Staff Report to the

Federal Energy Regulatory Commission

on Northwest Power Markets

in November and December 2000

February 1, 2001

The analyses and conclusions are those of the study team and do not necessarily reflect the views of other

staff members of the Federal Energy Regulatory Commission, any individual Commissioner, or the

Commission itself.
i

Contents

Page

1. Overview and Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2. Background ..........................................................4

Generation Capacity and Ownership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Northwest Energy Balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Historical Purchase and Trade Patterns . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

3. Northwest Markets During the Summer 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Prices and Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Sales and Revenue by Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Generation and Input Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Gas Cost Increases to Utility Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Environmental Factors and Weather Conditions . . . . . . . . . . . . . . . . . . . 16

4. Northwest Markets in November and December, 2000 . . . . . . . . . . . . . . . . . . . . . . . 18

Spot Market Power Prices and Volumes . . . . . . . . . . . . . . . . . . . . . . . . 18

Weather and Hydro Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Other Factors Contributing to High Prices and Spikes . . . . . . . . . . . . . . . 23

Combining the Factors: a Descriptive Statistical Analysis . . . . . . . . . . . . 27

Tables

1. Northwest Capacity Changes by Plant Type, 1991 to Present ...................6

2. Total Generation in the Region and the West, 1995 to 1999 ....................7

3. Average Cost of Power Purchases by Utilities 1990 - 1999 ....................9

4. Northwest Sales and Revenue, Totals for May through August, 1995 to 2000 . . . . 14

Figures

1. Northwest Subregion of the WSCC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2. Generation Resource Capacity and Hydro Ownership in the Northwest . . . . . . . . . . . 5

3. Northwest Capacity Surpluses and Deficits 1990 to 1999 .....................8
ii

4. Utility Wholesale Power Purchases in the Northwest 1990 to 1999 . . . . . . . . . . . . 10

5. Mid Columbia and COB Prices, February to September 2000 . . . . . . . . . . . . . . . . . 12

6. Spot Market Natural Gas Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

7. Total Power Generation by Resources in the Northwest, May to 

September . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

8. Power Generation from Natural Gas in the Northwest . . . . . . . . . . . . . . . . . . . . . . . 15

9. Gas Costs at Western Electric Utilities, January to September 2000 . . . . . . . . . . . . . 16

10. Northwest Spot Gas and Electric Prices, November and 

December 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

11. Price and Quantity at Mid Columbia for Day-Ahead On-Peak

 Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

12. Rank of Regional Temperatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

13. Rank of Regional Precipitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

14. Stream Flow Index for Washington State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

15. California Emergencies: Hours in Emergency Status . . . . . . . . . . . . . . . . . . . . . . . 24

16. NOx Reclaim Prices for SCAQMD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

17. December 2000 Outages, California ISO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
1 Staff Report to the Federal Energy Regulatory Commission on Western Markets

and the Causes of the Summer 2000 Price Abnormalities, November 1, 2000.

1

1. Overview and Summary

This report examines operating and market conditions in Northwest power

markets during November and December 2000. It is an extension of an earlier report on

bulk power markets in the West during summer 2000 and covers many of the same issues

regarding high prices and their underlying causes.1

 The focus of this report is on rapidly

increasing power prices during November and December, including a dramatic price

spike in the second week of December. It provides further background on the Northwest

in the context of the overall western power market described in the Western bulk power

report, and examines the specific events and factors leading to increased prices during

November and December.

The main observations from the study are summarized below:

• November 2000 was the coldest November nationwide since 1911, with the

coldest temperatures in the West and Northwest. In early December, a massive

arctic air mass descended on the Northwest region.

• California was under frequent emergency conditions of varying severity during

November and December, and was often unable to supply normal winter exports

to the Northwest region. The California emergency events are correlated with the

high prices in the Northwest.

• Low water levels, precipitation and stream flows limited the energy available

from hydropower generation. Especially low reservoir levels placed stringent

limits on available water for power generation, in order to ensure supplies would

be available later in the season during expected winter conditions. Low

precipitation levels and diminishing stream flows in November and December led

to lower forecasts of available water, and increased the impact on available water

for power generation in December. As a result, the normal process of seasonal

power exchange – sales from the Northwest to California in the summer in

exchange for sales from the California to the Northwest in the winter – failed to

materialize this year.
2

• Very little generation capacity was added in the Pacific Northwest (Washington

and Oregon) or California during the 1990s. This limited capacity, coupled with

high demand and low energy supplies from hydropower, left the Northwest

exposed to a power shortage when California experienced severe power

emergencies. Additional generation is planned for the Northwest and California,

but it is not projected to come on line until 2002 or 2003.

• Environmental conditions limited the full use of power resources in the region: 

- Air quality limits (on NOx) reached annual limits at a number of facilities

in California and generation plants shut down, although some were later

brought back on line after receiving waivers. 

- Minimum flow requirements at hydropower facilities needed to protect fish

populations limited the ability to use water for power generation. Much of

this water is “spilled” and not used for power generation. These limitations

have a particularly large impact when reservoir levels and stream flows are

low, by further reducing the water available for later generation needs.

• Outages appear to have played a significant role in limiting availability of

thermal capacity in the West. Scheduled outages were delayed this fall, in part out

of concerns that high temperatures would continue through October. As a result,

more plants were out on scheduled maintenance when the cold temperatures hit. 

Forced outages at thermal plants, including older gas plants running at higher

levels from May through September and plants shut down because of NOx

limitations, contributed to the overall level of outages as well. Outages in

California were high during the critical period of price spikes in early December

and certainly put pressure on other resources to meet demand. However, our data

on outages are very limited outside California and firm conclusions are difficult to

draw. 

• Natural gas price increases, limits on pipeline capacity and storage levels

contributed to the pressure on power prices. Natural gas price and availability

were affected by similar demand conditions, including requirements for heating

and for electricity generation. Contributing factors included pipelines to

California running full at capacity or limits on the capacity to take gas from the

pipeline into the distribution systems, flow orders on some pipelines resulting

from the flow levels, and low levels in California combined with high storage

withdrawal rates. 
3

• Statistical analysis of available data confirms that much of the variation in power

prices can be explained by operating conditions. For example, a regression

analysis indicates that around 94 percent of the power price variation can be

explained by temperature, precipitation or stream flow levels, and tight supply and

demand measured by the prevalence of emergency conditions in California.

In summary, the northwest power markets saw increased demand through the

1990s, without increased generation capacity in either the Pacific Northwest or in

California. In November and December of 2000, the market was driven by extreme cold,

high natural gas prices and low storage levels, and by low water, precipitation and stream

flow levels. These conditions were made worse by an operating environment with a

large number of outages and environmental constraints, and the general atmosphere of

market uncertainty surrounding the extreme nature of these fundamental factors. In this

environment, power prices rose to extremely high levels for much of the period, levels

above short-term power production costs, and, if sustained, above long-term costs as

well. 

Northwest customers are not as exposed to these high prices as those in California. 

In California, some customers were directly exposed to the high spot market prices (San

Diego) while others found their utilities at risk because of high power purchase costs. In

the Northwest, customers are at much lower risk from the high prices, because a much

greater proportion of the northwest load is protected through utility-owned generation or

long-term contract, but some impact on customer rates is to be expected.

Section 2 provides a background showing how the Northwest fits into the context

of the general western power markets and differentiates the northwest conditions from

the remainder of the West. Section 3 summarizes the conditions leading up to November

and December, and Section 4 analyzes the events of November and December. 
2

Unless otherwise noted, only the U.S. portion of the area will be included. This

area includes Washington, Oregon, Idaho and Utah, and portions of Montana, Wyoming,

Nevada and California as shown in Figure 1.

4

2. Background

For purposes of this report, the Northwest power market will be viewed as the

Northwest power area (NWPA) a subregion of the Western Systems Coordinating

Council.2

 This area is shown in Figure 1. The Northwest power market is distinguished

from other regional markets by the dominant role of hydropower resources and by

substantial presence of federal and other public power entities, as depicted in Figure 2. 

From a planning and operational perspective, the major role of hydropower means that

energy availability plays a central role, with generation capacity requirements highly

dependent on water resource conditions and water use requirements outside the energy

sector. In all regions, electricity demand is sensitive to long and short-term weather

conditions. In the Northwest, both demand and supply conditions are highly dependent

on weather. 

This section surveys the patterns of generation resource use, loads and ownership

in the Northwest and west since 1990. During this period, very little capacity was added

in the Northwest, while loads were growing and generation from the aging resource base

was utilized at an increasing rate. Areas outside the Pacific region (Washington, Oregon

and California) supplied an increasing proportion of the generation needs in the West. 

At the same time, non-utility generation assumed a larger role, as overall utility purchases

more than doubled and purchases from non-utility sources increased substantially. The

remainder of this section provides background material on the evolution of these factors

in the 1990s, setting the stage for the developments of summer and fall 2000.

Generation Capacity and Ownership

The Northwest currently has approximately 55,000 MW of winter generating

capacity, about 65 percent hydropower. Very little capacity has been added since 1990:

additions of 3,300 MW of capacity have been reduced by 2,530 MW of retirements. 

Additions to capacity have been primarily natural gas, but these have been offset by the

retirement of nuclear capacity (see Table 1). Overall, operating capacity has increased by

only 2 percent over a 10-year period.
5

Figure 1. Northwest Subregion of the WSCC

January 1, 2000

Coal

24%

Nat Gas

8%

Nuclear

2%

Hydro-Federal

40%

Hydro-Private

11%

Hydro

 66%

Hydro-Other 

Public

15%

Figure 2. Generation Resource Capacity and Hydro Ownership in the 

 Northwest
3

California, Oregon and Washington make up the Pacific census region, and will

be referred to as the "Pacific region."

6

Table 1. Northwest Capacity Changes by Plant Type, 1991 to Present

Capacity in Megawatts

Plant Type 1996-2000 1991-1995 Total 1991-2000

Current

Capacity

Additions to Operating Capacity

Combine Cycle 1,091 962 2,053 2,587

Gas Turbine 69 447 516 1,155

Hydro 48 352 400 35,575

Nuclear 0 1,107

Steam 34 339 372 14,668

Total 1,241 2,100 3,341 55,091

Capacity Retirements

Combine Cycle 0 2,587

Gas Turbine 240 59 299 1,155

Hydro 1 26 28 35,575

Nuclear 1,944 1,944 1,107

Steam 99 160 260 14,668

Total 340 2,190 2,530 55,091

Net Capacity Additions

Combine Cycle 1,091 962 2,053 2,587

Gas Turbine -171 388 217 1,155

Hydro 47 326 372 35,575

Nuclear 0 -1,944 -1,944 1,107

Steam -66 178 113 14,668

Total 901 -90 811 55,091

Note: Internal combustion plants included in gas turbine category. Other plant categories not listed contributed

150 Megawatts of net capacity additions from 1991 to 2000.

Source: Resource Data International, PowerDat Database, January 2001.

The low rate of additions to capacity in the Northwest has corresponded to an

equally low rate in California, changing the pattern of generation needed to meet demand

in the Pacific Northwest (Washington and Oregon) region and California.3

 Resources in

the Pacific region have been run more frequently and other areas of the West have

increased their share of total western generation. Table 2 shows the growth of generation

in the Pacific region and the overall west. As the table shows, generation in the Pacific

region increased by 37 billion kilowatthours (BkWh) from 1995 to 1999, an 11%

increase from a virtually unchanged resource base over the period.
7

Table 2 shows a shift in generation away from resources in the Pacific to other

areas of the west. From 1995 to 1999, generation in the West outside the Pacific region

grew by 58 BkWh, or 22 percent. This rate of generation increase was twice the rate in

the Pacific region. Although increases in demand outside the Pacific account for some of

this increase, the increased generation also substituted for the lack of additional capacity

in the Pacific region.

Table 2. Total Generation in the Pacific Region and the West, 1995 to 1999

(Million Kilowatthours)

1995 1996 1997 1998 1999

Utility Generation

Washington 95,671 112,606 117,453 97,128 112,072

Oregon 44,031 47,884 49,068 46,351 51,698

California 121,881 114,706 112,183 114,928 87,875

 Pacific Region Total 261,583 275,196 278,704 258,407 251,645

 Rest of the US West 258,329 266,925 281,928 307,433 296,479

 Pacific as % Total West 50.3 50.8 49.7 45.7 45.9

Non-Utility Generation

Washington 6,703 6,216 4,859 5,203 5,181

Oregon 1,321 3,239 3,446 4,921 5,126

California 63,935 63,484 62,422 76,021 108,228

 Pacific Coast Total 71,959 72,939 70,727 86,145 118,535

 Rest of the US West 12,263 13,480 13,744 13,689 32,475

 Pacific as % of Total West 85.4 84.4 83.7 86.3 78.5

Total Generation

Washington 102,374 118,822 122,312 102,331 117,253

Oregon 45,352 51,123 52,514 51,272 56,824

California 185,816 178,190 174,605 190,949 196,103

 Pacific Coast Total 333,542 348,135 349,431 344,552 370,180

 Rest of the US West 270,592 280,405 295,672 321,122 328,954

 Pacific as % of Total West 55.2 55.4 54.2 51.8 52.9

Source: Resource Data International, PowerDat Database, January, 2001.

Table 2 also shows the shift in ownership of generation from utilities to nonutilities. Most of the increased non-utility share in the Pacific has been in California.

California has historically taken a large share of its power from non-utility sources, but

the proportion increases dramatically in 1998 and 1999 from around 63 BkWh (1995 to

1997) to 108 BkWh in 1999, in large part a result of selling off utility generation

capacity. States in the Northwest have not undertaken a program of retail access or

divestiture of utility assets comparable to California. The Northwest has seen much more

modest shifts toward non-utility sources: Washington decreased over the 5-year period,
8

with only around 5 percent of generation from non-utility sources, while Oregon

increased significantly from a small base in 1995 to around 9 percent in 1999.

Northwest Energy Balance

The Northwest is a winter-peaking region. Typically, it provides power to

California and other southern areas of the west in the summer and receives power from

these areas during the winter. Thus, the Northwest has surplus power needs that it

markets to the south in the summer, but runs a deficit in the winter during its peak winter

period. Although the Northwest has a power deficit during the winter, the Northwest is

generally less dependent on outside resources to meet load than California, in part

because of the historically abundant sources of hydropower. However, water for

generation may also be needed to preserve water or maintain stream flows for other water

uses or for environmental mitigation. During a low water year, the Northwest will have

less surplus power for other regions during the summer and greater needs for power from

those regions during the winter. 

Since 1990, the Northwest's dependence on resources outside the region has

increased, as the summer surplus of capacity over peak load has diminished and the

winter capacity deficit has widened. This trend is shown annually in Figure 3. This

figure shows the winter and summer peak loads in the Northwest and the corresponding 

-20.0

-15.0

-10.0

-5.0

0.0

5.0

10.0

15.0

20.0

25.0

30.0

Percent Surplus(+) or Deficit(-)

Summer Surplus(+)/Deficit(-)

Winter Surplus(+)/Deficit(-)

Source: Resource Data International, PowerDat Database, January, 2001.

Figure 3. Northwest Capacity Surpluses and Deficits 1990 to 1999
9

generation capability. Although some year-to-year variation is to be expected, due to

variation both in energy demand and in energy supply limitations on hydro resources, the

trend is clearly downward, reflecting the increasing need to rely on power generated

outside the area.

Historical Purchase and Trade Patterns

Western utilities actively traded wholesale electric power before the advent of

restructuring. Although transmission constraints can limit trade at times, these

constraints are not generally binding and power can be freely traded at most times. The

average rates for wholesale purchases by utilities are shown in Table 3. Over the 10-year

period of the 1990s, rates are seen to increase and to come closer together. When

wholesale trading was smaller in scope than today, and cost based, low prices frequently

reflected surplus conditions and prices in one area could be low while they were high in

another. As trade has moved to market-based pricing in recent years, the spread of prices

has narrowed. In 1999, for example, the spread in the average purchase cost per MWh

across the Arizona, Northwest and Rockies regions was only $4/MWh; in 1990 it was

$18 and in 1995 it was $10. 

The convergence of prices outside California has been accompanied by dramatic

increases in volumes purchased. These volumes reflect both increased reliance on trade

for supplying loads, but also increased wholesale activity on the part of the utilities

themselves. Both the level of trade and proportion of purchases from marketers and nonutilities have increased dramatically, as shown for the Northwest in Figure 4.

Table 3. Average Cost of Power Purchases by Utilities 1990 - 1999

 ($/MWh) 

WSCC Subregion

Year Arizona California Northwest Rockies Total

1990 $38 $53 $20 $28 $38

1991 $36 $52 $20 $30 $37

1992 $38 $57 $22 $32 $40

1993 $36 $58 $25 $31 $41

1994 $37 $61 $27 $36 $42

1995 $35 $57 $25 $35 $40

1996 $32 $54 $29 $34 $36

1997 $31 $50 $24 $35 $33

1998 $30 $55 $29 $36 $36

1999 $27 $45 $31 $30 $35

Source: Resource Data International, PowerDat Database, January, 2001.
10

0

50

100

150

200

250

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Wholesale Purchases (Billion Kilowatthours)

Total Wholesale Purchases by Utilities

Purchases from Marketers and Non-Utilities

Source: Resource Data International, PowerDat Database, January, 2001.

Figure 4. Utility Wholesale Power Purchases in the Northwest 1990 to 1999
11

3. Northwest Markets During the Summer 2000 

The high prices and the power crisis in California were the main focus of attention

in the summer of 2000, but the underlying problems were wider regional ones, and the

Northwest felt the impact as well. Residential and small commercial customers were not

directly exposed to short-term market prices, as they were in San Diego. As Table 2

above shows, most of the generation in the Northwest is utility-owned, and the impact of

the high prices in the spot market is lessened by the relatively small proportion of the

overall market exposed to those prices. Nevertheless, the recent increases in price have

been large and sustained, and the degree of dependence on external supplies or the spot

market varies by individual utility. This section provides a general description of how

the western market over the summer affected conditions in the Northwest, and provides

some limited information on the likely, eventual impact of those prices on customers.

Prices and Sales

Spot Market Price Patterns

Although power market prices spiked at certain points over the summer, the

recurrence of high prices over the longer term may have a greater impact on customer

bills. Prices spiked less frequently as the summer progressed and California imposed

price caps at lower levels, but average prices continued to climb. This climb in prices

can be observed in the spot prices at the California-Oregon Border (COB) and at receipt

points along the Columbia river (Mid-C) by averaging the daily prices over the previous

30-day period and plotting the trend as shown in Figure 5. A large, but short-lived spike

in prices will appear as a jump in the 30-day average, followed by a gradual reduction in

the average price. Figure 5 shows a very different pattern: average prices jump up, but

they stay at the higher level until the middle of September. 

Natural Gas Spot Prices

The cost of natural gas as an input to power generation is one factor in the rising

power price. For much of this period, natural gas was the marginal fuel for power

generation, at least in California. So it is reasonable to assume that the rising trend in

power prices was driven in part by a corresponding rise in gas prices at western delivery

points. Figure 6 show the gas prices corresponding to the power prices in Figure 5. The

price pattern seems to have four distinct stages: 
12

(1) A moderate rise from around $2.50 per MMBtu from the beginning of the

year to about $3.00 per MMBtu in late May; 

(2) A more rapid rise to the $4.00 level at the end of June, corresponding to the

initial stages of the problem in California; 

(3) A leveling off at $4.00 in July and early August, corresponding to

moderating weather and load conditions in July; and 

(4) A return to the rapidly rising trend in late August and September, to a level

over $5.00 by the end of September. 

Unlike power prices, spot natural gas prices gave no indication of a falling trend

at the end of September. While there seems to be a relationship between gas and power

prices in spot markets, it is clearly not simple and direct. Prices for both increase over

the period, but at very different rates: gas moves from around $2.50 in May to over $5.00

in September, approximately doubling. Over the same period, power prices moved from

around $25 in May to $150 to $200 in September, a six- to eight-fold increase.

30-Day Moving Averages

$0

$50

$100

$150

$200

$250

9-Feb

23-Feb

8-Mar

22-Mar

5-Apr

19-Apr

3-May

17-May

31-May

14-Jun

28-Jun

12-Jul

26-Jul

9-Aug

23-Aug

6-Sep

20-Sep

COB OFF PEAK

COB PEAK

MIDC OFF PEAK

MIDC PEAK

Source; Megawatt Daily

Figure 5. Mid Columbia and COB Prices, February to September 2000
4

The Eugene Water and Electric Board received an increase of 15 percent. Seattle

City Light has had two 6-percent rate increases and a 10-percent surcharge. 

13

Sales and Revenue by Sector

Preliminary sales and revenue data for the summer do not yet show an indication

of rising prices to consumer in residential and commercial sectors. As shown in Table 4, 

residential sales in the period of May through August have grown from 1995 to 2000,

increasing 20 percent over the period; prices grew 6 percent from 1999 to 2000, but this

growth does not appear to be significantly higher than in previous years. Industrial sales,

on the other hand, have been flat over the period, with year 2000 sales increasing less

than 1 percent over 1995. 

Residential and commercial power revenues per MWh increased only 1 percent in

2000 over 1999. However, there have been several reports of requests for rate increases

by utilities, so there will be some longer term rate impact.4

 

Some indication of potential rate increases may be reflected in increases in

industrial prices, which are more likely to quickly reflect pass-through of changes in 

30-Day Moving Average

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

16-Feb

1-Mar

15-Mar

29-Mar

12-Apr

26-Apr

10-May

24-May

7-Jun

21-Jun

5-Jul

19-Jul

2-Aug

16-Aug

30-Aug

13-Sep

27-Sep

Price ($/MMBtu)

Malin NW Sumas Stanfield El Paso San Juan Non-Bondad

Source: Gas Daily

Figure 6. Spot Market Natural Gas Prices
5

Source: RDI PowerDat Database, January 2001. Information based on a sample

of utilities in each state.

14

Table 4. Northwest Sales and Revenue, Totals for May through August, 1995 to 2000

1995 1996 1997 1998 1999 2000

Residential and Commercial Sectors

Sales 25.6 27.4 25.8 28.0 29.1 30.9

Average Revenue/Mwh $56 $58 $58 $58 $57 $58

Industrial Sector

Sales 22.7 20.5 21.4 23.7 23.1 22.8

Average Revenue/Mwh $32 $32 $29 $28 $29 $34

costs to the utility than are rates for residential and commercial customers. Industrial

average revenues for May through August of 2000 show increases of 20 percent over

May through August of 1999 for the Northwest as a whole. Increases varied

considerably by state and utility over the summer. In the month of August, for example,

the increases in 2000 over August 1999 were largest in Washington (34%) and Oregon

(24%), while the remainder of the West had increases of only 4 percent. One utility,

Puget Sound, had an increase of 158 percent, from $33/MWh to $84/MWh, and others

had increases in the 30% to 50% range.5

 

Generation and Input Costs

Northwest Generation by Resource

The summer period, May through September, shows two main changes from the

pattern of generation in prior years: lower hydropower generation and higher natural gas

generation. Hydro generation fell 13.3 million MWh, a decrease of 20 percent from the

average of the previous 5 years (see Figure 7.) The loss of hydropower generation was

made up by a three-fold increase in natural gas generation (from 3.3 to 10.2 million

MWh) and increases in other steam generation from coal and nuclear power plants. 

The increase in gas use is a significant increase over prior years, but the trend has

been consistently upward, as shown in Figure 8. Some of the increase reflects the

addition of new combined cycle capacity, but it also may reflect increased use of older

gas steam facilities. Coupled with the increases in gas use elsewhere in the west over the

summer, it reflects a new level of gas use in electric generation that can have a significant

impact on gas usage if it coincides with peak gas use periods in the winter. 
15

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

Annual Generation (Million MWh)

Hydropower Coal Natural Gas Nuclear 

Hydropower 67.0 53.7

Coal 35.8 38.2

Natural Gas 3.3 10.2

Nuclear 1.9 3.1

Average, 1995-1999 2000

Source: Resource Data International, PowerDat Database, January, 2001.

Figure 7. Total Power Generation by Resources in the Northwest, May to 

 September

0.0

2.0

4.0

6.0

8.0

10.0

12.0

Generation (Million MWh)

Natural Gas 2.6 2.7 2.6 3.6 5.0 10.2

1995 1996 1997 1998 1999 2000

Source: Resource Data International, PowerDat Database, January, 2001.

Figure 8. Power Generation from Natural Gas in the Northwest
16

Gas Cost Increases to Utility Plants

The increases in gas use over the summer coincided with the increase in the spot

market price of gas. The increases in the spot market price reported in the trade press can

be compared with actual gas costs reported at electric utility plants. The gas cost at

electric plants in the West is shown in Figure 9. Northwest gas costs increased less than

costs in other western regions, starting out the summer near the spot market levels of

around $3.00/MMBtu, and ending the summer under $4.00/MMBtu when the spot

market price went above $5. 

Environmental Factors and Weather Conditions

The Northwest was not directly impacted by the high environmental costs of

power generation that raised generation costs in southern California. Since power price

increases in one region of the West rapidly translate into increases throughout the West,

however, these factors are likely to have had significant indirect impact by raising market

prices for power throughout the west.

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

Cost ($/MMBtu)

Arizona California Northwest

Arizona $2.49 $2.77 $2.93 $2.93 $3.43 $4.45 $4.44 $4.40 $4.45

California $2.94 $3.09 $3.07 $3.14 $3.70 $4.92 $5.02 $5.15 $5.13

Northwest $2.72 $2.37 $2.55 $3.01 $3.32 $3.91 $3.67 $3.76 $3.76

Jan Feb Mar Apr May Jun Jul Aug Sep

Source: Resource Data International, PowerDat, January, 2001.

Figure 9. Gas Costs at Western Electric Utilities, January to September 2000
6

See Bulk Power Report, Vol 1, p 2-24.

17

The most direct environmental impact in the Northwest is on the availability of

water for hydropower generation. The largest impact appears to have resulted from the

pattern of runoff during the spring.6

 Over the summer months, Northwest stream flow

conditions appear to have been near normal.

Weather conditions in the Northwest during the summer were not as extreme as in

other areas of the West. May, June and August were well above normal, but July was

near normal. These conditions would not tax the power system in the Northwest under

normal conditions, since the summer is not the peak season in the region. However,

when combined with the hydropower conditions, they did serve to limit the ability of the

Northwest to supply power to California and the Southwest. 
7

Megawatt Daily, December 1, 2000.

8

Megawatt Daily, November 27, 2000.

18

4. Northwest Markets in November and December, 2000

This section describes the recurrence of high prices and price spikes in the

Northwest in November and December 2000, and then discusses the fundamental factors

contributing to those spikes. It concludes with a short statistical analysis that quantifies

some of the leading factors and uses them to estimate the pattern of power prices in

November and December. 

Spot Market Power Prices and Volumes 

In September and October, power prices appeared to be moderating from the

sustained high levels of the summer. Prices continued to fluctuate considerably, but the

trend was clearly downward from late August prices over $200 ($225 at Mid-Columbia

on August 29) to prices under $100 in early November ($75 on November 4.) In midNovember, prices for natural gas and electricity started to rise again (see Figure 10.) The

increases at first were small enough to be attributed solely to anticipation of the winter

peak season, but then gas prices jumped over $10 per MMBtu and electricity prices rose

to over $200. This significant trend was punctuated by dramatic increases in early

December, but returned after the spikes subsided to close around $300 during the last

week of December.

The December prices were foreshadowed by the balance of the month prices at the

beginning of December. Balance of the month trades of $310 for December were

reported at Mid-Columbia, while prices of $245 at NP15 and $189 at Palo Verde were

reported.7

 The higher prices at Mid-Columbia underscore the market perception that the

Northwest was likely to be the area of greatest power needs during December. This

pattern is reinforced by a comparison with December forward prices a few days earlier:

$220 at Mid-Columbia, $190 at NP15, and $180 at Palo Verde.8

 Not only do these

prices show the rapid increase in forward prices for December, they also show that the

Northwest led the increase, with Mid-Columbia up $90, while NP15 rose only $55 and

Palo Verde only $9. Clearly, there were anticipated problems in getting power to the

Northwest in December.
9

Natural Gas Intelligence, Gas Price Report, November 27, 2000.

19

The pattern of natural gas prices tracked with the pattern of power prices (see

Figure 10). Power prices did not follow the rapid run up in natural gas prices in the last

week of November, but otherwise shifts in power prices appear to mirror shifts in natural

gas prices. The last week in November set the stage for the natural gas price increases:

the natural gas price at Sumas, Washington, started the week at $8.50 on November 20

and doubled to $17.04 in two days, just before the Thanksgiving holiday. Frigid

weather, pipeline operational flow orders (OFOs) on several regional pipelines

(Northwest, PG&E, Transwestern and El Paso) and the "dire status" of Southern

California gas storage conditions were all cited in trade press accounts as key

contributing factors in the rapid gas rise.9

 The speed and size of the natural gas price

increase appeared to take the market by surprise, and no immediate impact was seen in

power prices.

The power price spikes came in early December, when prices began to rise in the

week beginning Monday, December 4. At the end of the week, on December 8, prices

for the following Monday, December 11, jumped to over $4,000 at Mid-Columbia and to

$0

$10

$20

$30

$40

$50

$60

1-Nov

3-Nov

7-Nov

9-Nov

13-Nov

15-Nov

17-Nov

21-Nov

27-Nov

29-Nov

1-Dec

5-Dec

7-Dec

11-Dec

13-Dec

15-Dec

20-Dec

22-Dec

27-Dec

29-Dec

Date

Gas Price ($/mmbtu)

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

Electric Price ($/MWh)

Malin(Gas)

NW Sumas (Gas)

Mid-Columbia

COB(Elec)

Source: Megawatt Daily, Gas Daily

Figure 10. Northwest Spot Gas and Electric Prices, November and 

 December 2000
20

$3,000 at the California-Oregon border. The factors contributing to the rising trend and

the price spikes are discussed in the remainder of this section.

Although prices spiked to extraordinary levels on December 11 and 12, as shown

in Figure 10, it is not clear how much power was purchased at these prices, and we lack

available information to determine the degree of exposure of utilities and their customers

in the Northwest. Based on the volumes reported in Megawatt Daily, however, it does

appear that overall quantities bought diminished as prices spiked (see Figure 11.) The

quantities reported in Megawatt Daily do not represent estimates of total market

quantities, but only the actual quantities included in the price survey. If changes in these

quantities are representative of general changes in the market, they do show a marked

reduction in purchase quantities beginning in the first week of December when the

market began to founder and prices started their path to extreme values. 

Weather and Hydro Conditions

As noted in the last section, Northwest weather and climatic factors, specifically

temperatures and stream flow conditions, did not appear to be critical factors over the

November 1 to December 31, 2000

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

1-Nov

3-Nov

7-Nov

9-Nov

13-Nov

15-Nov

20-Nov

22-Nov

28-Nov

30-Nov

4-Dec

6-Dec

8-Dec

12-Dec

14-Dec

19-Dec

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28-Dec

Quantity (MW)

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

Mid-C

Price

Source: Megawatt Daily

Figure 11. Price and Quantity at Mid Columbia, Day-Ahead On-Peak

 Power
10Natural Gas Intelligence, December 11, 2000, based on reported information

from Salomon Smith Barney.

11Salomon Smith Barney meteorologists Jon B. Davis and Mark Russo, quoted in

Natural Gas Intelligence, December 11, 2000.

21

summer or during the early fall. But temperature, precipitation and stream flow

conditions changed for the worse during November and early December.

Figure 12 shows the monthly temperature rankings from September to December

in three western regions, showing that the entire west experienced an extremely cold

November. Nationwide, November was reported as the second coldest November of the

106 on record, with only the winter of 1911 being colder. Idaho, Wyoming, Utah and

Arizona experienced their second coldest winters on record, and California and Colorado

their third coldest.10 

Figure 12 shows general temperature conditions, but doesn't show how closely

related concerns about weather during the week of December 11 were in early December

when prices started to rise. Forecasts during the first week of December anticipated a

"polar pig" arriving the next week and bringing record-breaking temperatures for the

entire west. The frigid temperatures were forecast to last the entire week11. These

forecasts combined with a series of Stage 2 emergencies at the California ISO, fueled the

trading on Friday, December 7, when prices for power delivered on Monday, December

11, rose to $4,000 at Mid-Columbia. During the week beginning Monday, December 11,

the extreme cold arrived, but the extreme conditions did not last quite as long as

predicted, with a moderating trend through the week. Prices subsided as temperatures

moderated. 

Extreme cold was not the only weather-related factor in the power shortages and

high prices. Precipitation in the Northwest, which had been at least at normal levels in

September and October, fell to low levels in November and December (see Figure 13)

raising growing concerns about the available hydropower at the normal peak winter

period in January or February. The precipitation conditions were accompanied by a 

significant shift in stream flow conditions from normal to low levels through November. 

The Figure 14 shows how the average stream flow index for Washington fell rapidly

until mid-December, reinforcing other demand and supply conditions leading up to the

December price spikes. 
22

 September to December 2000 (1=Coldest, 106=Warmest)

0

10

20

30

40

50

60

70

80

90

100

Sep-00 Oct-00 Nov-00 Dec-00

Temperature Ranking (last 106 years)

Southwest Northwest West

Source: NOAA website, www.ncdc.noaa.gov/ol/climate/research/caq3/caq3.html

Figure 12. Rank of Regional Temperatures

 September to December 2000 (1=Driest, 106=W ettest)

0

20

40

60

80

100

120

Sep-00 Oct-00 Nov-00 Dec-00

Precipitation Rank (last 106 Years)

Southwest Northwest West

Source: NOAA website, www.ncdc.noaa.gov/ol/climate/research/caq3

Figure 13. Rank of Regional Precipitation
23

Other Factors Contributing to High Prices and Price Spikes

Several other key factors contributed to the power shortage and price events. 

There were no emergency conditions at the California ISO in October, permitting power

prices to moderate somewhat. As power shortage concerns deepened in December,

California experienced a return of emergency conditions. These conditions show up

clearly in Figure 15, which plots the hours under each of the emergency stages for the

days in November and December. The emergencies were a result of worsening supply

and demand conditions, but they fed back into the market, creating additional market

stress about the ability to find supplies to meet demand and making the market aware of

the vulnerable status of the California ISO.

May,2000 to January, 2001

2.50

3.00

3.50

4.00

4.50

5.00

1-May

15-May

29-May

12-Jun

26-Jun

10-Jul

24-Jul

7-Aug

21-Aug

4-Sep

18-Sep

2-Oct

16-Oct

30-Oct

13-Nov

27-Nov

11-Dec

25-Dec

8-Jan

Stream Flow Index (1=driest, 7=wettest)

Source: USGS web site: water.usgs.gov/cgi-bin/average_daily?wa

Figure 14. Stream Flow Index for Washington State
24

Environmental factors continued to exert further stress during the period. For

natural gas supply, they affected both price and quantity. First, prices for NOx permits

continued at high levels (see Figure 16) in Southern California. The rules governing the

use of these permits make it difficult to directly estimate the impact of their prices on

generation costs, but prices at the levels seen since August 2000 are bound to exert

upward cost pressure on prices in Southern California and influence power prices in the

west when gas is on the margin. Given the conditions in California, gas could be

expected to be on the margin much of the time. The impact can be particularly

pronounced under emergency conditions, when older units with very high NOx

emissions rates are needed to meet load.

Second, environmental restrictions could prohibit certain plants from running at

any price. When plants are subject to hard limits on output of NOx emissions, special

waivers are needed to permit the plants to run. The need to obtain permits, and the

negotiated outcomes that arise, make the environmental component of power pricing an

even more uncertain exercise than it is under more normal conditions. This condition

occurred during critical times in November and December: 2000 MW of AES gas-fired

capacity were taken offline at the end of November under regulatory pressure to install

0.0

5.0

10.0

15.0

20.0

25.0

1-Nov

8-Nov

15-Nov

22-Nov

29-Nov

6-Dec

13-Dec

20-Dec

27-Dec

Hours in Emergency Status 

Stage 1 Stage 2 Stage 3

Source: California ISO

Figure 15. California Emergencies: Hours in Emergency Status
12Assessing the 2001 Outlook, Northwest Power Planning Council

25

scrubbers. This capacity was returned to service after the high prices on December 11, 

when AES reached an agreement with the South Coast Air Quality Management District 

that eased penalties and permitted the capacity to return.

Finally, there are environmental requirements to maintain flow levels for the

protection of fish populations which limit the use of water for power generation. As

stream flows diminish, the need to release a certain amount of water to preserve the

environment will have a major impact on the available energy from hydropower in the

Northwest. The water level behind Grand Coolee Dam in the Northwest is the second

lowest of the last 25 years, approaching the level in 1989, a level far below all other years

from 1975 to date.12

Outages were commonly cited by the California ISO as a contributing factor in

California emergencies, and appear to have been important in other geographic areas as

well. The only systematic outage data available for this study were from the California

ISO for December. These data show that outages were high during the first week in

December, but were lower in the remainder of the month (see Figure 17.) The specific

relationship between these outages and power shortages and prices cannot be determined

May to December, 2000

$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

$50

May-00 Jun-00 Jul-00 Aug-00 Sep-00 Oct-00 Nov-00 Dec-00

Dollars per pound

Source: Cantor-Fitzgerald web site.

Figure 16. NOx Reclaim Prices for SCAQMD
13Power Markets Week, November 20, 2000.

26

from these data. The high level of outages during the week of December 4 to 10 

probably contributed additional market stress as prices began to rise, and the lower level

during the week of December 11 to 18 probably contributed to the relatively swift fall of

prices from the highest levels. It is difficult to draw any further conclusions from these

data, and no conclusions can be systematically extended to the Northwest.

Although we lack detailed quantitative information outside California, it appears,

from trade press reports, that some scheduled maintenance was delayed from October to

November out of concerns that high temperatures would last through October.13 The

normal winter period is January, so a large amount of planned maintenance was still

being performed in December. These conditions are consistent with the level of planned

maintenance shown in the California ISO data in Figure 17. In addition, three large

nuclear units were out of service for scheduled maintenance at the same time in

November. One of them, Diablo Canyon-1 was delayed for two weeks, finally returning

around November 22. None of these conditions is inherently suggestive of a pattern of

withholding. Even when specific requests to delay maintenance were granted, the results

could be mixed. Maintenance on Diablo Canyon-2, scheduled for 4 days at the

beginning of December, was delayed until the second weekend in December, from

-

2,000

4,000

6,000

8,000

10,000

12,000

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31

Day of the Month

Megawatts Out of Service (MW)

Planned Outage

Planned/Forced

Forced

Source: California ISO.

Figure 17. December 2000 Outages, California ISO
27

December 9th to 11th. As a result the unit went down for maintenance, just as the power

price for Monday, December was spiking to $4000 at Mid-Columbia. The unit came

back into service late in the day on Monday, in time to contribute to moderating prices

during the week, but too late to help mitigate the dramatic spike on Monday. 

Combining the Factors: a Descriptive Statistical Analysis

Several of the factors discussed in this section were quantified and developed as a

daily time series of prices and conditions. The time series was then used to quantify the

relationship between power prices and these factors. The following factors were used in

a statistical analysis of on-peak, day-ahead power prices reported in Megawatt Daily for

the Mid-Columbia delivery point:

• Temperature Conditions in the Northwest. The temperature in Seattle as reported

by the Accuweather.

• Emergency Conditions in California. For this purpose, the presence of emergency

conditions was measured by the number of minutes in Stage 2 emergency each

day, using data from the California ISO.

• Stream Flow Conditions. This measure used daily stream flow information for

Washington. Two separate measures were constructed: an average index for each

day across all streams, and a percentage of streams with flows below the 25th

percentile.

These operating variables were used in a regression analysis to explain the price of

power at Mid-Columbia. Using a statistical measure know as the coefficient of

determination, or R2

, these variables are highly significant and explain 94 percent of the

variation in the Mid-Columbia power price. This result confirms the belief that these

fundamental operating conditions were important in explaining the price of power.