signals and responses, do we 

need a backstop if markets fail? How would we know a market failure?

• How do you deal with the relative environmental difficulties of siting generation 

closer to load and siting large transmission lines?

• Should the transmission system be built out until there is no congestion (that is, 

until all requests for transmission service can be met without jeopardizing system 

security)? If not, what is the right level of congestion to accept on the 

transmission system?

• Who should pay for relieving transmission congestion? Everybody? Those who 

caused it? Those who benefit from its relief? If not everybody, who decides and 

what is the payment mechanism? 

• Should the Council make recommendations or decisions about generation 

location? How should it arrive at those recommendations or decisions? How 

would they be implemented in a disaggregated world?

• What is the role of local economic development in transmission decisions? Does 

it make a difference who pays for the transmission?

Value of and Barriers to Resource Diversity

Current Trends 

Figure 2 shows the approximate current status of generating resource development in the 

Northwest.
February 6, 2002 16

Figure 2 – Northwest Generating Resource Development

Generating Project Development Activity in the Northwest

January 2000 Base 

0

2000

4000

6000

8000

10000

12000

In-service Construction Permitted Permits

Pending

Planned Potential Deferred Retired

Capacity (MW)

Unknown Hydropower

Wind Geothermal

Nuclear Coal

NG CC Biomass

NG Other Fuel Oil

Figure 2 indicates that the great majority of the generation that has recently entered 

service, is under construction, is permitted, is in the permitting process or is planned is 

fueled by natural gas. Most of the units are combined cycle units with a few single cycle 

units as well. The major exception is an unprecedented but relatively modest amount of 

wind generation currently under construction and in the permitting process. There are 

“potential” projects fueled by coal and nuclear fuels as well as additional wind, but these 

are not far along in the process. 

Figure 3 shows the shares of Northwest generation for the major fuel types in 1996 and 

projected for 2003.

Figure 3 – Shares of Northwest Generation

Percent of Average Northwest Generation

(Average Hydro Conditions)

0%

20%

40%

60%

80%

100%

1996 2003

Other

Natural Gas 

Nuclear

Coal

Hydro
February 6, 2002 17

As this figure shows, the share of generation fueled by natural gas is expected to more 

than double by 2003. In many respects, this represents a more diverse resource set than 

existed in the past. In addition, the Council has long recognized the economic flexibility 

of natural gas-fired generation technologies in a competitive electricity market, especially 

one with a large share of precipitation-dependent hydropower generation. However, if 

the development pattern in the future reflects the pattern in Figure 2, we might expect 

natural gas-fueled generation to supplant coal by a significant margin within the time 

horizon of the Fifth Power Plan. Viewed from the perspective of the WSCC, 47 percent 

of the generating capacity in the West is projected to be gas-fired by 2010.4

Growing reliance on natural gas as an electricity generation fuel has also raised issues of 

whether conversion of electric space and water heating to directly use natural gas is a 

more energy efficient and economically efficient use of natural gas. While previous 

Council analysis has established that fuel conversions are neither a resource under the 

Act nor a conservation measure, there may be situations where fuel conversion is still a 

desirable course of action for the region. The Council will address this issue in the power 

plan and determine appropriate actions, if any, in the context of other conservation and 

resource decisions.

Value of Resource Diversity

Whether the rapidly increasing role of natural gas-fired generation technologies is a cause 

for concern is an open question. Resource diversity is not an end in itself. The question 

is whether or not greater diversity yields benefits. The benefits that diversity might 

deliver are like the benefits of a diverse investment portfolio – if one segment of the 

portfolio goes sour, hopefully other segments will hold their own or even compensate for 

the poor performing one. 

There are several kinds of risk associated with a lack of diversity in new resource 

additions that could be evaluated. They include:

• Fuel price/volatility risk – the effects of differential fuel price escalation rates 

and/or differential price volatility on the overall relative costs of resources. Fuel 

price risks can typically be passed through to consumers.

• Fuel supply risk -- the risk of fuel supply interruptions. 

• Environmental cost (regulatory) risk – the risk associated with the potential 

internalization of environmental costs. An example is the risk of the 

internalization of climate change risks through market mechanisms like a carbon 

tax or regulations on emissions. 

• Fixed cost or investment risk. From a market perspective, this is one of the risks 

that investors may take in hopes of earning a return on their investment. In a 

competitive market, it is more difficult to pass this risk on to consumers. The 

current preponderance of technologies with low fixed costs in the new generation 

mix suggests that this is a risk that investors seek to minimize. From a societal or 

central planning perspective, fixed cost risk represents the risk that societal 

 

4

 10-Year Coordinated Plan Summary 2001-2010, Western Systems Coordinating Council, August 2001
February 6, 2002 18

resources may be tied up in less productive activities. The questions are whose 

role is it to take investment risk, and what is the best sharing of the role of 

investment risk-taker? 

• Performance risk – the risks associated with common cause equipment failure.

The analytical question is whether consideration of these risks is likely to change the 

relative cost-effectiveness of different resource types. 

Opportunities for and Barriers to Resource Diversity 

If there are significant benefits to a more diverse set of new resources, where are the 

opportunities for development of those resources, and are there infrastructure, policy or 

regulatory barriers that prevent those opportunities from being realized? 

Transmission 

As noted in the section on transmission, transmission considerations can affect resource 

decisions in a number of ways. 

Transmission investment may be a necessary adjunct to investment in certain resource 

types that are by their nature located far from Northwest load centers, such as some wind 

generation. It may be a desirable investment as part of an overall economic decision, 

such as a choice to locate a coal plant at the mine mouth rather than locating it closer to 

loads and hauling the coal by rail, or the choice to locate a gas plant near a pipeline that is 

distant from loads rather than near one that is closer to loads because the former pipeline 

provides cheaper gas.

There are also transmission operating considerations, such as scheduling requirements or 

imbalance market penalties, may have disproportionate effects on some resource types, 

like wind or other non-controllable resources, compared to more traditional utility 

resources.

Transmission investment can be postponed or avoided entirely by investment in end-use 

efficiency improvements, demand-side management programs or small-scale distributed 

generation at the end use. Because of the varying locations of transmission constraints at 

the present time, some of these programs or small-scale resources may have different 

values, depending on where they are implemented or located. 

The Council proposes in its power plan to specifically examine the transmission issues 

raised by alternative resources. For example, are there instances where investments in 

transmission combined with existing or alternative resources would be the most costeffective means of meeting demand for electricity, and are there transmission pricing or 

other policies that are preventing those investments? At the same time, the Council will 

also look at the value of distributed resources, including smaller-scale generation, enduse efficiency improvements and demand-side management, in reducing or delaying 

transmission investments. 
February 6, 2002 19

Integrating Intermittent Renewable Resources into the System

The output of wind, solar and some small hydropower is a function of the intermittent 

availability of the primary energy resource and may vary significantly and unpredictably 

on a sub-hourly basis. Other system resources may need to be dispatched to compensate 

for these variations in output. Several issues are associated with the effects of 

intermittency. Issues currently receiving attention include “imbalance charges,” and, 

more recently fixed-capacity access charges. Regarding imbalance charges, operators of 

intermittent facilities (or organizations taking or wholesaling the output of these 

facilities) may be required to pay for the cost of dispatching resources to compensate for 

the intermittent output. Provided that the cost of compensation is a fair representation of 

actual costs, this is a reasonable component of the cost of providing power from these 

sources. However, in addition to the cost of dispatching compensating resources, 

penalties may be assessed for deviation in output exceeding prescribed values. Though 

implemented to curtail market gaming by the operators of dispatchable resources, these 

penalties could be applied to in such a way as to be large enough to significantly impact 

the economic competitiveness of intermittent resources.

Other issues associated with resource intermittency include establishing transmission 

charges proportional to the transmission costs imposed by the resource, and determining 

the true cost, and how that cost might vary as intermittent supplies increase, of serving 

imbalance.

Other than consideration of the effects on cost-effectiveness of the seasonal variation of 

wind resources, issues associated with resource intermittency have not been assessed in 

previous power plans. The expected near-term development of intermittent resources 

was not sufficient to warrant extensive analysis. With increasing development of 

intermittent resources and the prospect of additional development driven by state public 

benefits charges, Bonneville’s renewables initiatives and various “green” power products, 

the issues associated with integration of intermittent resources have taken on greater 

importance. The Council proposes to assess these issues to the extent possible and to 

issue recommendations where appropriate. Because of the relationship of many of these 

issues to the transmission system, the Council may work in conjunction with Bonneville 

to address certain of these issues. 

Distributed Resources – reliability, transmission and distribution

The concept of distributed resources, in its broadest sense, seeks to take better advantage 

of locating generating facilities or investments in DSM. Locating new generation or 

DSM near loads can reduce the electrical losses and economic and environmental costs of 

transmission and distribution. Thermal generation located near loads creates 

cogeneration opportunities, with the prospects of improving the efficiency of energy use 

and the economic and environmental cost of serving electrical and thermal loads. 

Distributed generation can also improve system reliability by providing smaller-scale 

local sources of power. 

Distributed resource benefits can be provided by a wide range of resources, technologies 

and applications, including many that are commercially available. Industrial 
February 6, 2002 20

cogeneration, for example, is a distributed generation application that has been in use 

since the initial commercialization of electric power. At one extreme, the siting of large 

combined-cycle plants nearer to loads can offset long distance transmission costs and 

losses. At the other extreme, micro-turbine and fuel cell technologies under development 

are expected to lead to affordable “power plants in the closet” that could bring the 

benefits of cogeneration to residential customers and defer or offset transmission and 

distribution system costs. The same can be true of investments in efficiency and load 

management. 

Technology development, by reducing the cost, size, and environmental impact of 

generating facilities, and by automating facility operation, is continually broadening the 

potential applications for distributed generation. At the same time, rapidly developing 

technologies such as direct digital control are providing new opportunities for demandside management. Formidable institutional barriers remain, however. Many of the 

economic advantages of distributed resources only appear if the prospective owner is able 

to share in the transmission and distribution benefits. Similarly, seasonal and time-of-day 

electricity (and fuel) price signals or alternatives (such as buy-back arrangements) are 

required to achieve economically optimum design and location of distributed resources. 

Interconnection standards can also be a significant barrier to distributed generation. 

Because it is likely infeasible to evaluate, control and monitor the environmental impacts 

and electrical interconnection of micro-scale generation, there is a need to adopt standard 

design and installation practices.

In its Fifth Power Plan the Council proposes to assess the potential benefits of distributed 

resources to the region and the prospects for achieving these benefits. We will attempt to 

identify barriers to the achievement of these benefits and approaches to resolving these 

issues. 

The Role of The Bonneville Power Administration in 

Resource Development

The primary motivation for the development of the Northwest Power Act in the late 

1970s was to authorize the acquisition of new resources by the Bonneville Power 

Administration. The predominant generating technologies of the day were large scale, 

very capital-intensive coal and nuclear power plants. Bonneville had backed the 

financing of three of the five Washington Public Power Supply System nuclear power 

plants through a mechanism called net billing. That mechanism had, however, been 

stretched to its limits. If Bonneville was to be involved in the development of additional 

resources, the authority of Bonneville would have to be expanded. The benefits of 

Bonneville involvement, such as the appearance of federal backing of a resource and the 

ability of Bonneville to spread the costs of new resources broadly around the region, were 

sufficient to cause utility and industry groups to unite in support of this expansion of 

Bonneville’s authority. The Northwest Power Planning Council was created, in large 

measure, to serve as a check and balance by the Northwest states on Bonneville’s 

acquisition authority.
February 6, 2002 21

It can be argued that many of the conditions that led to the passage of the Northwest 

Power Act and the expansion of Bonneville’s acquisition authority no longer obtain. In a 

competitive wholesale power market, no one appears to be particularly interested in 

taking on the fixed cost risk of large coal or nuclear power plants. That being the case, 

the rationale for Bonneville involvement in resource acquisition is much diminished. 

There are other reasons to question the need for and value of Bonneville involvement in 

resource acquisition. They include:

• Bonneville involvement in resource acquisition can expose Bonneville and 

ultimately the United States Treasury to risk. Bonneville is required by law to 

meet the requirements of those public agencies that place load on Bonneville. 

The customers are required to purchase the power only for the length of the power 

sales contracts. The length of these contracts is typically less than the term of 

financing new generating resources. In the mid-nineties, Bonneville experienced 

an exodus of customers because their rates, driven largely by their fixed cost 

obligations, were temporarily above market prices. This could happen again, 

particularly if Bonneville were to undertake significant long-term resource 

acquisitions. This could expose Bonneville and the Northwest to significant 

political risk if Bonneville were unable to meet its obligations to the Treasury.

• Bonneville can and does attempt to limit its acquisitions to short terms coincident 

with their contractual obligations. This, however, means that they do not know 

what their obligations will be until a relatively short time before a new contract 

period begins. This can force Bonneville into the market in a relatively large way 

in order to secure resources to meet its obligations. This is not an enviable 

position. Some also argue that in these circumstances, Bonneville is such a large 

presence that it seriously distorts the market. 

• The pricing of Bonneville’s power also distorts the market. Bonneville is 

required by law to sell its firm power to regional customers at cost. Historically, 

Bonneville has chosen to meld the cost of more expensive new resources with the 

lower cost Federal Columbia River Power System resources. The result is a 

melded cost that is lower than the cost of new generating resources and some new 

efficiency resources as well. As a consequence, Bonneville’s utility customers do 

not see the full cost of new resources and have diminished incentive to invest in 

new resources themselves or promote the more efficient use of electricity. Many 

believe that Bonneville could charge different prices for the power from different 

resources so long as the prices charged were based on the cost of the respective 

resources (e.g., an existing resources block and a new resources block). This has 

been termed a “tiered rate.” Overall, the cost to a customer would not be greater 

than with melded rates, although the marginal rate would reflect the incremental 

cost of new power. Bonneville has made one attempt to implement such a system 

but eventually abandoned the idea in the face of customer opposition.

There are several alternatives that have been discussed over the years:
February 6, 2002 22

• Maintain the status quo. Bonneville and the region have managed to operate 

within this system up to now. In short, “If it ain’t broke, don’t fix it.”

• Implement a tiered rate system as described above.

• Bonneville could act as an agent for acquisition of new resources for its 

customers, but those customers would pay the full cost of those resources and 

accept the risk associated with them. This was proposed by the Comprehensive 

Review of the Northwest Energy System in 1996.5 Alternatively, some other 

form of cost and risk sharing could be devised. 

• Bonneville could merely act as an agent for the sale of the power only from 

existing federal resources and not develop new resources. Customers would be 

on their own for requirements above “their share” of the existing federal 

resources. The existing resources could be sold as traditional firm power products 

(with Bonneville marketing the non-firm power) or through a “slice” product 

where the customer gets its “share” of the output of the system, both firm and 

non-firm. This has the added advantage of dispersing control of the non-firm 

power and, thus, limiting the ability of one player to exercise market power 

through its control of non-firm power while also reducing the presence of the 

federal government in the competitive new resource development market. 

There are numerous issues associated with any of these alternatives or others that may be 

proposed. They include whether Bonneville should be obligated to meet load growth 

and, if so, how. Another question is, what happens to Bonneville’s role in the 

development of conservation and renewable resources if Bonneville is no longer 

responsible for meeting growing loads in the region? Is it reasonable for Bonneville to 

have responsibility for the development of some kinds of resources and not others? 

Perhaps the most significant barrier to any move from the status quo is the fact that most 

alternatives require an allocation of the existing low-cost resources within the region. 

Such an allocation would be contentious because of the high value of the existing system. 

It may create the perception of winners and losers within the region. But it may 

ultimately be a more stable solution than the status quo.

There are currently ongoing discussions among different customer groups that are 

focused on the question of allocation of existing Bonneville power in the post-2006 rate 

period and beyond and Bonneville’s role in resource acquisition. If these discussions 

bear fruit, the Council would analyze the proposal or proposals to develop the pros and 

cons with respect to resource development, power system adequacy, reliability, cost, 

market dynamics and the ability of the region to retain the benefits of the federal system. 

The purpose of this analysis would be to help the public and regional leaders reach 

decisions about the appropriateness of the proposals. In the absence of such proposals, 

the Council intends to engage the region on these issues and develop the pros and cons 

associated with the alternatives as fully as possible. 

 

5 Comprehensive Review of the Northwest Energy System, December 12, 1996, p. 15. Available at: 

http://www.nwcouncil.org/library/1996/cr96-26.htm
February 6, 2002 23

Global Climate Change Risks

A preponderance of scientific opinion asserts that the earth is warming and that this 

warming is largely the result of increased production of carbon dioxide and other 

greenhouse gasses due to human activities. In addition, it is now generally asserted that 

some level of global climate change is inevitable. While some effects of climate change, 

such as longer growing seasons in certain regions, may be positive, others may be 

negative. For example, some expect adverse consequences from effects including sealevel rise, changes in precipitation patterns and storm activity and consequent runoff 

patterns, changes in the distribution of infectious diseases and pests, and effects on the 

distribution and health of forest and other natural ecosystems. 

Because of the widespread use of fossil fuels to produce electricity, the electric power 

industry is a principal contributor to the growing atmospheric concentration of carbon 

dioxide. Furthermore, the production of electricity from hydropower, so important in the 

Northwest, may be affected by climate change if historical precipitation patterns change. 

Therefore, any effort to control and adapt to climate change must involve the electric 

power industry.

The status of the climate change issue and the effect of possible carbon dioxide control 

measures on the value of conservation and renewable resources were assessed in the 

Fourth Power Plan. That plan set forth several recommendations regarding climate 

change, principally a stronger emphasis on conservation and general recommendations 

regarding the design of approaches to greenhouse gas control. 

In the new power plan, the Council proposes to review the status of the global climate 

change issue, including the current understanding of possible effects on the Northwest 

hydropower system and the effects of possible greenhouse gas emissions control policies 

on the relative cost-effectiveness of resources available to the Northwest. 

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