Northwest Electricity Markets in 2001: 

Status and Proposed Actions

March 26, 2001 Council Document 2001-05
2 Northwest Electricity Markets in 2001

Executive Summary

There is significant regional concern about electricity 

supplies and prices for the rest of 2001 and beyond. Our 

analysis indicates that this concern is well-founded. The 

purpose of this paper is to clarify the electricity situation 

for 2001, to note the actions that are being taken to 

address the problem, and to urge additional actions that 

can be taken to help improve this year’s prospects for 

meeting electricity needs while minimizing impacts on 

fish programs and the regional economy.

Western electricity markets are headed for a difficult 

summer and possibly a difficult winter of 2001-02 as 

well. Current poor water conditions translate into continued tight electricity supplies for the rest of 2001. The 

accompanying high electricity prices could combine with 

a general slowdown in economic activity to create difficulties for many of the region’s businesses and citizens. 

This paper does not focus on conditions beyond 2001, 

and no inferences regarding the future adequacy and reliability of power supplies should be drawn beyond this 

time frame. Longer-term issues will be addressed in 

future analyses.

In order to meet regional loads this winter, the region 

has had to rely on emergency operation of the hydrosystem, drawing down reservoirs below the levels established 

by the 2000 Biological Opinion on Operation of the Federal Columbia River Power System issued by the National 

Marine Fisheries Service. It is a virtual certainty that 

these emergency operations also will be necessary during 

this spring and summer to keep the electricity system 

from suffering outages. In addition, it is likely that substantial reductions in spill will be necessary. 

The use of emergency hydro and spill reduction and 

their possible effects on fish can be at least partially 

mitigated by taking actions to reduce demand, increase 

in-region generation and purchasing power that may be 

available from the market during the spring. However, 

the latter, in particular, may have a high cost to the 

region’s utilities and economy. As we approach the end 

of summer, restoring reservoirs to levels called for in the 

Biological Opinion (BiOp) is important for reliability in 

the fall and winter as well as for meeting salmon targets 

for flows in 2002. Achieving this is likely to require 

reductions in the spill called for in the BiOp. The difficult 

tradeoffs facing the region involve electricity reliability, 

salmon recovery goals and costs to the region’s utilities 

and the regional economy. To the extent that additional 

generation and demand reduction can be achieved this 

summer at costs lower than expected market prices, this 

trade-off will be more manageable.

Recommended Actions

Individuals, businesses and utilities are already taking 

actions that will help achieve some of these goals. However, there are additional actions that need to be taken 

by regional leaders as soon as possible. These are listed 

below:

• Public leaders should continue to inform and educate 

the public about the electricity problems faced by the 

region this year. Public awareness can be one of our 

most effective tools.

• Parties in the region need to come to agreement about 

hydropower operating strategies for the summer that 

prioritize water usage to strike an appropriate balance 

among reliability of electricity supply, costs to the 

region’s economy, the financial health of the region’s 

utilities and salmon recovery goals. 

• Utility regulators should support and expedite utility 

programs to implement emergency demand management programs.

• Siting and environmental agencies should expedite 

emergency siting of short-lead-time generation while 

still protecting the longer-term societal interests.

• The region’s utilities should seek to bring existing 

emergency standby generation into the grid. Environmental agencies should cooperate by expediting temporary operating permits for such facilities, if necessary.

• Environmental agencies should work to temporarily 

relax restrictions that prevent existing generating plants 

from continued operation at full capacity, without jeopardizing public health and safety.

• Utilities and public agencies should expand the scope 

and funding of existing energy efficiency programs that 

can be expected to deliver savings in the short term.

• Utilities, Bonneville Power Administration (BPA), and 

regulatory agencies should begin the process of designing electricity pricing structures that provide price signals to help develop demand response to prices and 

shortages.

• State and local agencies should ensure that low-income 

assistance programs are adequately funded to respond 

to impacts from high electricity prices.
Northwest Electricity Markets in 2001 3

Background

Status of Electricity Markets

Wholesale electricity markets in the West are in serious 

trouble. Prices since last winter have increased from 

between $25 and $30 per megawatt-hour to several hundred dollars per megawatt-hour. Utilities in California are 

on the verge of bankruptcy, the state has stepped in to 

acquire electricity supplies, and is also considering buying 

the transmission system. California has been operating in 

Stage 3 emergency conditions much of the winter. The 

Pacific Northwest has been forced to implement emergency 

operations of the Columbia River hydropower system to 

keep from interrupting electricity supplies, but this presents 

risks to threatened and endangered fish species.

Many consumers have been insulated from higher 

prices so far. In California, consumer prices were frozen 

by law. In the Northwest, many publicly owned utilities 

buy all of their power from BPA. Other utilities have 

their own generating resources that have been adequate 

to meet loads without reliance on spot markets. However, even what seemed like a reasonably small exposure 

to spot markets for some utilities has turned into huge 

rate increases to the utilities’ consumers because of the 

extremely high wholesale prices. Beginning in the new 

rate period in October 2001, BPA customers may also be 

exposed to some very large rate increases based on the 

need to acquire a few thousand megawatts of additional 

electricity to meet subscription loads.

Causes of Current Market Conditions

It is important to understand that the electricity market 

situation in the West is extremely unusual. This is not 

what should be expected of an even modestly well-functioning restructured electricity market. The reasons for 

the dramatic price excursions we have been experiencing 

are several and are interrelated. They include an immature and structurally flawed electricity market; the simultaneous occurrence of high prices in natural gas and oil; 

poor water conditions; adverse weather; and generating 

capacity that has not been keeping up with the growth 

in electricity demand. It is extremely bad luck for poor 

water, adverse weather, and all major energy commodity 

cycles to coincide, but for it to occur when electricity 

markets are in such a fragile state is extraordinary.

 The Council’s “Study of Western Power Market 

Prices: Summer 2000” described the problems in the electricity market. There are two dominant characteristics of 

the current Western electricity market that are at fault. 

First, the demand side of the market has not yet developed. Price signals are not getting through to consumers 

as retail prices. Second, customers and utilities that are 

exposed to market prices have not adequately protected 

themselves from market price risk. In California, both of 

these characteristics were designed into the restructured 

electricity market. The consequences of these characteristics were not clear until hot temperatures and poor 

hydroelectric conditions exposed the growing shortage of 

capacity in the market last summer.

The fact that electricity capacity has become short, 

may itself be due to the very recent restructuring of 

electricity markets. There have been, and remain, significant uncertainties about the future structure of electricity 

markets, and the plans are inconsistent among the states 

in the West. This kind of uncertainty has made the private sector reluctant to commit capital to new generating 

capacity. Beyond this, the Council’s “Northwest Power 

Supply Adequacy/Reliability Study” raised some issues 

about whether adequate capacity would be maintained 

even in a well-structured and mature electricity market. 

But that is a longer-term issue than we wish to address 

in the current paper.

Understanding that the current situation is unique is 

important background for considering actions to help the 

region through the coming year. One should not underestimate the magnitude of the change involved in moving to 

a more competitive electricity market. The inertia is huge 

and, as in the case of California, policies sometimes work 

against the transition instead of furthering it. Unless one 

believes it is possible to reverse the nationwide move to 

a competitive wholesale power market, actions should be 

considered that help develop a viably competitive wholesale market while helping to alleviate the current shortages. 

As disruptive as the current shortage and high prices 

are, they are rapidly forcing the development of new supplies and improved demand-side responses in the electricity market. New electricity generating plants are being 

started to supplement supplies. But the responses are 

not limited to the traditional generation solutions; smaller 

distributed technologies are gaining favor, demand-side 

changes are being sought by utilities and found, and 

increasingly, demand-side opportunities are being volunteered to utilities as high prices and slowing economic 

conditions affect businesses in the region. These 

responses to the high electricity prices will help alleviate, 

but not eliminate, the electricity supply problems this 

summer. But in the longer term they will forge new 

relationships and approaches that will make the future 

wholesale electricity market more efficient and competi-
4 Northwest Electricity Markets in 2001

tive by diversifying the supply alternatives available and 

making demand more responsive to market conditions. 

These adjustments have a dark side, however. Emergency reductions in electricity use by businesses often 

mean reduced production and loss of jobs. Higher wholesale prices, passed on to residential customers mean 

increased expenditures for electricity and less money left 

over for other purposes. Low-income consumers can 

be especially hard hit because energy bills are a larger 

portion of their already tight budgets.

Below, we document in more detail the expected electricity supply for the coming months and the responses 

taking place in the electricity markets. We then look at 

the limited policy alternatives for helping the region make 

it through the coming summer.

Electricity Outlook for 2001

2001 promises to be another difficult year for the 

Northwest power system and, in fact, for the West as 

a whole. The “meltdown” of the California market of 

last year was triggered, in part, by an unusual Northwest 

rivers runoff pattern that resulted in significantly less 

power in the market last summer than has been the case 

in recent years. This unmasked an underlying overall 

supply shortage resulting in the run-up in prices. 

While 2000 was near normal in terms of overall 

runoff, 2001 is starting off as a very poor water year. 

The current January-July runoff forecast is approximately 

55 percent of average, assuming normal precipitation for 

the March-July period. There is only one year in the 

60-year record with lower March through July runoff. If 

dry conditions persist, this could be one of the poorest 

hydro years on record. Using 1944 water conditions, 

a year with just slightly higher runoff than the current 

projection, “normal” hydropower generation is approximately 4,700 average megawatts less than average over 

the March through August period.1 Using 1977 water 

conditions, the lowest on record, the March through 

August “normal” hydropower generation is over 5,000 

average megawatts below average. If the region DOES 

NOT take extraordinary steps in the operation of the 

hydropower system or purchase substantial amounts of 

power on the market at what are almost certain to be very 

high prices, we could face significant deficits this spring 

and summer. For 1944 water conditions, the total energy 

deficit across the months of April through August is 5,600 

megawatt-months.2 The maximum monthly deficit is 

approximately 2,700 megawatt-months in May. For 1977 

water conditions, the total April through August deficit 

is almost 8,000 megawatt-months, with the May deficit 

reaching 3,300 megawatt-months. 

Policies to Address Shortages

There are steps that can be taken in the operation 

of the hydropower system that can significantly reduce 

or eliminate these summer deficits. Additional generation 

can be achieved through operating outside the BiOp constraints -- drafting reservoirs deeper and reducing spill. 

Loads can be reduced through contract buyouts, conservation and demand exchange efforts. However, the 

choices we make will have implications for our ability 

to continue to meet load through the fall and winter of 

2001-02. These alternatives and the choices involved are 

examined in the following section. However, even with 

such operations, it is likely that this summer will be a 

period of tight supplies and continued high market price. 

The realistic options for policy makers to help negotiate a path through this summer’s electricity problems 

are limited. Some new generation capacity is expected 

to come online in time to help this year, and the use of 

hydrosystem flexibility will improve electricity supplies. 

The rest of the problem can only be addressed by reducing electricity consumption. High wholesale prices and 

forecasts of increasing retail prices are already stimulating actions by consumers and utilities.

Enhancing Supply

Emergency Hydro, Spill Reduction, and Out-ofRegion Purchases 

As noted earlier, there are steps that can be taken 

in the operation of the region’s hydroelectric system to 

increase generation above that which can be achieved 

if the system is operated strictly to the constraints of 

the BiOp. These steps, however, typically involve tradeoffs. For example, if water conditions were not to get 

significantly worse than the current runoff forecast, the 

region could meet it loads across the spring and summer 

through the use of “emergency hydro” alone. Emergency 

hydro involves generating additional energy by drafting 

the system deeper than the constraints established in the 

BiOp. This, however, would reduce summer flows and 

1 “Normal” hydropower output refers to the amount of energy 

that can be generated when operating the system to the Biological Opinion constraints. More generation can be achieved by 

drafting reservoirs deeper and/or reducing spill. 

2 A “megawatt-month” is the energy produced by one 

megawatt of generation over the period of a month. 
Northwest Electricity Markets in 2001 5

leave the reservoirs at the end of August at levels that 

significantly reduce the ability of the power system to 

meet loads through the fall and winter, assuming the ability to purchase imports is limited. If water conditions 

deteriorate to those of 1977, use of emergency hydro 

alone would not solve the spring and summer reliability 

problems and would leave the reservoirs in even worse 

condition at the end of August. 

Staff has done a preliminary analysis of the region’s 

ability to serve load across the 2001-02 winter. That 

analysis compares starting the reservoirs in September at 

the level called for in the BiOp with starting the reservoirs 

at the lower level that would result from using emergency 

hydro alone throughout this spring and summer with 1977 

water conditions. The analysis further assumed that 

beginning in September, the lower two thirds of the historical water years were possible. This reflects a weak 

relationship between spring and summer runoff and the 

runoff in the subsequent fall and winter. The analysis 

estimates the probability of meeting load with water conditions, temperatures and therefore demand for electricity, and forced outages varying randomly. The analysis 

assumed that there is some ability to purchase imports 

through the fall and winter up to 2,250 average megawatts.

With the caveat that this is a preliminary analysis and 

the results may change, it indicates the probability of 

being unable to fully meet loads at some time during 

the winter (December through February) increases from 

approximately 20 percent to 45 percent when starting the 

reservoirs at the lower level. The probability that for any 

day in January loads would exceed supply at some level 

goes from 7 percent to 15 percent, with the maximum 

daily observed energy deficit going from 8,800 to 11,000 

megawatt-days. For this reason, we believe that operating 

the hydropower system across the spring and summer to 

achieve BiOp reservoir levels at the end of August is a 

very important consideration. 

To get through the summer reliably and achieve BiOp 

reservoir levels at the end of August will require either 

extensive purchases from outside the region and/or significant reductions in spill. The availability and cost 

of out-of-region purchases is problematic. Even if the 

power is available, it could be very expensive. With 

significant reductions in spill in conjunction with use of 

emergency hydro, it would be possible to maintain a 

reliable system across the spring and summer and leave 

reservoirs very close to BiOp levels going into the fall. 

This obviously raises questions regarding the impacts 

of significantly reduced spill on survival of downriver 

migrants.

 However, it should also be noted that reducing 

spill also provides some additional flexibility and possible 

value to the hydropower system. Staff has estimated 

preliminarily that by eliminating spill entirely and using 

emergency hydro, with 1944 water conditions the system 

would retain water with an energy equivalent of approximately 5,500 megawatt-months. For 1977 water conditions, this figure drops to about 1,600 megawatt months. 

The bulk of this retained water/energy is available in July 

and August. There are several uses to which this could 

be put. To a limited degree, some of the water could 

be retained in the reservoirs resulting in higher reservoir 

levels at the end of August and more hydropower for use 

in the ensuing fall and winter. Some of the eliminated 

spill could be restored. Or the energy could be generated, 

coincidentally increasing flows in the river. The period 

in which it would be available coincides with the peak 

demand months in the Southwest. Some of this energy 

could be used to help meet the Southwest’s demands and 

would generate much-needed revenues, some of which 

might be used for additional salmon recovery projects. 

As an alternative, it might very well be possible to negotiate energy exchanges with California utilities that help 

the Northwest in the fall and winter and help California 

in the summer. Moreover, additional energy in the market 

this summer would serve to hold down market prices to 

some degree throughout the West.

To maintain reliability, restore reservoir levels, maintain the economic health of the region’s economy and 

its utilities, and not unduly impair salmon recovery goals 

without additional runoff will be extremely difficult and 

will require thoughtful and careful balancing. Additional 

in-region generation and demand reduction will make 

that balancing easier but not easy. The region needs to 

come together on an operating strategy that achieves the 

appropriate balance, and do so soon. 

 Increasing Generation

 Northwest generating capacity development has 

greatly increased following a several-year hiatus. About 

800 megawatts of capacity is expected to enter service 

during the first half of 2001, and an additional 700 megawatts should be available by winter 2001(Figure 1).

About two-thirds of the resource additions shown in 

Figure 1 are gas-fired combined-cycle combustion turbines. Klamath Cogeneration (484 megawatts) is scheduled for service in July 2001. Rathdrum (270 MW) is on 

an accelerated schedule for mid-July completion. Coyote 

Springs 2 (280 megawatts) and the Hermiston Power 

Project (536 megawatts) will follow in summer 2002.
6 Northwest Electricity Markets in 2001

 Figure 1. Pacific Northwest Generating Resource Additions

 Figure 2. West-Wide Generating Resource Additions
Northwest Electricity Markets in 2001 7

Hydropower upgrades, wind and other renewables 

comprise about 18 percent of the 2003 total. Upgrades at 

Lower Baker, Rocky Reach, Cabinet Gorge, Little Falls 

and other hydro projects will supply about 80 additional 

megawatts of capacity and about 60 average megawatts 

of energy. FPL Energy, developer of the 300-megawatt 

Stateline wind project northeast of Pendleton, Oregon, 

expects at least two-thirds of the project to be operating 

by winter 2001. The remainder of Stateline and the 

25-megawatt Nine Canyon wind project near Richland, 

Washington, should enter service during 2002. 

In recent months, several Northwest utilities and industrial consumers have been working to secure and site 

short lead time generating equipment to meet near-term 

reliability needs. More than 500 megawatts of new peaking capacity, some temporary, is planned for 2001 service. 

This capacity will consist of simple-cycle combustion turbines and diesel-generator farms, fuelled by oil or natural 

gas. Temporary diesel farms are already in operation 

at Tacoma (48 megawatts), the Georgia-Pacific Bellingham mill and the Cherry Point refinery (26 megawatts). 

Others will enter service through the remainder of 2001. 

Electricity prices in the region are affected by the 

conditions in the entire interconnected western electricity 

market as defined by the Western Systems Coordinating 

Council (WSCC). Energy balance in the Pacific Northwest would not necessarily imply lower wholesale electricity prices if the rest of the West remained resource 

short. For the WSCC area as a whole, about 6,900 

megawatts of new generating capacity will enter service 

between January and July 2001. These figures include 

about half of the 2,100 megawatts of emergency peaking 

capacity sought in California for summer 2001, an estimate considered reasonable by California observers. An 

additional 1,300 megawatts of new generating capacity 

is scheduled by the end of 2001 (Figure 2). As in the 

Northwest, the majority of new additions are combinedcycle combustion turbines fuelled by natural gas. 

Whether these capacity additions, and others that may 

develop in the WSCC and the Northwest, are adequate to 

balance demands and bring electricity prices down after 

2001 depends on the levels of demand, availability of 

hydroelectricity in future years, and expansion of natural 

gas supplies and pipeline capacity. These issues will be 

addressed in future analyses.

Possibilities for Enhancing Thermal Generation

Additional capacity in the near-term

Sources of additional generating capacity by summer 

2001 include packaged generation, reactivation of idle 

units and operation of distributed emergency generating 

units. Packaged reciprocating engine generator sets and 

gas turbine generator sets are commercially available, 

though increasingly difficult to secure in the near term. 

Capacities range from less than one to about 100 megawatts. Natural gas operation is generally lower cost but 

presents concerns regarding nitrogen oxide emissions. 

Fuel oil provides greater siting flexibility but presents 

problems of sulfur dioxide and particulate matter as well 

as nitrogen oxides. Noise and vibration may be issues in 

both cases. Prospective sites require transmission interconnection capability and fuel supply. The major keys 

to the near-term development of additional generating 

capacity are securing equipment, expeditious permitting 

and overcoming local objections.

Some idle generating capacity might be reactivated 

for near-term operation. Our records show about 130 

megawatts of idle capacity in the region, primarily small 

cogeneration plants associated with the wood products 

industry. Most operate on wood residue, though some 

could use fuel oil or natural gas. The feasibility of 

reactivating these units would have to be determined on 

an individual basis.

Emergency generating units are found in many power 

plants, office buildings, hospitals and at other large commercial and industrial sites. These range in size from a 

few kilowatts to several megawatts. Most are reciprocating 

engine generator sets and some are small gas turbines. 

Most use fuel oil. The principal issue is whether these 

units could be routinely dispatched to serve load without 

compromising their primary function, which is to provide 

emergency backup. Other issues include coordination of 

operation, air quality impacts, noise and vibration. The 

feasibility of using these units for routine generation units 

must be determined on an individual basis. Portland General Electric and Grant PUD have reported some success in 

securing agreements for operation of these facilities.

Permitting

In general, any relaxation of the permitting processes 

and standards for permanent base-load generation would 

have little effect on the electricity problem for this 

summer and fall. Because of 12 to 24-month construction periods, permitting will not affect the amount of 

permanent generation that can be completed this year. 

Moreover, there is a significant amount of generation 

sited and under development. By winter 2003, at least 

2,500 megawatts of permanent capacity will have been 

placed in service in the Northwest since release of the 

Council’s Adequacy and Reliability Study of March 2000. 

This represents over 80 percent of the 3,000 megawatts 

of supply and demand-side resource additions that that 

study found to be needed to restore conventional loss-of-
8 Northwest Electricity Markets in 2001

load probability by winter 2003 (Figure 1). Some believe 

this indicates the siting processes are effective where they 

have been tested by real proposals, mostly in Oregon and 

Washington. However, some in Montana believe that the 

siting process has been a deterrent to development, and 

efforts are being made to streamline future permitting 

processes to reduce unnecessary delays while still maintaining environmental standards.

Permits are in effect for more than 2,600 megawatts of 

combined-cycle capacity not yet under construction. Permitting is under way for an additional 8,500 megawatts 

of combined-cycle plant, including the contested Sumas 2 

project in Washington state. Not all of the permitted sites 

are ideally situated for development, and in not every 

case do developers appear to be actively pursuing permitted projects. However, several of the permitted sites 

are excellent prospects for development. The principal 

impediments in these cases appear to be equipment availability and securing the commitments to buy the output, 

which are required for project financing. 

An exception to these recommendations is permitting 

of the short lead time projects discussed earlier. Expeditious permitting is essential for these options to be effective. But, while permitting must be quick, environmental 

impacts cannot be ignored. Temporary installations have 

a way of becoming permanent. Local opposition can 

contribute to the removal of poorly sited units, as in the 

case of the Bethel plant in Oregon. A basic criterion 

for accelerated permitting would be a time limit on operation, following which the plant could be permitted using 

conventional processes and criteria. Other criteria might 

include compliance with basic “bright-line” environmental criteria, similar to the approach used for accelerated 

California permitting.

 Maintenance schedules

Scheduled maintenance outages were a factor contributing to the high wholesale power prices of June 

2000. Though scheduled outages extending into June 

have been common practice in the Northwest, early snowpack runoff and high Southwest loads in 2000 combined 

to create need for additional June generation. A similar 

situation is likely this year. Because of proprietary concerns, there is no longer overall outage coordination in 

the Northwest. Forecast power prices and futures markets 

are thought to provide sufficient incentive for operators to 

schedule maintenance during lower price periods. However, improved information such as posting of outage 

plans, runoff expectations or near-term price forecasts 

would be desirable. 

A special case for the Northwest is the Columbia Generating Station (CGS) nuclear plant. A 30-day refueling 

outage is scheduled to begin on May 18. While 30-day 

outages have been achieved in the past, this schedule 

will be challenging because of the large number of fuel 

bundle transfers needed for the transition from an 18 to 

a 24-month refueling cycle. Failure to meet the target 

schedule will push the outage further into the anticipated 

high demand period of June. While the schedule could be 

shifted forward to improve the probability that the plant 

will be operating for peak early-summer loads, such a 

move at this time would be disruptive and result in less 

efficient use of fuel. 

Air quality restrictions

Last year, the operations of some Northwest combustion turbines were constrained by air quality restrictions. 

Puget Sound Energy, the operator of about 70 percent 

of Northwest combustion turbine capacity, reports that 

arrangements, including retrofits of additional pollution 

control equipment, have been made that will allow its 

units to operate without interruption this summer.

Reducing Consumption

While the supply of new generating capacity is 

increasing, there is still a significant probability that 

regional demand for energy will not be met. Therefore, 

there is a need, and significant opportunity, for actions 

that will reduce consumption and bring demand closer to 

the available supply. These activities include correcting 

price signals, facilitating voluntary demand reductions, 

and enhancing the acquisition of energy efficiency. 

Getting the Signals Right - Prices

The vast majority of electricity consumers pay electricity prices that are poor indicators of the actual cost of 

providing electricity. This problem has two dimensions: 

first, most retail prices are based on average cost rather 

than marginal cost (the cost of providing an extra unit), 

and second, retail prices vary little or not at all with 

season or time of day. This, in spite of the fact that the 

cost of generating and delivering electricity can vary by 

several hundred percent depending on the time of day 

and season of the year3. Last year’s wholesale prices 

3This pattern is not just a recent phenomenon associated 

with the dramatic developments of the last year in the 

West Coast electricity market. In fact, even two years ago 

hourly prices varied across a 4-to-1 range in the California Power Exchange market. Such variations in electricity value should be expected in a competitive wholesale 

market.
Northwest Electricity Markets in 2001 9

demonstrated even more volatility than we can attribute to 

the cost of generation. 

This disconnect between real time wholesale prices 

and retail prices is a fundamental deficiency in the electricity market and contrasts with the markets for most 

goods and services. For most goods and services, consumers see price variation that reflects supply conditions: 

when oil production is reduced in the Middle East, consumers are not surprised to pay more for gasoline; when 

Florida orange groves suffer frost damage, consumers are 

not surprised to pay more for orange juice; consumers are 

not surprised to pay more for tomatoes in January than 

in July. These price variations give consumers incentives 

to respond by buying substitutes, adjusting the timing of 

their purchases, or by simply buying less of a product that 

is currently more expensive than its value to them.

Without variation in retail prices to reflect supply conditions, electricity consumers lack the incentive to change 

their usage patterns. Even when the marginal kilowatthour is costing the power system 50 cents to a dollar, 

consumers continue to use electricity as if it cost 2.5 to 10 

cents, because that is the cost to them. Thus we might see 

electricity that cost the power system $5.00 being used 

by an industrial customer to produce a product that sells 

for 80 cents (with an operating profit of no more than 20 

cents). It makes sense to industry, given the cost it sees, 

but it makes no sense to the system as a whole. 

Without some remedy to this problem, the system 

will continue to provide too much power (i.e. more than 

customers would buy if they saw the actual cost), and at 

average prices that are higher than necessary. When supplies are particularly tight, unresponsive demand magnifies increases in wholesale prices. 

The simple (at least in theory) prescription is to charge 

marginal cost for customers’ marginal use, with retail 

prices that change hourly and reflect hourly supply conditions. Customers facing such “real time pricing” would 

have proper incentive to reduce or shift use in response 

to current conditions, or to invest in energy efficiency 

measures in response to expected prices over the long run. 

This need not have a disastrous impact on the total bill of 

the customer. The important point here is that marginal 

use should see marginal cost. Rates can be structured 

to accomplish this without raising the price of all use. 

Real time pricing might be a reality in the future, but 

for many reasons (e.g. the limitations of existing meters 

and contracts, customer and regulator acceptance) it is 

not a realistic option for many customers today. Some 

regional utilities and regulators are already exploring rate 

structures that include or approximate real time pricing. 

Broad development and adoption of such rate structures 

would go a long way toward creating an efficient electricity market that avoids many of our current problems.

Demand Management

In the meantime, there are at least partial remedies that 

can be put in place quickly; in fact, we’ve seen significant 

progress in the last few months and more progress seems 

possible. These remedies can be separated into three 

broad categories: 1) voluntary curtailment, which reduces 

electricity use by reducing the level of comfort or services 

(e.g. lighting levels, indoor air temperature or industrial 

production); 2) demand shifting, which does not necessarily reduce total electricity use but changes its timing; 

and 3) efficiency improvements, which reduce electricity 

use but maintain the same level of comfort or service. 

All three categories of reductions can be appropriate and 

useful responses to tight supply conditions such as the 

region faces this year. All three responses are reduced 

when price signals are missing or distorted. In general, 

voluntary curtailment and demand shifting can be put in 

place more quickly. Energy efficiency may take longer to 

implement, but efficient equipment continues to provide 

savings throughout its life.

The term “demand management” is used to refer to 

programs designed to achieve either voluntary curtailment or demand shifting. These two approaches are discussed together in this section because demand shifting 

is essentially curtailment with a compensating increase 

in use at a more economical time, and because similar 

incentives apply to both. The problem facing the Northwest this year is primarily an energy problem. This 

means that actions that actually reduce demand are most 

beneficial. However, there remain differentials between 

peak period and off-peak period market prices. Consequently, demand shifting can reduce costs and help 

control peak period prices. 

In the absence of efficient price signals, utilities 

are developing an assortment of “second best” demand 

management programs. The programs are designed to 

achieve responses similar to those expected from efficient 

prices. Most of them pay customers for reducing load, 

instead of charging the marginal cost of serving load. If 

the customer is willing to reduce load for a payment that 

is less than the marginal cost of providing power, the 

customer, the utility and the rest of its customers can all 

be better off. The main advantage of these mechanisms, 

compared to real time prices, is that these mechanisms 

are available now, when there is a critical need, and they 

provide reasonably predictable results once they are in 

place. There are disadvantages, too; these mechanisms 

require negotiation and administration, creating transac-
10 Northwest Electricity Markets in 2001

tions costs that make it necessary for utilities to limit the 

number of customers who can participate.

Types of demand management mechanisms

These mechanisms can be put in three broad categories. The first is traditional interruptible contracts, 

which offer the customers a reduction in electricity price 

in exchange for the utility’s right to interrupt service 

under specified conditions. Most of these contracts were 

originally designed to provide the option of a quick and 

certain reduction in load to protect system stability, and 

were not expected to be exercised often. 

Interruptible contracts appear to have a continuing role 

in supporting the system’s stability, but it may well be 

more difficult to recruit participants in the future, now 

that actual exercise of the interruption is recognized as a 

real possibility.

The second category includes mechanisms that are 

flexible, intended to be exercised multiple times, responding to recurring supply conditions. They were originally 

designed to respond to limited supply or high price conditions expected to last for hours at a time, but they can be 

applied to more extended shortages such as this year’s. 

These mechanisms involve an offer made by a supplier to 

pay for load reductions on a specified day, for specified 

hours. Customers who are willing to reduce their load in 

the specified period respond, the supplier notifies customers whose offers are accepted, and the process repeats 

whenever the supplier needs reductions. Examples of this 

category are:

• B.C. Hydro’s Price Dispatched Curtailment program

• Demand exchange programs offered by Bonneville, 

Portland General Electric, PacifiCorp and Snohomish 

PUD

• Avista Utilities’ program, an open offer of a fixed price 

for 24-hour blocks of load reductions

These demand exchange and similar mechanisms will 

be useful even in years when supply is not so limited as 

it is this year. Even in a year with generally adequate 

supply, there are likely to be short periods when the balance of demand and supply is tight, and customers might 

very well be willing to reduce loads for compensation that 

is less than the marginal cost of supply.

The third demand management category includes 

mechanisms that have been negotiated on a one-time 

basis, responding to this year’s persistent supply problem, 

and are expected to last for months. These negotiations 

generally have resulted in reductions in loads for the rest 

of the fiscal or calendar year. Reductions after that would 

be the subject of new negotiations. Examples of these 

negotiated reductions are the agreements between:

• Bonneville and its direct service industries customers

• Springfield Utility Board and Globe Metallurgical Inc.

• Proposed agreements between Idaho Power and a 

number of irrigation customers

• Chelan County PUD and industrial customers

• Grant County PUD and industrial customers

Longer-term buyouts, lasting for several months, are 

useful in a year like this one, but they have significant 

impacts on the local economy. We wouldn’t expect to see 

these mechanisms used in more normal years.

Potential load reductions from these mechanisms

Programs in the last two categories are very new. 

They have delivered useful amounts of load reduction, 

and offer promise of more. For example, between June 

2000 and March 2001 the aluminum industry loads on 

Bonneville have been reduced by about 1,300 megawatts. 

The reduced aluminum industry consumption has been 

available to serve other loads and reduce emergency operation of the hydro system. We can hope that more customers will be able to participate as utilities streamline 

and extend the programs, but we can’t say what the 

number of participating customers might be ultimately. 

We can expect customers to think of more ways to reduce 

load, with more time to think and perhaps invest in equipment that makes reductions possible, but any quantitative 

estimate is at best a very rough one. 

Keeping these limitations in mind, we could make 

such an estimate by applying the percentage reduction in 

peak load achieved by PGE’s Demand Exchange (4 to 

5 percent) to an assumed regional peak load of 36,000 

megawatts. This suggests the additional ultimate potential could be in the range of 1,440 to 1,800 megawatts 

beyond the aluminum industry reductions noted above. 

We might not reach this potential this summer, because 

PGE is ahead of most utilities in the development of 

its program, but in the longer term, this potential could 

even be conservative as more customers are included in 

programs.

The more important lesson to take from the early 

experience is not how much total reduction we may be 

able to get, but that it’s very likely that we can get 

more than we have so far. These programs are based 

on voluntary agreements; in contrast to rolling blackouts, 

no one is forced to go without power. We should try 
Northwest Electricity Markets in 2001 11

to make the programs available to as many customers as 

possible.

Efciency Improvements 

The Northwest has relied heavily on this form of 

demand reduction to provide a significant portion of the 

new resources required. The Council estimates that since 

1980, more than 1,400 average megawatts of energy 

efficiency has been acquired. Unfortunately, many of 

the utility programs responsible for this accomplishment 

were ramped down significantly in the late 1990s in the 

face of uncertainty regarding deregulation. Just like their 

supply-side counterparts, many of these programs and the 

infrastructure to support them take significant amounts 

of time to develop. However, there are some actions 

that can be taken to quickly accelerate existing programs 

and provide near-term conserved energy. The improved 

efficiency from these actions will continue to provide 

value in the future.

The following is a list of some of the most promising 

areas for quick-response energy efficiency programs. 

Combined, they represent 224 average megawatts, or 

almost the annual output of a new combined cycle gasfired combustion turbine:

• Replace Existing Incandescent Bulbs and Fixtures with 

Compact Fluorescent Bulbs and Fixtures: Compact 

fluorescent bulbs produce the same amount of light 

using just 25 to 30 percent of the electricity used 

by standard incandescent light bulbs. If each of the 

roughly 4.5 million households in the region replaced 

just three incandescent light bulbs with compact fluorescent bulbs it is estimated that the region could save 

100 average megawatts or enough to power the City 

of Springfield, Oregon for a year. Consumer awareness of electricity shortages and prices has already 

begun to stimulate retail sales of these products. In 

addition, many regional utilities are already moving 

to further encourage this activity. PacifiCorp, PGE, 

Bonneville and other regional utilities have joined 

a regional lighting initiative through the Northwest 

Energy Efficiency Alliance’s Energy Star marketing 

program to offer rebate coupons to their customers.

• Upgrade Existing Commercial Building Lighting Systems: Many of the region’s existing commercial 

buildings can be cost-effectively retrofitted with the 

same energy efficient lighting technologies that are 

now required by new buildings codes. Replacing 

older, less efficient lamps and ballasts in overhead 

fluorescent lighting with modern, high quality lamps 

and electronic ballasts can reduce energy use by as 

much as 30 to 50 percent. There are additional 

energy savings from changing out old, incandescent 

display lighting with newer more efficient sources. 

Retrofits such as these made up much of the savings 

accomplished by the utility programs in the 1990s. 

Yet many buildings still use the older, less efficient 

and lower quality lighting systems. If just 10 percent 

of the region’s commercial buildings reduced their 

lighting energy use by 30 percent, the region could 

save an average of 45 megawatts4, or enough to 

energy to supply the city of Redmond, Washington, 

for a year.

• Tune Up Heating, Ventilating and Air Conditioning 

Systems in Existing Commercial Buildings: Complex 

commercial buildings, just like modern automobiles, 

should have regularly scheduled tune ups to make 

sure their heating and cooling equipment is operating 

properly and that the controls are calibrated. Experience from utility sponsored programs in this and 

other regions across the country have shown that 

such “tune ups” or “re-commissioning” can reduce 

electricity use by 10 to 20 percent, without equipment replacement. In this initiative, particular attention should be focused on making sure that existing 

“economizer” cooling equipment is operating properly. If just 5% of the region’s existing commercial 

floorspace could be tuned-up, we could reduce 

regional electricity consumption by 22 average megawatts, or enough energy to supply Oregon City, 

Oregon, for a year.

• Replace Existing Electric Motors: Motors are the 

single largest consumer of electricity in the industrial 

sector using roughly 60 percent of the energy used by 

non-direct service industries. The new generation of 

“premium efficiency” electric motors are 2 to 6 percent 

more efficient than those produced just 10 years ago, 

and as much as 10 percent more efficient than the 

motors currently installed in many facilities. When an 

existing large motor fails, it is now common practice 

in industry to refurbish or “rewind” rather than replace 

the motor with a new model. Research has shown 

that “rewinding” electric motors if not done properly 

degrades their energy efficiency. Given current electric 

rates, it will make economic sense in some circumstances to replace functional existing electric motors 

during scheduled downtime with new, premium efficiency motors. Replacing 10 percent of failed or existing electric motors with “premium efficiency” motors 

could save the region 46 megawatts; enough to power 

the City of Auburn, Washington, for a year.

 4Based on an average reduction of 0.5 watts per square 

foot off a base usage of 1.7 watts per square foot; 3,874 

hours per year, average space heat interaction of 10 percent (increased space heat used to compensate for reduction in waste heat from lights) and 2.27 billion square feet 

of floor space total.
12 Northwest Electricity Markets in 2001

• Retire Second Refrigerators: Approximately one out of 

five homes in the region has two refrigerators. The 

average 10-year old refrigerator uses twice the electricity that new Energy Star models of the same size 

use, and the average 20-year refrigerator uses three 

times the electricity that new models use. Initiating a 

regional program to retire and properly recycle these 

refrigerators could result in significant regional savings. Some of these “second refrigerators” now are 

being used by consumers because their primary refrigerators are too small. This initiative should also offer 

a “two-for-one” trade in to encourage consumers to 

retire both their old refrigerators if they replace them 

with a new, and perhaps larger, but much more efficient Energy Star model. Every 10 percent reduction 

in the number of the region’s “second refrigerators” 

could reduce the demand for electricity by approximately 5 to 7 average megawatts or enough electricity 

to supply half of the city of Cheney, Washington, for 

a year.

• Accelerate Replacement of Existing Clothes Washers:

New Energy Star clothes washers use 35percent less 

electricity than models just meeting current federal 

minimum standards and 45 percent less than those 

built a decade ago. In addition, the new Energy Star 

models typically use 35 to 45 percent less water, placing fewer demands on water and wastewater facilities. 

Initiating programs to promote the “early retirement” 

and recycling existing clothes washers could save substantial amounts of both energy and water. If just half 

of the new clothes washers sold in the region over the 

next twelve months meet the Energy Star standards, 

we can reduce regional electricity demand by about 

5 average megawatts or enough to power the city of 

Weiser, Idaho, for a year. In addition, the region 

would reduce water use by 625 million gallons.

The Value of Public Leadership

The approaches mentioned above essentially rely on 

utility programs and economic incentives to achieve reductions and shifts in demand. The value of public officials 

in educating the public about the nature and seriousness of 

the current situation and the contribution they can make to 

easing the power crunch should not be overlooked. Many 

of the actions that can help with the situation involve relatively minor changes in personal and corporate behavior - 

reducing thermostat settings slightly in the winter, reducing 

unnecessary lighting, turning off unused appliances and 

office equipment, slightly higher summer thermostat settings in air-conditioned buildings, to name a few. The Governors of Oregon and Washington have been particularly 

aggressive in calling for that kind of personal response. 

While it is difficult to tell with precision what quantitative 

impact those calls have had, there clearly has been some. 

It is also clear from observation that the message has not 

gotten through to everyone. Public leaders should continue 

to communicate the importance of personal and corporate 

action and lead by example.

Controlling the Market

The extremely high electricity prices being experienced in the West, while a result of very unusual conditions, are nevertheless having significant effects on some 

parts of the regional economy. These effects can be 

expected to grow over the rest of this year as the wholesale price increases work their way further down into the 

economy through increases in retail prices. Some businesses have already closed because of high energy prices, 

creating increased unemployment and loss of income. 

In California, utilities teeter on the edge of bankruptcy. 

Low-income families are likely to be especially hard hit 

as retail prices begin to respond to the extremely high 

wholesale prices. 

Concerns about the damage high prices are doing to 

the economy have led some to call for the Federal Energy 

Regulatory Commission (FERC) to reregulate wholesale 

power prices above a certain level throughout the West. 

They believe that temporary reregulation of wholesale 

electricity prices can be designed to allow a fair rate of 

return and at the same time to send a strong price signal 

that will encourage the development of more generation 

and cost-effective conservation. These parties argue, as 

well, that the economic impacts of recent extremely high 

prices on Northwest families, farms and industry are 

unacceptable and create unjustified profits for relatively 

few companies.

Others are strongly opposed to price controls. In 

general, economists and agencies that are charged with 

creating workable and efficient markets, such as the Federal Energy Regulatory Commission, are not enthusiastic 

about price controls. Opponents of price controls claim 

that they have been ineffective in a market setting, and 

that they tend to blunt the price signals that lead to market 

adjustments and are often circumvented by market participants. In addition, there are serious questions about our 

ability to effectively implement consistent price controls.

Regardless of the outcome of this debate, significant 

price increases are likely to occur. In view of the 

expected increase in electricity prices, state and local 

leaders should directly address the impacts on lowincome consumers by expanding the scope and funding of 

existing programs. The impact on local business should 

be partially alleviated by publicizing and encouraging 

access to some of the types of demand management programs described above.