Revised Draft

Forecast of Electricity Demand 

for the 5th Pacific Northwest 

Conservation and Electric Power Plan

May 13, 2003
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Introduction and Summary

A twenty-year forecast of electricity demand is a required component of the Council’s 

Northwest Regional Conservation and Electric Power Plan. 1 Understanding growth in 

electricity demand is, of course, crucial to determining the need for new electricity 

resources and helping assess conservation opportunities. The Council has also had a 

tradition of acknowledging the uncertainty of any forecast of electricity demand and 

developing ways to reduce the risk of planning errors that could arise from this and other 

uncertainties in the planning process.

Electricity demand is forecast to grow from 20,080 average megawatts in 2000 to 25,423 

average megawatts by 2025 in the medium forecast. The average annual rate of growth 

in this forecast is just less than 1 percent per year. This is slower demand growth than 

forecast in the Council’s 4th power plan, which grew at 1.3 percent per year from 1994 to 

2015.

The slower demand growth primarily reflects reduced electricity use by the aluminum 

industry and other electricity intensive industries in the region. Forecasts of higher 

electricity and natural gas prices will fundamentally challenge energy intensive industries 

in the region.

The medium case electricity demand forecast means that the region’s electricity needs 

would grow by 5,343 average megawatts by 2015, an average annual increase of 214 

average megawatts. As a result of the 2000-01 energy crisis, the 2003 demand is 

expected to be nearly 2000 average megawatts lower than in 2000, making the annual 

growth rates and megawatt increases from 2003-2025 higher than from the 2000 base. 

The annual growth rate from 2003 to 2025 is 1.5 percent per year, with annual megawatt 

increases averaging 330.

Compared to the 2015 forecast of demand in the Council’s 4th power plan, the 5th plan 

forecast is 3,000 average megawatts lower. Nearly, two thirds of this difference is due to 

lower expectations for the region’s aluminum smelters.

The most likely range of demand growth (between the medium-low and medium-high 

forecasts) is between 0.4 and 1.50 percent per year. However, the low to high forecast 

range recognizes that growth as low as -0.5 percent per year or as high as 2.4 percent per 

year is possible, although relatively unlikely. Table 1 summarizes the forecast range.

 

1

 Public Law 96-501, Sec. 4(e)(3)(D)
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Table 1

Demand Forecast Range

(Actual) Growth Rates

2000 2015 2025 2000-2015 2000-2025

Low 20,080 17,489 17,822 -0.92 -0.48

Medium Low 20,080 19,942 21,934 -0.05 0.35

Medium 20,080 22,105 25,423 0.64 0.95

Medium High 20,080 24,200 29,138 1.25 1.50

High 20,080 27,687 35,897 2.16 2.35

Forecasting Methods

The approach to the demand forecasts is significantly different from previous Council 

plans. For this plan, the Council has not used its Demand Forecasting System. Instead 

there are three separate approaches to the forecast in terms of methods and relationship to 

the Council’s 4th power plan. The methods differ for (1) the range of long-term nondirect service industry (non-DSI) forecasts from low to high, (2) for a monthly near-term 

medium case forecast, and (3) for a forecast of aluminum smelter and other direct service 

industry (DSI) demand. 

The non-DSI forecasts generally rely on the forecasts from the 4th power plan for their 

long-term demand trends. The decision to use the 4th power plan forecast trends was 

based partly on an assessment of the accuracy of those forecasts over the five or six years 

since they were done.2 The total demand forecasts tracked actual loads very closely 

between 1995 and 2000. The average percentage error in the forecast of electricity 

consumption for those years has been less than one half of a percent. Figure 1 illustrates 

actual consumption compared to the medium, medium-low and medium-high forecasts 

through 2000. Figure 1 also illustrates the ability of the model to simulate the period 

before 1995 when actual values of the main forecast drivers are used. 

The forecasts for individual consuming sectors have also been quite accurate since the 

1995 forecasts were done. The level of residential consumption was overforecast by an 

average of 0.6 percent. Commercial consumption was underforecast by an average of 0.9 

percent, and industrial consumption, excluding DSIs, was overforecast by an average of 

3.6 percent. Since there was little evidence that the long-term forecasts were departing 

seriously from actual electricity consumption, the Council decided to continue to rely on 

its earlier forecast trends for non-DSI electricity demand. 

The medium case non-DSI forecast is developed in two stages. The first stage is a nearterm monthly forecast of demand recovery from the recent energy crisis. The second 

stage is a long-term forecast of demand trends from 2005 to 2025. 

 

2

 Northwest Power Planning Council. “Economic and Electricity Demand Analysis and Comparison of the 

Council’s 1995 Forecast to Current Data.” September 2001, Council Document 2001-23. 

http://www.nwcouncil.org/library/2001/2001-23.htm
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Figure 1

Demand Forecast Versus Actual Consumption of Electricity

10500

12500

14500

16500

18500

20500

22500

1981198319851987198919911993199519971999

Years

Average Megawatts

ACTUAL

Medium High

Medium

Medium Low

During late 2000 and 2001 electricity demand decreased dramatically in the region due to 

the electricity crisis, large increases in retail electricity rates, and an economic recession. 

The Council analyzed the components and causes of the 2000-2001 decline in electricity 

consumption in its assessment of the outlook for winter 2001-2002 electricity adequacy 

and reliability. 3 As illustrated in Figure 2, nearly 60 percent of the reduction was due to 

closing down aluminum smelters, which make up the bulk of the DSI category. 

Therefore, a large part of the total medium forecast of demand recovery depends on 

specific assumptions about the return to operation of aluminum and other large industrial 

loads that were either bought out or shut down during 2001. The medium case forecast to 

2005 addresses the recovery from this starting condition. 

The medium case forecast of non-DSI demand recovery depends on assumptions about 

recovery from the economic recession and the effects of recent retail electricity price 

increases, although these effects are not modeled in any formal way. In general, the 

effects of higher retail electricity prices are assumed to dampen the effect of economic 

recovery on electricity use and slow the recovery of electricity demand. By 2005 nonDSI electricity demands are assumed to have nearly returned to a non-recession level, but 

that demand is lower than the 4th power plan forecast due to some assumed permanent 

effects of higher electricity prices, as well as lasting efficiencty improvements achieved 

during the crisis. 

 

3

 Northwest Power Planning Council. “Analysis of Winter 2001-2002 Power Supply Adequacy”. 

November 2001. Council Report 2001-28. http://www.nwcouncil.org/library/2001/2001-28.pdf
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Figure 2

Components of a 20 Percent Load Reduction from July 2000 to July 2001

DSI

58%

Buyouts

5%

Shutdowns

7%

Other 

Response

30%

The near-term medium forecasts are done on a monthly basis through 2005. The monthly 

forecasts through 2005 are done as electricity loads to facilitate tracking the forecast 

against actual load data as it becomes available. After 2005 the forecast is presented as 

electricity sales and is comparable to the range forecasts and to previous Council demand 

forecasts.

The range of long-term non-DSI forecasts is developed for the years following 2005. 

These four forecasts, as well as the medium case extension beyond 2005, depend on the 

growth rates of the corresponding forecasts in the 4th power plan. The 2005 starting 

points for the range forecasts are estimated by applying 4th plan low to high case growth 

rates to an estimate of actual electricity demand in 2000 instead of the 4th plan forecasts 

for 2000. However, the relative pattern of growth for each case is adjusted to resemble 

the pattern near-term medium case decreases in 2001 and recovery to 2005. After 2005, 

low to high case annual growth rates from the 4th plan were applied to the respective 

range of cases. This approach results in a narrower range of forecasts than the 

corresponding years forecasts in the 4th power plan.

The long-term forecasts should be viewed as estimates of future demand, unreduced for 

conservation savings beyond what would be induced by consumer responses to price 

changes. The Council has referred to these forecasts as “price effects” forecasts in the 

past. The shift from actual consumption to the price effects forecast is made in 2001. In 

the medium case, the only sector with any significant programmatic conservation by 

2001 in the 4th power plan was the residential sector. Residential sector consumption in 
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2001 has 191 average megawatts of programmatic conservation savings added to 

demand. This makes the decrease in residential consumption appear smaller in the 

forecast than actual consumption decreases are likely to be for 2001. Similar adjustments 

affect the higher growth cases for the other sectors as well.

The forecast of electricity demand by the region’s aluminum smelters and the few other 

remaining industrial plants that were traditionally served directly by the Bonneville 

Power Administration (DSIs) are discussed separately below. The forecast of aluminum 

smelter electricity use is an exception to reliance on the 4th plan forecast trends. Both the 

method of forecasting and the results are significantly different from the 4th power plan.

Demand Forecast

The demand forecasts are presented in this section. The medium-term monthly forecasts 

are presented in the form of monthly “load” forecasts. That is, the values include 

transmission and distribution losses. The long-term forecasts are presented as electricity 

sales, or electricity consumption at the end-use level, and therefore exclude transmission 

and distribution losses. The long-term forecasts of electricity demand are developed for 

individual consuming sectors such as residential, commercial, and industrial. The longterm forecasts are directly comparable to the demand forecasts presented in the 4th power 

plan.

The forecast of demand for electricity by aluminum smelters is treated separately from 

the non-DSI demand. This reflects the large amount of electricity required by these 

plants combined with a growing uncertainty about their future operation in the region.

Non-DSI Forecasts

Near-Term Monthly Non-DSI Load Forecast

Figures 3a and 3b illustrate how the near-term forecasts of non-DSI loads are designed to 

track recovery back toward the forecast trends from the Council’s 4th power plan. In 

Figure 3a the upper line is the 4th power plan trend forecast converted to electricity loads 

with a monthly pattern added. The lower line shows the near-term monthly forecast of 

loads. The dashed vertical line separates actual monthly load data from the forecast. The 

recovery may be more clear in the corresponding annual numbers shown in Figure 3b.

When the Council first developed a near-term forecast of load recovery in October 2001 

it was expected that non-DSI loads would recover to near the 4th plan forecast levels by 

2004. This is no longer the case, as shown in Figures 3a and 3b. There are two 

substantial reasons for the changes to the near-term load forecast since the earlier 

assessment. First, the anticipated rate of economic recovery has been slower than 

expected. Second, energy prices, which fell substantially in 2002, have increased again 

in 2003. Some of the increase is due to temporary conditions including strikes in the oil 

industry of Venezuela, concerns about the war in Iraq, a cold winter in the eastern part of 

the country, and low runoff forecasts for the Pacific Northwest. However, other 

contributors to high energy prices may be indicative of longer-term trends. These include 

the reduced growth in natural gas supplies in spite of significant drilling activity and 
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continued high retail prices for Bonneville’s customers and the customers of investorowned utilities as well.

As shown in Figure 3b, instead of recovering to the long-term trend forecast from the 4th

power plan by 2004, the revised annual non-DSI load forecast remains below the 4th plan 

forecast in 2005. This difference, which amounts to 929 average megawatts, is 

considered to be a permanent reduction in electricity demand, and affects the long-term 

forecast as well. The reductions are focused in the industrial sector, where energy 

intensive businesses are vulnerable to the large price increases the region has suffered 

since 2001.

Figure 3a

Comparison of Monthly Near-Term Forecast to the 4th Power Plan

12000

14000

16000

18000

20000

22000

24000

2000 2001 2002 2003 2004 2005

Average Megawatts

4th Plan

Draft 5th
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Figure 3b

Comparison of Annual Near-Term Forecast to the 4th Power Plan

10000

12000

14000

16000

18000

20000

22000

1999 2000 2001 2002 2003 2004 2005

Average Megawatts

5th Plan Non-DSI

4th Plan Non-DSI

Long-Term Forecasts of Non-DSI Demand

The range of long-term forecasts of total non-DSI electricity sales is shown in Figure 4. 

In the medium forecast, non-DSI electricity consumption grows from 17,603 average 

megawatts in 2000 to 24,464 average megawatts by 2025. This is an increase of 1.33 

percent, and 275 average megawatts, per year from 2000 to 2025. These growth 

indicators are lowered somewhat by the electricity crisis and recession in 2000-01. From 

2005 to 2025 the average annual growth rate is 1.43 percent per year, with an average 

annual increase in consumption of 300 average megawatts.

Figure 4 illustrates how the 4th plan demand forecast and the draft near-term and longterm forecasts for the 5th power plan compare. The near-term forecast reflects the 

currently depressed electricity demand and then merges into the medium forecast. The 

other forecasts in the range appear as dashed lines that extend from 2005 to 2025. The 4th

plan forecasts appear as solid lines that extend to 2015. Historical actual weather 

adjusted sales appears as a dotted line through the year 2000.

The range of forecasts indicate that actual future demands should fall within plus or 

minus 15 percent of the medium forecast in 2025 with fairly high probability. This is 

reflected in the medium-low to medium-high forecast range in Table 2. However, under 

more extreme variations in circumstances they could vary by 30 to 40 percent from the 

medium forecast, as shown by the low to high forecast range.
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Figure 4

Forecast Total Non-DSI Electricity Sales Compared to 4th Plan Forecasts

10000

15000

20000

25000

30000

35000

40000

198119841987199019931996199920022005200820112014201720202023

4th Plan Range

Actual

5th Plan Range

5th Plan Medium

Table 2

Non-DSI Electricity Sales Forecast Range

Growth Rates

2000 2015 2025 2000-15 2000-25

(Actual)

Low 17603 17489 17822 -0.04% 0.05%

Medium Low 17603 19482 21474 0.68% 0.80%

Medium 17603 21147 24464 1.23% 1.33%

Medium High 17603 23000 27937 1.80% 1.86%

High 17603 26187 34397 2.68% 2.72%

Maintaining growth rates from the 4th power plan’s demand forecasts after 2005 

implicitly assumes that the underlying assumptions remain about the same in terms of 

their effects on growth in electricity demand. The main driving assumptions in the 4th

power plan demand forecasts were economic growth, fuel price assumptions, and 

electricity price forecasts.

We have not attempted to develop a new economic forecast. However, the 4th plan 

economic forecasts were checked for obvious deviations from actual values since the 

forecasts were developed in 1995.4 The most aggregate determinates of demand are, 

population, households, and total non-farm employment. The number of households is 

 

4

 Council Document 2001-23, sited above.
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the key driver of residential electricity demand growth. Actual household growth has 

followed the medium household forecast from the 4th power plan. Population growth 

also tracked the medium forecast until 2000 Census data showed an upward revision in 

regional population. The new population count placed 2000 regional population between 

the medium and medium-high forecasts.

Employment forecasts are more sensitive to economic conditions than population and 

households. The period of sustained rapid growth in the national and regional economies 

during the late 1990s exceeded the 4th plan forecast assumptions, which were 

representative of longer-term sustained growth possibilities. Non-manufacturing 

employment, which drives the commercial sector forecasts has been closer to the 

medium-high forecast through 2000, although state forecasts of non-manufacturing 

employment that were available when the assessment was done show its growth 

moderating and moving back toward the medium forecast. The current slowdown in 

economic activity likely will have moved non-manufacturing employment back to the 

medium or below.

The effects of robust economic growth in the late 1990s are even more apparent in 

manufacturing sector employment. Actual manufacturing employment moved well 

above the medium-high forecast in 1997 and 1998 when there was a boom in 

transportation equipment employment (i.e. Boeing). State forecasts available in mid2001 expected manufacturing employment to return to medium forecast levels for 2001-

2003. With the development of a recession in the fall of 2001 the manufacturing 

employment has probably fallen below medium forecast levels. There were some 

offsetting errors within the individual manufacturing sectors. In particular, electronic and 

other electrical equipment employment has been above the medium-high case, while 

paper and allied products has been below the medium-low.

Future natural gas prices are expected to be higher in this power plan than in the 4th plan. 

Table 3 below compares 4th plan gas price forecasts for 2015 to this plan’s draft natural 

gas price forecasts. The medium natural gas price forecast for this plan in 2015 is 

between the medium high and high case in the 4th plan, and the revised 2015 medium 

forecast is 38 percent higher than the 4th plan medium forecast. Based on the Council’s 

Load Forecasting Models, this would imply that electricity demand might be increased by 

3 to 4 percent over the 4th plan forecasts if nothing else changed.

Table 3

Natural Gas Price Forecasts for 2015

(2000 $ Per Million Btu)

4

th Plan Forecast 5th Plan Draft Forecast

Low $ 1.85 $ 2.55

Medium Low $ 2.16 $ 2.90

Medium $ 2.47 $ 3.40

Medium High $ 3.09 $ 3.60

High $ 3.71 $ 3.70
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However, the effects of higher gas prices may be offset by higher electricity prices. It is 

difficult to compare retail electricity prices between the two forecasts because the old 

price forecasting models are no longer appropriate for price forecasting in a partially 

restructured electricity market. The new price model addresses only wholesale electricity 

prices. Future retail prices will reflect both wholesale market prices and utility-owned 

resource costs if the system remains mixed, as it is currently. It is clear that higher 

natural gas prices will have an effect on electricity prices, both through the cost of utility 

owned natural gas-fired generation and through the wholesale market price of electricity. 

Higher electricity prices have a larger downward effect on electricity consumption than 

the upward effect that a comparable increase in natural gas prices would have. In the 

end, it isn’t clear whether the changes in natural gas and electricity prices would cause a 

net increase or decrease in electricity consumption.

Sector Forecasts

Total non-DSI consumption of electricity is forecast to grow from 17,603 average 

megawatts in 2000 to 24,464 average megawatts by 2025, an average yearly rate of 

growth of 1.33 percent. The year 2000 is used as the base year for the forecast and 

growth rate calculations. It is a more representative year for examining long-term trends 

in demand than 2001 or 2002 would be. Table 4 shows the forecast for each consuming 

sector in the medium case. Each sector’s forecast is discussed in separate sections below.

Table 4

Medium Case Non-DSI Consumption Forecast

(Average Megawatts)

2000 2005 2010 2015 2020 2025 Growth Rates

(Actual) 2000-25 2000-15 2005-25

Total Non-DSI Sales 17,603 18,433 19,688 21,147 22,742 24,464 1.33 1.23 1.43

Residential 6,724 7,262 7,687 8,230 8,809 9,430 1.36 1.36 1.31

Commercial 5,219 5,453 5,771 6,146 6,556 6,993 1.18 1.10 1.25

Non-DSI Industrial 4,836 4,904 5,397 5,919 6,505 7,150 1.58 1.36 1.90

Irrigation 652 629 641 654 667 681 0.17 0.02 0.40

Other 172 185 191 198 204 211 0.82 0.93 0.66

Residential Sector

Residential electricity consumption is forecast to grow by 1.36 percent per year between 

2000 and 2025. Figure 5 illustrates the range of the residential consumption forecast, 

compared to historical data, and the forecasts from the Council’s 4th power plan. The 

medium case residential demand forecast for 2005 is 161 average megawatts lower than 

the 4th plan forecast for that year. The forecast growth of residential sector use of 

electricity is slightly less than the growth from 1986-1999 of 1.8 percent annually.

The medium residential forecast remains just below the 4th plan medium case. This 

adjustment reflects the fact that the 4th plan slightly overforecast actual residential sales 

between 1995 and 2000, and that there are expected to be some longer-term effects of 

utility and consumer efficiency investments in response to the electricity crisis and high 

prices of the last couple of years. The 2005 residential demand forecast is 161 megawatts 
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lower than the 4th plan forecast for 2005, or a 2.2 percent reduction in the forecast 

consumption level.

Figure 5

Forecast Residential Electricity Sales Compared to 4th Plan Forecasts

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

14000

198119851989199319972001200520092013201720212025

Average Megawatts

4th Plan Range

Actual

5th Plan Range

5th Plan Medium

Although the near-term forecast shows a significant dip in residential consumption in 

2001, the reduction in consumption is dampened significantly by making the adjustment 

to a “price effects” forecast in 2001. That is, the forecasts are intended to reflect what 

demand for electricity would be if new conservation programs are not implemented. The 

consumption levels before 2001 include the effects of conservation programs on 

electricity use, thus reducing consumption. The residential sector sales forecast is the 

only one affected by programmatic conservation in 2001 in the medium case of the 4th

power plan. The adjustment to eliminate the savings from conservation programs 

increased the residential electricity use forecast by 191 average megawatts in 2005.

It should be noted that the draft forecasts presented here have not been adjusted for the 

future effects of new building or appliance codes that have been put into effect since the 

4th plan forecasts were done. These changes in minimum energy efficiency would 

reduce the future “price effects” forecast shown here. The analysis to make these 

adjustments has not been completed at this time.

Commercial Sector

Commercial sector electricity consumption is forecast to grow by 1.18 percent per year 

between 2000 and 2025, increasing from 5,219 to 6,993 average megawatts. Figure 6 

illustrates the forecast. Compared to the 4th power plan forecast of commercial electricity 
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use, the medium case has been adjusted upwards to reflect the fact that there has been a 

slight tendency to underforecast commercial demand since 1995. The draft forecast for 

2005 is 325 average megawatts higher than the 2005 medium forecast in the Council’s 4th

power plan.

Figure 6

Forecast Commercial Electricity Sales Compared to 4th Plan Forecasts

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

198119851989199319972001200520092013201720212025

Average Megawatts

4th Plan Range

Actual

5th Plan Range

5th Plan Medium

Comments in the residential section about the effects of new building and appliance 

efficiency codes apply to the commercial sector as well. In the medium commercial 

sector forecast, there is no adjustment made for conservation programs in shifting to the 

medium price effects forecast in 2001. The conservation program adjustment does affect 

the starting point for the medium-high and high forecast in 2005. It also affects the 4th

plan forecast shown in the graph. The transition from a “sales” forecast to a “price 

effects” forecast is apparent in the high case, the upper line in Figure 6. The near-term 

forecast dip in the medium case is the expected effect of recent price changes and 

economic recession. 

The growth forecast for the commercial sector is for a significantly slower growth than in 

the past. Between 1986 and 1999 commercial electricity use grew at 3.1 percent per year. 

Therefore, the forecast growth rate of 1.2 percent represents a big slowdown in 

commercial growth. This slowdown was present in the 4th power plan forecasts as well. 

But there has not been a significant underforecasting trend since the 4th plan forecast of 

commercial demand was done even though the region has experienced a robust growth 

cycle during these years. Figure 7 shows the forecast compared to actual sales for 1994 

through 1999. Although the actuals for 1995 and 1999 are above and at the medium-high, 

respectively, the other four years are at or below the medium case forecast.
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Figure 7

4

th Plan Commercial Forecast Performance

3800

4000

4200

4400

4600

4800

5000

5200

5400

1994 1995 1996 1997 1998 1999 2000

Average Megawatts

MH

ML

Medium

Actual

Several factors could help explain the forecast of slower growth of commercial electricity 

use. The underlying forecast of employment growth in the non-manufacturing sectors is 

significantly slower than historical growth. This alone could account for much of the 

decreased electricity demand growth forecast. In addition, the demand forecasting model 

accounts for building vintages and efficiency. As newer, more energy efficient, buildings 

that have been subject to building efficiency codes enter the stock and replace older 

buildings the electricity use per square foot of buildings will tend to decrease. Such 

factors may account for the decreased rate of growth of commercial electricity use, but 

the Council continues to evaluate the commercial forecasts to see if these forecasts might 

understate future commercial electricity needs. The Council would like to hear the views 

of utilities and the public on this issue.

Non-DSI Industrial Sector

Industrial electricity demand is difficult to forecast with much confidence. Unlike the 

residential and commercial sectors where energy use is predominately for buildings, and 

therefore reasonably uniform and easily related to household growth and employment, 

industrial electricity use is extremely varied. Further, the use tends to be concentrated in 

a relatively few very large users instead of spread among many relatively uniform users.

The direct service industries (DSIs) of Bonneville are treated separately in this discussion 

because this hand-full of plants (mainly aluminum smelters) accounts for nearly 40 

percent of industrial electricity use. In addition, the future of these plants is highly 

uncertain. Large users in a few industrial sectors such as pulp and paper, food 
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processing, chemicals, primary metals other than aluminum, and lumber and wood 

products dominate the remainder of the industrial sector’s electricity use. Many of these 

sectors are declining or experiencing slower growth. These traditional resource based 

industries are becoming less important to the regional electricity demand while new 

industries, such as semiconductor manufacturing are growing faster.

Non-DSI industrial consumption is forecast to grow at 1.58 percent annually from 2000 

to 2025 (see Figure 8). Electricity consumption grows from 4,836 average megawatts in 

2000 to 7,150 in 2025. The medium-high and medium-low forecasts are about 20 and 30 

percent higher and lower than the medium forecast, respectively. This reflects the greater 

uncertainty in forecasting the industrial sector’s electricity demand. In addition, the 

actual industrial consumption data is becoming more difficult to obtain as some 

consumers gain access to electricity supplies from independent marketers instead of their 

local distribution utility who must report their electricity sales. 

The near-term forecast reflects a severe reduction of consumption in 2001 and 2002. 

Higher electricity prices are expected to continue to repress industrial electricity use. 

2005 demand remains significantly, 1,022 average megawatts, lower than the 2005 

forecast for 4th power plan.

Figure 8

Forecast Non-DSI Industrial Electricity Sales Compared to 4th Plan Forecasts

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

198119841987199019931996199920022005200820112014201720202023

Average Megawatts

4th Plan

History

5th Plan Range

5thPlan Medium

Irrigation and Other Uses

Irrigation and other uses are relatively small compared to the residential, commercial and 

industrial sectors. Irrigation has averaged about 640 average megawatts between 1986 
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15

and 1999 with little trend discernable among the wide fluctuations that reflect year-toyear weather and rainfall variations. Other includes streetlights and various federal 

agencies that are served by Bonneville. It is relatively stable and averaged about 180 

megawatts a year between 1986 and 1999. 

Unlike most other sectors in the draft forecast, the irrigation forecast range has been 

changed substantially, although due to its small size it has little effect on total demand. 

Analysis showed that the average irrigation use over the past 20 years was substantially 

lower than where the medium forecast in the 4th plan started. The 2005 consumption was 

lowered to 629 average megawatts in the draft forecast, compared to a 4th plan value of 

700 average megawatts in that year. The forecast medium case, shown in Figure 9, 

includes very little growth, as has been the case for the last 10 or more years. The range 

considers a high case growth of 0.7 percent a year and the low case considers that 

irrigation electricity use could decline by 0.8 percent annually. Substantial expansion of 

irrigated agriculture seems unlikely given the competing uses of the oversubscribed water 

in the Pacific Northwest.

Figure 9

Forecast Irrigation Electricity Sales Compared to 4th Plan Forecasts

0

100

200

300

400

500

600

700

800

900

198119851989199319972001200520092013201720212025

Average Megawatts

4th Plan Range

Actual

5th Plan Range

5th Plan Medium

Other electricity use did not have a range associated with its forecast in the 4

th power 

plan. The other forecast is unchanged from the 4th plan forecast, growing at just under 

one percent annually. 
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Aluminum (DSIs)

Background

Direct Service Industries, or DSIs, refers to a group of industrial plants that have 

purchased electricity supplies directly from the Bonneville Power Administration. In the 

past, most of these plants obtained all of their electricity needs from Bonneville. 

Recently, many of these plants have diversified their electricity supplies, either by choice 

or because of reduced allocations from Bonneville. This discussion generally addresses 

the total electricity requirements of these industrial consumers regardless of source.

“DSIs” is often used interchangeably with aluminum smelters because aluminum 

smelters account for the vast bulk of this categories’ electricity consumption. If all of the 

region’s ten aluminum smelters were operating at capacity, they could consume about 

3,150 average megawatts of electricity. Table 5 shows the smelters, their locations, their 

aluminum production capacity and the amount of electricity they are capable of 

consuming at full operation. 

Table 5: Pacific Northwest Aluminum Plants

Owner Plants County Capacity Electricity

Demand

(M tons/yr.) (MW)

Alcoa Bellingham WA Whatcom 282 457

Alcoa Troutdale OR Multnomah 130 279

Alcoa Wenatchee WA Chelan 229 428

Glencore Vacouver WA Clark 119 228

Glencore Columbia Falls MT Flathead 163 324

Longview Aluminum Longview WA Cowlitz 210 417

Kaiser Mead WA Spokane 209 390

Kaiser Tacoma WA Pierce 71 140

Golden Northwest Goldendale WA Klickitat 166 317

Golden Northwest The Dalles OR Wasco 84 167

Total 1663 3145

Source: Metal Strategies, LLC, The Survivability of the Pacific Northwest 

Aluminum Smelters, Redacted Version, February, 2001.

This amount of electricity is significant in the Pacific Northwest power system. The 

amount of power used by these aluminum plants in full operation could account for 15 

percent of total regional electricity use. When operating, the electricity use of these 

plants tends to be very uniform over the hours of the day and night. However, the 

aluminum plants have faced increasing difficulty operating consistently over the past 20 

years because of increased electricity prices and aluminum market volatility.
DRAFT DRAFT DRAFT

17

Aluminum smelting in the region started during the early 1940s to help build up for the 

war effort and to provide a market for the hydroelectric power production in the region. 

Smelting capacity was expanded throughout the 1960s and 1970s. Since then no new 

plants have been added, although improvements to the existing plants have resulted in 

some increases in smelting capacity. The 10 aluminum plants in the Pacific Northwest 

account for a significant share of the U.S., and even the world, aluminum smelting 

capacity. Before the millennium, the region’s smelters accounted for 40 percent of the 

U.S. aluminum smelting capacity and about 6 to 7 percent of the world capacity. Their 

presence in the region is largely due to the historical availability of low priced electricity 

from the Federal Columbia River Power System. Aluminum smelting is extremely 

electricity intensive. Electricity accounts for about 20 percent of the total cost of 

producing aluminum worldwide and is therefore a critical factor in a plants’ ability to 

compete in world aluminum markets. With increasing electricity prices this share is now 

substantially larger for the region’s smelters, perhaps as much as one third of costs.

 Deteriorating Position of Northwest Smelters

The position of the region’s aluminum smelters in the world market has been 

deteriorating since 1980. This is due to a combination of increased electricity prices, 

declining world aluminum prices and the addition of lower cost aluminum smelting 

capacity throughout the world. 

Around 1980 the cost and availability of electricity supplies to the Pacific Northwest 

aluminum plants began to change dramatically. At the time, Bonneville supplied all of 

the smelters’ electricity needs at very competitive prices. However, between 1979 and 

1984 Bonneville’s electricity prices increased nearly 500 percent. This is illustrated in 

Figure 10, which shows Bonneville preference utility rates for electricity since 1940. The 

aluminum plants, along with other electricity consumers in the region, suddenly found 

themselves in a much less advantageous position with regard to electricity costs.

As the region’s aging smelters have struggled to stay competitive in a world aluminum 

market, the conditions of their electricity service have also been changing. During the 

1970s, the region’s electricity demand began to outgrow the capability of the 

hydroelectric system. The fact that aluminum smelters had no preference access to the 

Federal hydroelectric energy meant that their electricity supplies were threatened. The 

Pacific Northwest Electric Power Planning and Conservation Act of 1980 (The Act) 

extended the DSI access to Federal power in exchange for the DSIs covering, for a time, 

the cost of the residential and small farm exchange for investor-owned utility customers. 

In addition, the DSIs were to provide a portion of Bonneville’s reserve requirements 

through interruptibility provisions in their electricity service. 

Over the years since the Act, the DSI service conditions and rates have changed in 

response to changing conditions. After the dramatic electricity price increases of 1980, 

smelters became more vulnerable to changing aluminum market conditions. Between 

1986 and 1996 Bonneville implemented electricity rates for the aluminum plants that 

changed with changes in aluminum prices. These rates were intended to help the 

aluminum plants operate through difficult aluminum market conditions, and to help 
DRAFT DRAFT DRAFT

18

stabilize Bonneville’s revenues. Until 1996, aluminum plants in the region bought all of 

their electricity from Bonneville, with the exception of one plant that acquired part of its 

electricity supply from a Mid-Columbia dam. In the 1996 rate case, aluminum plants 

chose to reduce the amount of energy they purchased from Bonneville to about 60 

percent of their demand in order to gain greater access to a (then) very attractive 

wholesale power market. In the 2001 rate case, Bonneville further reduced the aluminum 

allocation to about 45 percent of smelters’ potential demand, or about 1,425 megawatts. 

The aluminum smelters are now required to obtain over half of their electricity 

requirements in the wholesale electricity market or from other non-Bonneville sources.

Figure 10: Bonneville Power Administration Preference Rates

0

5

10

15

20

25

30

194019431946194919521955195819611964196719701973197619791982198519881991199419972000

Mills per Kilowatt-hour

 Most new world aluminum smelting capacity has been added outside of the traditional 

western economies, often in countries where social agendas may be driving the capacity 

decisions as much as aluminum market fundamentals. The disintegration of the former 

Soviet Union and the liberalization of trade in China have had a significant effect on the 

development of a world aluminum market. The addition of more capacity over time and 

improving aluminum smelting technology is reflected in declining aluminum price 

trends. Figure 11 shows aluminum prices from 1960 through 2001. Trends calculated 

over different time periods all show a consistent downward trend. On average, aluminum 

prices corrected for general inflation decreased by about 0.8 percent annually from 1960 

to 2001. The downward trend is particularly pronounced from 1980 to the present. 
DRAFT DRAFT DRAFT

19

Figure 11: Aluminum Price Trends

Aluminum Association 2002

Long run price trends

0

500

1000

1500

2000

2500

3000

3500

4000

196019611962196319641965196619671968196919701971197219731974197519761977197819791980198119821983198419851986198719881989199019911992199319941995199619971998199920002001

LME 3 Months, 2001$

Trend (1960-2001) -exp

Trend (1981-2001) -exp

trend 1990-2001

Source: CRU International Ltd., Presentation to Aluminum Association 2002.

The steady improvement in aluminum smelting technologie s over time has meant that the 

region’s smelters have tended to grow relatively less competitive in terms of their 

operating costs as new more efficient capacity has been added throughout the world. By 

investing in improved technology some of the region’s smelters have been able to 

partially offset the effects of these declining cost trends. In addition, the worsening 

position of the region’s aluminum smelters relative to other aluminum plants may have 

been partly offset by the decreasing capital costs and debt as older plants and equipment 

depreciate. Nevertheless, a growing share of the regional smelting capacity has become 

swing capacity. That is, plants could operate profitably during times of strong aluminum 

prices or low electricity prices, but tended to be shut down during periods of less 

favorable market conditions. 

Caught in the pincers of decreasing aluminum prices and increasing electricity prices, 

many of the region’s smelters have reached a critical point. Events since the spring of 

2000, in both the electricity and aluminum markets, have had a dramatic effect on the 

region’s aluminum plants. By mid-summer of 2001, all of the region’s aluminum 

smelters had been shut down for normal production, either because of high electricity 

prices and poor aluminum market conditions or because Bonneville bought back the 

electricity to help meet an expected shortfall of electricity supplies and remarket the 

electricity at much higher market prices. The elimination of aluminum electricity load 

played a key role in avoiding electricity shortages in the summer of 2001 and the 

following winter. 
DRAFT DRAFT DRAFT

20

Sharing of the savings from remarketing aluminum plants’ electricity helped ease the 

financial strain on aluminum companies and their employees of a long shut down. 

During 2002 electricity prices in the wholesale market fell to low levels, but aluminum 

prices remained very low and only a few smelters found it desirable to partially return to 

production. In addition, Bonneville’s rates have remained high. There does not appear to 

be much optimism for a quick recovery of aluminum prices. Some analysts expect the 

Global aluminum market to remain in surplus until 2005. 

Currently, two of the regions smelters have closed permanently, two more are in 

bankruptcy proceedings, and others are in dire financial straights. During 2002 

aluminum plants on average only consumed 393 average megawatts of electricity. 

Increases in energy and electricity prices during 2003 have worsened the conditions for 

aluminum smelters and the three plants that had partially reopened have recently 

announced plans to cut back or suspend operations.

With aluminum market recovery uncertain, and with expected future electricity prices too 

high for most aluminum plants to operate profitability, future aluminum electricity use is 

expected to be much lower than in previous Council plans. The ability of aluminum 

plants to operate depends critically on the level of electricity prices. With the medium 

natural gas price assumptions, the Council currently forecasts spot market electricity 

prices to move up to the $40 per megawatt-hour range (see Figure 12). Few, if any, of 

the region’s smelters would be able to operate with electricity prices at that level. It is 

unclear how much of the aluminum load Bonneville might serve in the future, but 

Bonneville’s future electricity prices may also be higher than aluminum plants can afford 

except when aluminum prices are especially high.
DRAFT DRAFT DRAFT

21

Figure 12:

Draft Medium Case Wholesale Price Forecasts for Mid-Columbia Electricity

0

5

10

15

20

25

30

35

40

45

50

2001200220032004200520062007200820092010201120122013201420152016201720182019202020212022202320242025

2000$ Per Megawatt-Hour

A Simple Model of Aluminum Electricity Demand

A simple model of Pacific Northwest aluminum plants was developed to relate the 

likelihood of existing aluminum plants operating to different levels of aluminum prices 

and electricity prices. Given an aluminum price, the model estimates what each 

aluminum plant in the northwest could afford to pay for electricity given its other costs. 

Then for a given electricity price, the electricity demand of the plants that can afford to 

operate make up the aluminum electricity demand in the region. Basic data for the model 

came from the July 2000 study cited as the source for Table 5, advice from the Council’s 

Demand Forecasting Advisory Committee, and comments on a draft aluminum forecast 

paper.5

Figure 13 illustrates the relative competitiveness of the eight remaining Northwest 

aluminum plants as represented in the model. (It is assumed that the other two smelters 

in Troutdale, Oregon and Tacoma, Washington are permanently closed.) Figure 13 

shows the amount that each plant could afford to pay for electricity given an assumed 

aluminum price of $1500 per tonne (about 67 cents a pound), which is about the average 

aluminum price over the past several years.

 

5

 “Forecasting Electricity Demand of the Region’s Aluminum Plants”. Northwest Power Planning Council 

document 2002-20. December, 2002.
DRAFT DRAFT DRAFT

22

Figure 13:

Affordable Electricity Price Limits of PNW Aluminum Smelters

At $1500 Per Tonne Aluminum Prices

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

Smelter

1

Smelter

2

Smelter

3

Smelter

4

Smelter

5

Smelter

6

Smelter

7

Smelter

8

$/Mwh

Electricity prices needed to 

operate smelters assuming 

a $1500 aluminum price.

One aluminum plant in the region is very efficient and likely to operate under a wide 

range of electricity and aluminum prices. Three other smelters could pay around $25 a 

megawatt-hour for electricity if aluminum prices were $1500 a tonne, which is higher 

than aluminum prices have been in several months. The other smelters could only afford 

to operate at electricity prices near $20 per megawatt-hour.

There are some important limitations to this simple model. It is intended to represent 

whether aluminum plants would be willing to operate for an intermediate time period. 

The costs used in the model include an amount above the pure short-term operating costs 

to allow sufficient ongoing capital investments to maintain the plants capability to 

produce. But the costs do not include sufficient returns on capital to justify the long-term 

operation of the plant.

Thus, the model does not address the question of when a plant would be likely to be 

permanently closed. In order to remain in operation, a plant would have to be able to 

recover sufficient funds during periods of high aluminum prices and low electricity prices 

to recover an adequate return on investment. However, as plants depreciate, or as they 

are sold at discounted prices, capital recovery becomes a smaller part of the decision, and 

strategic positioning in global markets may enable some plants to remain available for 

operation when conditions are attractive enough. The implicit assumption in the model is 

that, if a plant can operate for the intermediate term under expected electricity and 

aluminum prices, then it will be able to recover sufficient returns during favorable 

cyclical market conditions to survive in the long term.
DRAFT DRAFT DRAFT

23

The model does not address the dynamics of temporary closures of aluminum plants or 

their return to operation. The dynamics of aluminum smelter operations are important 

considerations for assessing their potential value as demand-side reserves. The potential 

demand-side reserves that might be provided by aluminum plants include; very shortduration interruptions for system stability purposes, interruptions of up to four hours 

during extreme peak electricity price spikes, and long-term shut downs of several months

to a year or more to address periods of poor hydroelectric conditions or other periods of 

significant generation capacity shortages. These issues will be addressed outside of the 

simple aluminum model described here. In the Council’s portfolio risk model, aluminum 

plant closure, reserves, and reopening conditions are related to uncertain variations in 

electricity and aluminum prices. This will be discussed in more detail later.

Model Results

By varying the aluminum and electricity prices over a range of possible values, the 

simple model can be used to simulate expected aluminum electricity demands under 

varying conditions. Aluminum prices were varied between $1050 and $2250 per tonne in 

$100 increments. For each aluminum price, electricity prices were varied between $20 

and $40 per megawatt-hour. This generated 91 different estimates of aluminum plant 

electricity demand under the varying aluminum and electricity combinations. Figure 14 

shows the results of this exercise. 

A couple of bracketing points are evident. First, at aluminum prices below $1150 per 

tonne, none of the Northwest aluminum plants can operate profitably at any electricity 

price between $20 and $40 per megawatt-hour. Aluminum prices have seldom been 

below $1200 a ton (in 2002 prices) in the past 20 years. On the other extreme, all eight 

smelters could operate at aluminum prices above $2050 per tonne for electricity prices up 

to $40 per megawatt-hour.

If past trends in aluminum prices continue, aluminum prices might decline at about 1 

percent a year. That would mean that average aluminum prices might average less than 

$1500 over the next 20 years. Of course there will be considerable volatility around that 

trend. At this point in the Council’s planning process, we do not have a range of future 

electricity prices that match the range of natural gas prices we are assuming for our 

analysis. Preliminary analysis with the medium natural gas price forecast shows that 

wholesale electricity prices under medium assumptions (see Figure 12) could be around 

$40 per megawatt-hour over the long term. In those ranges of electricity and aluminum 

prices, it is unlikely that more than two aluminum plants could operate, and electricity 

demand by aluminum smelters in the region would be less than 900 megawatts.

The results in Figure 14 include an assumption that one smelter will continue to have 

access to low cost mid-Columbia dam power for part of its electricity demand. Access to 

some lower cost supplies of electricity from Bonneville or other sources and further 

investments in smelter efficiency may improve the ability of some smelters to stay in 

operation. The simple aluminum model was used to see what effect an offer of 100 

megawatts of electricity priced at $28 per megawatt-hour would have on smelter 
DRAFT DRAFT DRAFT

24

operations. Assuming an availability of such electricity supplies changes the model 

results for the 91 combinations of aluminum and electricity prices. 

Figure 14: Spectrum of Potential Aluminum Smelter Electricity Demands

0

500

1000

1500

2000

2500

3000

1050 1150 1250 1350 1450 1550 1650 1750 1850 1950 2050

Aluminum Price ($/Tonne)

Electricity Use (Mwa)

20

25

28

30

32

35

40

$/Mw

h

In order to more easily illustrate these effects, an expected value of electricity demand 

was calculated for each assumed electricity market price. This was done by weighting 

electricity demand simulated at different aluminum prices by the percent of days in the 

last ten years that actual aluminum prices fell into that range. Another way of 

characterizing an individual bar in Figure 15 is that it is a weighted average of the 

electricity use in an individual line from Figure 14.

Using just market electricity prices and the one mid-Columbia supply contract, expected 

smelter electricity demands ranged from 783 megawatts at $40 per megawatt-hour 

electricity prices to 2,138 megawatts at $20 electricity prices. This is shown in the leftmost bar for each electricity price group in Figure 15. 

If smelters could arrange to purchase 100 megawatts of power priced at $28 per 

megawatt-hour, it is estimated to have a relatively small effect on expected aluminum 

operations (See the middle bars in Figure 15). At market prices below $28 the expected 

electricity demand of aluminum smelters is actually reduced by the higher priced power 

supply. If market power prices were $40, the availability of 100 MW of power at $28 per 

megawatt-hour is estimated to increase the expected value of aluminum smelters’ 

electricity demand of from 783 to 875 megawatts, a relatively small effect. If smelters 

could arrange a block of power at $20 (illustrated by the right-most bars in Figure 15) the 

estimated increase in electricity demand at the $40 market price would be 314 megawatts. 

That increase is roughly the electricity demand of one additional smelter.
DRAFT DRAFT DRAFT

25

Figure 15: Expected Aluminum Plant Electricity Demand

(Effect of Special Electricity Supplies)

0

500

1000

1500

2000

2500

20 25 28 30 32 35 40

Market Electricity Price ($/MWh)

Expected demand (MW)

Market Price

100MW of Power @$28

100MW of Power @$20

The analysis above addresses the question of whether the existing smelters in the region 

are likely to operate under different aluminum and electricity market conditions. It does 

not address the likelihood of permanent closure. Historically, older and less efficient 

smelters are not frequently closed permanently. Their depreciated capital costs allow 

them to operate when electricity and aluminum prices are attractive. They may provide 

an inexpensive option for aluminum supplies in tight aluminum markets. In addition, 

permanent closure may involve expensive site clean up.

The result is that the region might retain a large, but uncertain, electricity demand. If 

such a demand is required to be served when they need electricity, it can be very costly 

for their electricity supplier to maintain generating capacity to serve the potential 

demand. If serving the demand is optional, however, through either interruption 

agreements or the smelters purchasing available power in the market, it can have 

attractive features that may reduce electricity price volatility. The future of aluminum 

operations in the region may depend on the ability of aluminum plants to find, and get 

value for, their potential for complementing the power system in a competitive wholesale 

market.

Mid-Term Aluminum Demand Assumption

The Council is required to include in its power plans a 20-year forecast of demand. The 

Council is also increasing its focus on the nearer term for purposes of reliability and 

adequacy analysis. For these purposes, a specific forecast of total electricity demand is 

useful. And for that, specific assumptions about DSI demands are needed. This section 

presents such a best guess forecast, but it is important to keep the extreme uncertainty 

regarding this assumption in mind when evaluating reliability, adequacy, or long-term 

resource strategies.
DRAFT DRAFT DRAFT

26

Figure 16 shows the assumed mid-term pattern of aluminum electricity demand through 

2005 compared to the Council’s assumption for the 4th power plan. In the current 

forecast, electricity demand is assumed to recover to about 1,000 megawatts by 2005. 

This would be consistent with two aluminum smelters operating plus 60 average 

megawatts of non-aluminum DSI demand. If the aluminum model is reasonably 

accurate, and if electricity can be acquired for $30 to $35 per megawatt-hour, this implies 

that aluminum prices would have to recover to $1,450 to $1,550 per tonne by 2005. The 

higher end of that range is similar to average aluminum prices during the past 10 years, 

but given recent trends and events in world aluminum markets, should be viewed as a 

reasonably optimistic assumption for the region’s aluminum plants in the future.

The forecast is significantly more pessimistic about aluminum plants’ ability to operate 

than the Council’s 4th power plan. This is consistent with a prolonged period of low 

aluminum prices during 2001 through 2004, with higher forecasts of electricity prices. It 

also is more pessimistic about the ability of some smelters to survive a prolonged period 

of high electricity prices, poor aluminum prices, and uncertainty about electricity markets 

and contracts.

 Figure 16: Medium Case Assumptions for Aluminum Demand Recovery to 2005

(Comparison to 4th Plan Assumptions)

0

500

1000

1500

2000

2500

3000

3500

Jan-02Apr-02

Jul-02

Oct-02

Jan-03Apr-03

Jul-03

Oct-03

Jan-04Apr-04

Jul-04

Oct-04

Jan-05Apr-05

Jul-05

Oct-05

Megawatts

4th Plan

5th Plan Medium Term

The 5th plan expectation for aluminum recovery is also significantly more pessimistic 

than the Council’s assumption in the summer of 2001 forecast. That forecast assumed 

that there would be a reasonably rapid economic recovery, with a concurrent recovery in 

aluminum prices and a significant lessening of electricity prices as the effects of the 
DRAFT DRAFT DRAFT

27

electricity crisis of 2000-2001 were dissipated. Under these assumptions, all but two of 

the region’s aluminum plants were assumed to be able to operate by 2005. 

Long-TermForecasts of Aluminum Smelter Electricity Demand

For the long-term medium forecast, the 2005 forecast level is extended to the end of the 

forecast in 2025. Figure 17 shows the medium total DSI demand assumptions extended 

to 2025 compared to the forecasts in the Council’s 4th power plan. In this figure nonaluminum DSI loads of 60 average megawatts have been added to the aluminum forecast. 

Again, this forecast does not imply that Bonneville will serve all of this DSI demand; it 

has been labeled DSI for convenience. The medium case is 1,260 average megawatts 

below the forecast in the Council’s last power plan.

Although the loads after 2005 are shown as constant, we would actually expect them to 

be quite volatile around that trend. In addition, since aluminum prices are expected to 

trend downward over time, and natural gas prices upward, it may become increasingly 

difficult for regional smelters to operate as the future unfolds.

Figure 17: Demand Assumptions for DSI Industries Compared to 4th Plan 

Assumptions

0

500

1000

1500

2000

2500

3000

3500

198119841987199019931996199920022005200820112014201720202023

Average Megawatts

4th Plan

History

Draft Range

Draft Medium

In all previous power plans, the Council has assumed a range of DSI demands. The high 

DSI demand assumption was paired with the high economic assumptions and demand 

forecast. This pairing of aluminum and other forecasting assumptions was based on the 

theory that aluminum prices would be the key variable and that aluminum prices were 

likely to be positively correlated with rates of economic growth. For illustrative purposes 
DRAFT DRAFT DRAFT

28

a similar approach has been used to develop a range of aluminum demand assumptions. 

Figure 18 shows the aluminum demand assumptions included in each forecast case for 

the Council’s 4th power plan compared to the outlook now. 

Only in the low forecast of the 4th power plan was there a large reduction of aluminum 

demand. It was assumed that Bonneville or other relatively affordable power would be 

available to the aluminum plants. Thus most of the plants were assumed to remain 

competitive, or at least operate as swing plants, in the medium case. Now the expectation 

is that only between zero and four of the region’s smelters could survive to operate at 

significant capacity factors.

The expectation of higher electricity prices and rapid expansion of aluminum smelting 

capacity in China and other areas have changed the outlook for the region’s smelters 

substantially. Aluminum prices are still important, but the cost of electricity has become 

a critical element for Northwest smelters. Since electricity prices are related to natural 

gas prices in the long-term, and high natural gas prices are associated with the high 

economic growth case, it is also reasonable to expect that lower aluminum demand could 

be associated with the higher economic growth cases. However, if high aluminum prices 

are still associated with higher economic growth, then it is possible that the high 

economic growth cases will favor aluminum plant operation given that electricity prices 

are not too high. In short, it is not clear how aluminum demand will be related to the 

economic growth conditions.

Figure 18: Aluminum Electricity Demand Assumptions for 2005-2025

 Compared to the Council’s 4th Power Plan

0

500

1000

1500

2000

2500

3000

3500

Low Medlo Medium Medhi High

Average Megawatts

4th Plan

5th Plan

The proposed solution to this dilemma is to forecast aluminum electricity demand 

separately from other demands for electricity. Since aluminum demands are very 
DRAFT DRAFT DRAFT

29

significant in determining future electricity demands of the region, they are an important 

source of uncertainty that should be modeled and addressed directly in the Council’s 

resource planning process. Therefore, the Council is modeling aluminum industry 

demands explicitly in its portfolio model. To that end, a simple model of the relationship 

between aluminum electricity demand and electricity and aluminum prices was 

developed.

Aluminum Demand in the Portfolio Analysis

In developing the 5th power plan, the Council is modeling aluminum plants as uncertain 

loads that depend on aluminum prices and electricity prices. This will be done in the 

Council’s portfolio analysis model. As it simulates alternative futures, the portfolio 

model randomly selects different electricity prices and aluminum prices. These 

conditions will be used to estimate the aluminum plants’ demand for electricity.

The relationship between the aluminum plants’ electricity demand and electricity and 

aluminum prices is derived from the results of aluminum model simulations similar to 

those illustrated in Figure 14. However, the simulations contained in the portfolio model 

take into account, in addition to the basic cost information for each plant, assumptions 

about cost of shutting down and restarting plants and minimum down time and up time. 

For example, it is assumed that the decision to restart a plant would include the startup 

costs and that, if a plant were to reopen, it would remain open for at least 6 months. 

Similarly, a plant may not close immediately when current prices make it unprofitable, 

and once it does close it would likely remain closed for a period of at least 6 months. The 

portfolio model goes beyond these calculations to consider the value of an aluminum 

plant interruption option to Bonneville or the regional power system.

New Dimensions of Council Demand Forecasting

Changing electricity markets are changing the planning requirements for the region. 

Electricity prices in the Pacific Northwest are related directly to demand and supply 

conditions, not just in the region, but also in the entire interconnected western United 

States. In addition, electricity markets have been, and are expected to remain, volatile. 

Shortages and high prices will occur at specific times of the year and day depending on 

electricity demand, but can be prolonged in cases of poor hydroelectric conditions, such 

as occurred in 2001.

Evaluating electricity markets requires assumptions about demand growth in the entire 

west and some understanding of how the demand will vary across different seasons and 

across hours of the day. The sections below describe the simple approaches used to 

develop assumptions about future patterns of electricity consumption and predicted 

growth in demand throughout the rest of the west. 

Patterns of Regional Electricity Consumption

One approach to forecasting temporal patterns of demand is to use the monthly and 

hourly patterns from the 4th power plan. In the 4th power plan, the Council used an 

extremely detailed hourly electricity demand forecasting model to estimate hourly 

demand patterns in the future. We have not run that model for this forecast, but the 
DRAFT DRAFT DRAFT

30

hourly patterns would remain similar. Another approach would be to use historical 

patterns of demand. In practice, these approaches would not result in significantly 

different monthly patterns of consumption. 

Whatever typical monthly shape is used, specific months can depart from the normal 

pattern depending on weather. Variability in consumption patterns due to weather events 

will be considered in the portfolio planning model that addresses mitigation of risk and 

uncertainty in electricity markets. Typical monthly patterns provide a starting point for 

that analysis. The same is true for the peak demand forecast and the typical hourly 

patterns of demand.

Monthly Patterns of Regional Demand

Figure 19 compares monthly patterns of regional demand in 1999 with patterns from the 

Council’s Load Shape Forecasting System (LSFS) from the 4th power plan simulation for 

1995. The points on this graph indicate the monthly consumption of electricity compared 

to the annual average. These patterns have been adjusted to reflect only non-DSI 

demand. DSI demands, dominated by aluminum plants, tend to be seasonally flat.

The monthly patterns of both the actual and modeled demand reflect the higher electricity 

consumption in the winter with a secondary and smaller increase during the summer. 

Within that general pattern, there appear variations in specific months. The LSFS was 

based on a year in which there was a severe cold event in December. A particular year 

was chosen to design the model rather than an average over several years to preserve the 

variability in the load patterns. Averaging would have tended to flatten the hourly 

variation masking some of the potential volatility.

For purposes of this forecast, the 1999 pattern is used. Table 6 shows the monthly 

demand shape in numerical terms.

Table 6

Monthly Non-DSI Electricity Consumption Pattern

Month Shape Factor

January 1.140

February 1.097

March 1.020

April 0.943

May 0.921

June 0.938

July 0.969

August 0.957

September 0.911

October 0.940

November 1.033

December 1.185
DRAFT DRAFT DRAFT

31

Figure 19

Monthly Patterns of Non-DSI Electricity Use

0.8000

0.8500

0.9000

0.9500

1.0000

1.0500

1.1000

1.1500

1.2000

Jan. Feb. Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Month / Annual Consumption

1999

LSFS

Regional Peak Demand

Monthly regional peak demands are also taken from the Council’s Load Shape 

Forecasting System. Figure 20 shows average monthly consumption compared to 

monthly peak hour consumption. Peak demand is highest relative to average monthly 

demand in the winter months. For example estimated January peak demand is 45 percent 

higher than the average demand for the month, whereas the peak August demand is only 

21 percent higher than average August demand. The summer and winter peak demands 

occur at different times of the day. In June, July and August peak demand hours are at 

2:00 or 3:00 in the afternoon. The rest of the year peak demand occurs at 8:00 or 9:00 in 

the morning.

The ratio of average monthly demand to peak hour demand in a month is referred to as a 

“load factor”. Over time the LSFS predicts that load factors will decline, especially 

during the winter months. That is, the peak hour demand will increase faster than the 

average monthly demand over time. Figure 21 shows predicted load factors for 1995, 

2005 and 2015 from the LSFS analysis of the 4th power plan forecasts. The change in 

load factor is most pronounced in the winter months. Discussion with the Council’s 

Demand Forecasting Advisory Committee indicated that utilities are experiencing 

increases in summer peak loads, probably due to an increasing presence of air 

conditioning in the region. In the future, the Council should investigate this trend further 

to see if the forecasted pattern needs to be modified to reflect a greater decrease in 

summer load factors.
DRAFT DRAFT DRAFT

32

Figure 20

Hourly Peak Demand Compared to Average Monthly Demand

0

5000

10000

15000

20000

25000

30000

35000

40000

Jan. Feb. Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Megawatts

Average Megawatts

Peak Megawatts

Figure 21

Forecast of Electricity Demand Load Factors

50

55

60

65

70

75

80

85

90

Jan. Feb. Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Load Factor

1995

2005

2015

Regional Hourly Demand Patterns

The LSFS forecasts hourly demand for 8,760 hours in the year. It does this for individual 

end uses within the commercial and residential sectors, for specific manufacturing 
DRAFT DRAFT DRAFT

33

sectors, and for irrigation. These hourly patterns are aggregated to obtain total hourly 

demand in the region. Figure 22 illustrates hourly shapes for a typical winter weekday, a 

very cold winter weekday, and a summer weekday. Winter demand peaks in the morning 

and again in the evening. This pattern is driven largely by residential demand patterns, 

which are more variable across the hours of the day than the other sectors.

Figure 22

Illustrative Hourly Demand Patterns in a Day

0

5000

10000

15000

20000

25000

30000

35000

13579

11131517192123

Hour

Megawatts

Cold Winter Day

Winter Day

Summer Day

These hourly patterns of demand may be used in various ways to address analytical 

requirements. In the 4th power plan, for example, they were aggregated into four distinct 

blocks of demand for a week. These included on-peak, shoulder, off-peak, and minimum 

load hours.6 This was done to address sustained peaking requirements in the plan. By 

estimating an hourly pattern for 8,760 hours in a year, flexibility is provided to aggregate 

the demand patterns for different types of analysis.

Electricity Demand Growth in the Rest of the West

In previous power plans, the Council has not concerned itself with demand growth in 

other regions of the West. However, as noted above, this is now an important 

consideration for analysis of future electricity prices that will be faced in this region.

For this draft forecast, a simple approach was used to estimate electricity demand growth 

for other areas of the West. The areas used by the Aurora electricity market model 

dictate the specific areas considered. The general approach used, although it varies for 

some areas, is to calculate future growth in electricity demand as an historical growth rate 

of electricity use per capita times a forecast of population growth rate for the area. The 

 

6

 See “Draft Fourth Northwest Conservation and Electric Power Plan”, Appendix D, p. D-36.
DRAFT DRAFT DRAFT

34

exceptions to this method were California where forecasts by the California Energy 

Commission were used, the Pacific Northwest as discussed below, and the Canadian 

provinces where electricity demand forecasts were directly available from the National 

Energy Board. 

Population forecasts for states are available from the U.S. Census Bureau web site. 

However, the Census forecasts were replaced by more recent state forecasts when they 

could be identified. For example, Nevada population forecasts were taken from the 

Nevada Department of Water Resources. There were two reasons for this. First, the 

Aurora model distinguishes between northern and southern Nevada and Census forecasts 

were only available at the state level. Second, the Census Bureau forecast showed 

Nevada population growing at only .85 percent a year, whereas Nevada has recently been 

the fastest growing state in the nation with population growth in the neighborhood of 5 

percent a year. Other population forecast sources used were the Colorado Department of 

Labor Affairs, the Arizona Department of Economic Security, Pacificorp’s Integrated 

Resource Plan for Utah, and the Wyoming Department of Administration and 

Information.

Electricity consumption per capita varies substantially among the states in the West, as 

have their patterns of change over time. Figure 23 shows electricity use per capita for 

western states from 1960 to 1999. The most spectacular change is for Wyoming, which 

started out in 1960 with the lowest use per capita and grew to substantially higher than 

any other state. This may reflect significant heavy industrial growth in electricity 

intensive, but low employment, plants; for example, oil and natural gas production. The 

Pacific Northwest states are the highest per capita users of electricity reflecting a past of 

very low electricity prices and a heavy presence of aluminum smelters. California is the 

lowest user of electricity per capita, followed by New Mexico, Utah and Colorado, which 

are all very similar to one another. Nevada and Arizona fall between these three states 

and the Pacific Northwest states.

The general pattern is substantial growth in electricity use per capita until about 1980. 

After 1980, most states’ electricity use per capita levels off or actually declines. 

Exceptions to this pattern are Colorado, New Mexico, Arizona, and Utah where use per 

capita has slowed, but continued growing.

The Pacific Northwest was a special case. In Aurora, the Pacific Northwest is divided 

into four areas; western Oregon and Washington (west of the Cascade Mountains), 

eastern Oregon and Washington combined with northern Idaho, southern Idaho, and 

Montana. The sum of these area forecasts should be consistent with the 20-year regional 

forecast discussed earlier. One approach would have been to share the regional demand 

forecast to areas based on historical shares. However, in order to recognize that areas 

within the Pacific Northwest have not grown uniformly, the forecast area growth rates 

were modified to reflect historical relative population growth in the four areas while 

maintaining consistency with the total regional population growth.
DRAFT DRAFT DRAFT

35

Table 7 shows the forecast growth rates for the Aurora demand areas. They are average 

annual growth rates from 2000 to 2025. 

Figure 23

State Electricity Use Per Capita: 1960 to 1999

0.000

5.000

10.000

15.000

20.000

25.000

30.000

19601962196419661968197019721974197619781980198219841986198819901992199419961998

MWhr Per Person

Colorado

California

Nevada

Arizona

New Mexico

Utah

Wyoming

Washington

Oregon

Idaho

Montana

Table 7

Forecast Electricity Demand Growth Rates for Western Demand Areas

Area Annual Growth Rate

PNW Western OR+WA 1.06 

PNW Eastern OR+WA and Northern ID 0.42

PNW Southern ID 1.50

PNW MT 0.63

Northern CA 1.51

Southern CA 1.62

Northern NV 2.12

Southern NV 2.72

WY 0.62

UT 2.80

CO 2.34

NM 3.05

AZ 2.47

Alberta 1.59

British Columbia 1.39
DRAFT DRAFT DRAFT

36

Future Forecasting Methods

At the time the Council was formed, growth in electricity demand was considered the key 

issue for planning. The region was beginning to see some slowing of the historically 

rapid growth of electricity use, and the future of several proposed nuclear and coal 

generating plants was thereby put in question. It was important for the Council’s 

Demand Forecasting System (DFS) to be able to determine the causes of changing 

demand growth and the extent and composition of future demand trends. Simple 

historical trends were no longer reliable. In addition, the requirement of the Northwest 

Power Act for a balanced consideration of both conservation and new generation placed 

another requirement on the Demand Forecasting System; it needed to support the detailed 

evaluation of improved efficiency opportunities and their effects on electricity demand.

These analytical requirements necessitated an extremely detailed approach to demand 

forecasting. Rather than identifying trends in aggregate or sectoral electricity 

consumption and their determinants, the Council developed a forecasting system that 

built demand forecasts up from the end-use details of each consuming sector (residential, 

commercial, industrial). Forecasting with these models required detailed economic 

forecasts for all of the sectors that are represented separately in the demand models. The 

models also required forecasts of demographic trends, electricity prices and fuel prices.

Before the last power plan update a significant new component was added to the demand 

forecasting system. As Western electricity systems became more integrated through 

deregulated wholesale markets, and as capacity issues began to arise in the region, it 

became clear that we needed to understand the patterns of electricity demand over 

seasons, months and hours of the day. Therefore the Load Shape Forecasting System 

(LSFS) was developed. This model builds up the hourly shape of demand based on the 

underlying hourly shapes of electricity use by the different types of end-use equipment. 

It contains about the same detail as the Demand Forecasting System, but when multiplied 

by 8,760 hours per year, a one year forecast can contain 400 million values.

The detailed approaches of the DFS and LSFS are expensive and time consuming. Major 

efforts are involved in collecting detailed end-use data, building the models, and 

maintaining and operating the systems. Neither the current planning issues, nor the 

available data and resources seem to support the continued use of the old demand 

forecasting approach. The Council developed an issue paper on forecasting methods in 

May 2001 to explore alternative approaches.7 It was agreed that it was not possible for 

the Council to employ the forecasting models for the 5th power plan. However, there was 

little consensus among commenters in the region about what changes should be made to 

the forecasting system for future Council planning.

The basic priorities for a demand forecast have changed. Although the Northwest Power 

Act still requires a 20-year forecast of demand, there are few decisions that need to be 

made today to meet growing electricity demands beyond the next five years. The lead-

 

7

 Northwest Power Planning Council. “Council Demand Forecasting Issues”. May 2001, Council 

document number 2001-13. [http://www.nwcouncil.org/library/2001/2001-13.htm]
DRAFT DRAFT DRAFT

37

time required to put new generating resources in place has been reduced substantially 

from the large scale nuclear and coal plants that appeared to be desirable in the early 

1980s. In addition, the restructuring of the whole sale electricity markets to rely more on 

competitively developed supplies means that there is a less clear role for the Council’s 

planning of the type and timing of new resources to be acquired.

The focus of the Council’s power activity has shifted to the evaluation of the performance 

of more competitive power markets and how to acquire conservation in the new market. 

The Council also has been concerned about the likelihood of competitive wholesale 

power markets providing adequate and reliable power supplies, which has three 

implications for demand forecasting. First, the focus is much shorter term. Adequacy 

and reliability depend generating resources, including water conditions and their effects 

of hydroelectric generation, compared to loads. The question that has faced the region 

recently has been whether there is adequate capacity and energy to meet the coming 

winter demand. Second, the region is no longer independent of the entire Western U.S. 

electricity market. Electricity prices and adequacy of supply are now determined by 

West-wide electricity conditions. The Aurora electricity market model that the Council is 

using requires assumptions about demand growth for all areas of the western integrated 

electricity grid. Third, the temporal patterns of demand and peak demands matter more. 

The region is becoming more likely to be constrained by sustained peaking capability 

than average annual energy supplies, as it was in the past. Further, the rest of the West 

has always been capacity constrained and thus peak prices throughout the West can be 

expected during peak demand periods.

Thus, for purposes of demand forecasting, the requirements of the forecast are shifting to 

shorter term, temporal patterns, and expanded geographic areas. This implies that a 

different type of demand forecasting system may be useful for future Council planning. 

However, there remains the question of estimated potential efficiency gains in the use of 

electricity. To assess cost-effective conservation potential the end-use detail of the old 

forecasting models would still be useful. But even if the Council still had the resources to 

use the old forecasting models, the detailed data necessary to update the models does not 

exist. Finding new ways of assessing conservation potential, or of encouraging its 

adoption without explicit estimates of the amount likely to be saved is a significant issue 

for regional planning.

The forecasts presented in this paper are based on an extension of the previous Council 

plan and relatively simple approaches to expanding the geographic and temporal 

dimensions of the forecast. The Council needs to invest in new forecasting approaches 

for future power plans. One of the action items for this plan is for the Council to develop 

a new forecasting system that is better oriented to the available Council resources, to the 

current planning issues, and to the available data regarding electricity consumption and 

its driving variables. The Council welcomes suggested approaches and advice in this 

area.

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