2-1

2. Supply and Demand Conditions 

Supply and demand conditions throughout the West were tight much of the summer,

with emergency conditions concentrated in California. The broad factors were hot weather,

in some cases extreme hot weather, coupled with continued demand increases without

corresponding increases in power production capability. The main findings of the report on

demand and supply conditions are: 

• Overall demand increased significantly. Driven by hot weather, load increases

over previous years were most pronounced in May and June. Average summer

demand in the California Independent System Operator (Cal-ISO) area increased 8

to 9 percent over the previous 2 years. Peak hour demand forecasts increased

slightly over 1999, but actual hourly peaks fell slightly, reflecting in part the

response to emergency declarations and actions. Offpeak demands increased

significantly in July and August, in part to meet increased pumping demands and to

conserve water stored at hydropower facilities, needed for peaking purposes both

inside and outside the Cal-ISO area.

• Exports from California increased significantly, with little overall change in the

level of imports. As a result, net import decreases averaging up to 3,000 megawatts

(MW) needed to be offset by increases in generation internal to the ISO control

area. The ability to increase imports was limited by hydro conditions in the

Northwest, which actually declined in July and August, and tight load conditions in

other western subregions. Weather conditions in the desert southwest were among

the hottest on record. These conditions led to increased exports in July and August,

corresponding to the decreases in the ISO price cap from $750 to $500 in July and

to $250 in August.

• Outages increased significantly. Compared with 1999, outages in the Cal-ISO area

increased as much as 2,900 MW. Planned outages in January through April were

significantly lower in 2000 than in 1999. However, unplanned outages in May

through August, particularly in July and August, were much higher in 2000 than in

1999.

• Increased quantities of demand and supply were left unscheduled in day-ahead

and hour-ahead markets. When loads increased above 35,000 MW in June, and at

lower levels in July and August, the Cal-ISO was forced to buy substantial amounts

of power in the form of replacement reserves or out of market purchases in real

time.

• Non-hydro generation resources throughout the West were more heavily utilized

in 2000 than in 1999. In 2000, non-hydro resources generated 15.1 percent more
2-2

power in May and 24.9 percent more power in June, compared with 1999. Based on

an analysis of WSCC capacity during the week of July 31 to August 4, little

additional capacity appears to have been available at such peak times.

Section 2.A. provides background on supply and demand: the bulk power system in

the West, distribution of resources and expectations for the summer of 2000 in the spring. 

Each of the main findings summarized above is discussed in Section 2.B.

A. Supply and Demand Background

1. Brief Description of Bulk Power System in the West

The Western Grid encompasses 1.8 million square miles within 14 western states,

two Canadian Provinces, and a portion of Baja California Norte Mexico. Figure 2-1

illustrates the configuration of the Western Grid. The Western Interconnection transfer

capability with other regions is limited to around 1,000 megawatts.

 The Western Grid operates under the North American Electric Reliability Council

(NERC) guidelines as administered by the regional reliability council: the Western

Systems Coordinating Council (WSCC). The WSCC is divided into four reporting

subregions and 30 load control areas. The subregions are shown in Table 2-1.

Table 2-1. Subregions in the WSCC

Subregion States Comprised

AZ/NM/SNV (Arizona) Arizona, most of New Mexico, the western part of Texas, southern

Nevada, and a portion of southeastern California

CA/MX (California) Most of California and the northern portion of Baja California, Mexico

NWPP (Northwest) Washington, Oregon, Idaho and Utah, British Columbia and Alberta, and

portions of Montana, Wyoming Nevada and California

RMPA (Rockies) Colorado, eastern Wyoming, and portions of Western Nebraska and South

Dakota

Within the California-Mexico subregion (California) of the WSCC is the California

power grid, which carries bulk electricity to local utilities for distribution to their 27

million customers and transports significant amounts of power for other generation or

local distribution entities in the region. The Cal-ISO assumed control of 75 percent of the

California power grid (Cal-ISO grid) in 1998, consolidating the transmission systems of

the three investor-owned utilities into one large system. The network comprises 21,000

circuit miles of power lines that deliver about 165 billion kilowatt-hours of electricity each

year. Power plants connected to the Cal-ISO grid have a total capacity of approximately

45,000 megawatts. 
1

 Resource Data International, RDI Powerdat Information System, September 2000.

2-3

2. Historical Load Growth and Resource Mix

Peak load in the WSCC has been steady over the last 17 years, as shown in 

Figure 2-2. Over this period, growth in peak summer demand was highest in the

Arizona/New Mexico/Southern Nevada (Arizona) region, at an overall annual average of 7.9

percent, followed by California at 3.2 percent, the Rockies at 2.8 percent and the

Northwest at 2.4 percent. Table 2-2 shows load growth for two recent 3-year periods.

California and Northwest show large differences in growth rates between the two 3-year

periods, while growth rate differences in the Rockies and Arizona are small. These

variations can be driven by many factors, but two major ones include changes in weather

patterns and increases in economic activity.

The WSCC region has approximately 160 gigawatts (GW) of generation capacity. 

From 1991 to 1998, an average of 1,197 megawatts (MW) were added per year, a growth

rate of under 1 percent.1 Current and planned (as of January 1, 2000) capacities by

subregions are shown in Table 2-3. Planned capacities in this table represent all active

plans and are adjusted for planned deratings and retirements of current capacity. Only small

amounts of capacity were planned for 1999 and 2000 (only around 1 percent in each year.) 

Significant capacity additions have been planned for 2001 and 2002, but may be subject to

cancellation depending on investors' perceptions of market and regulatory stability.

Figure 2-3 shows the wide variation in the types of generation resources across the

WSCC region. The Northwest is dominated by hydropower (65% of capacity). The output

of the many federally owned and operated hydropower facilities is marketed by the

Bonneville Power Administration. The Rockies have largely coal generated resources

(68%). Arizona has a large amount of coal capacity (41%); these coal resources are more

expensive to produce than the coal resources in the Rockies, but still well below the cost of

producing power from oil or natural gas sources. Many of the resources in California are

oil and/or natural gas generation.
2-4

Table 2-2. Comparison of 3-Year Average Growth in Summer Peak, in the 

 WSCC, 1998 and 1995

Subregions Average Growth Percentage

1996 to 1998

Average Growth Percentage

1993 to 1995

Arizona 4.3 4.3

California 3.9 0.6

Northwest 3.4 0.8

Rockies 3.0 4.3

ARIZONA

BAJA CALIFORNIA NORTE

CALIFORNIA

COLORADO

IDAHO

MONTANA

NORTH DAKOTA

NEBRASKA

NEW MEXICO

NEVADA

OKLAHOMA

OREGON SOUTH DAKOTA

SONORA

TEXAS

UTAH

WASHINGTON

WYOMING

Voltage Category

 Below 230kV

230kV - 344kV

345kV - 499kV

500kV - 734kV

AC-DC-AC Tie

DC

Figure 2-1. Western Power Grid
2-5

The pattern of imports and exports of power among the four subregions and Canada

is to a large extent determined by the distribution and cost of generating resources. The

Northwest and the Rockies subregions are significant exporting areas at peak times: the

former based on the availability of hydropower capacity and the latter based primarily on

coal-fired generation. California is the major importing subregion, both because its

capacity is below its peak load, but also because this capacity is more expensive. The

import and export patterns are generally seasonally based, with California importing in the

summer and exporting to the Northwest in the winter. Table 2-4 shows annual trends in

generation, imports and exports from 1990 to 1998. Steady increases in imports are shown

into the California and Arizona subregions, with the increased exports coming largely from

the Northwest. A particularly large increase in exports from the Northwest (and

corresponding imports into California and Arizona) is shown for 1997 and 1998. 

Table 2-3. Current and Planned Generation Capacity in the WSCC, as of 

 January 1, 2000

 (Megawatts)

 Planned Plants by Planned Online Year

Subregion Current 2000 2001 2002 2003 2004 2005

Arizona 24,562 132 1,919 4,885 4,055 0 500

California 52,709 620 2,505 3,110 1,594 0 255

Northwest 72,443 1,426 1,115 1,391 836 51 -67

Rockies 9,381 358 251 799 672 339 85

Total WSCC 159,095 2,536 5,790 10,185 7,157 390 743

Source: WSCC-Existing Generation and Significant Additions and Changes to System Facilities, 1999-2009, issued May 2000.

Notes: Planned capacity includes all active plans, with reductions for retirements. Northwest includes Canada.
2-6

0

20

40

60

80

100

120

140

1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Peak Demand in Thousands of Megawatts

Arizona

Rockies

Northwest

California

Figure 2-2. Peak Summer Demand in WSCC

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Northwest Rockies Arizona California

Geothermal/

Other

Combined

Cycle

Comb.

Turbine/

Internal

Comb.

Nuclear

Steam-oil &

gas

Coal

Hydro

Figure 2-3. Capacity Resource Percentages by WSCC Subregions
2-7

Table 2-4. Generation, Imports and Exports in WSCC, 1990 to 1998

 (Thousand Megawatthours)

1990 1991 1992 1993 1994 1995 1996 1997 1998

Internal Generation

 Arizona

 California

 Northwest 

 Rockies

66,852

208,350

214,623

43,315

72,811

199,435

235,047

42,141

72,998

195,099

235,190

42,603

77,373

215,474

217,682

42,997

76,091

221,911

219,935

43,505

79,271

230,660

221,970

44,166

76,035

225,384

239,155

45,844

77,467

218,720

265,852

48,187

94,155

205,246

278,699

52,431

Total WSCC 533,140 549,434 545,890 553,526 561,442 576,067 586,418 610,226 630,531

Imports

 Arizona

 California

 Northwest

 Rockies

7,222

30,814

11,278

2,999

5,526

46,665

8,115

3,723

4,649

45,336

9,465

2,856

4,355

33,187

17,204

3,355

5,826

31,011

21,274

4,230

5,641

30,814

19,009 

5,278

7,117

30,738

11,069

4,342

14,142

45,730

17,098

3,929

15,374

51,125

12,711

3,676

Exports

 Arizona

 California

 Northwest

 Rockies

12,882

4,011

19,769

8,293

14,594

2,799

30,445

7,377

13,648

2,409

29,729

7,021

15,432

4,980

19,104

6,366

13,585

10,183

23,510

7,186

12,613

9,207

21,406

7,391

9,406

7,191

30,156

6,764

12,362

6,477

52,442

8,194

10,998

6,236

66,526

9,028

Source: NERC Electricity Supply and Demand 2000 Database (ES&D)

3. Spring Expectations for the Summer of 2000

The WSCC forecasts include a separate forecast for each of the four subregions and

for the WSCC region as a whole. The subregion forecasts are required due to differences in

demand, installed generation, and limitations in the western transmission grid. In its updated

May forecast for the summer of 2000, the WSCC concluded that if normal temperatures

were to prevail during the summer period, projected regional capacity margins and

reliability should be adequate. It also stated that if higher than normal unplanned generator

outages occur, an area experiences significantly higher than normal temperatures, or the

loads in multiple areas peak simultaneously, portions of the region may need to issue public

appeals for customers to reduce their electrical consumption or other measures may be

necessary. 

WSCC concluded that the southwest portion of WSCC (New Mexico, Arizona,

southern Nevada, California, and Baja California, Mexico) might not have adequate

resources to accommodate a widespread severe heat wave or higher than normal generating

outages. Table 2-5 shows the WSCC projected total demand, resources and anticipated

margins for the summer months for those portions of the WSCC region located wholly

within the United States. 
2-8

Table 2-5. WSCC-U.S. Forecasted Demand and Supply, Summer 2000

 (Megawatts)

May June July August September

Total Load 96,908 108,635 116,440 114,899 107,616 

Total Resources 136,023 136,868 136,771 136,586 137,166

Unavailable 10,959 3,780 2,830 2,927 5,944 

Net Resources 125,064 133,088 133,941 133,659 131,222

Net Imports and Exports 533 483 483 283 283 

Margin MW 29,034 28,228 21,281 22,697 27,645 

Margin % 30.4 27.0 19.0 20.5 26.8

The forecast for the summer from the California subregion is summarized in Table 2-

6. The Cal-ISO also prepared a forecast containing two different weather assumptions, and

consequently two different peak and net import forecasts (see Table 2-7). The WSCC and

ISO forecasts agreed that exceptionally high temperatures could lead to a capacity shortage.

Table 2-6. WSCC-California Forecasted Demand and Supply, Summer 2000

 (Megawatts)

May June July August September

 Total Load 38,906 47,457 52,057 51,487 47,978

 Total Resources 54,516 54,497 54,497 54,497 54,497

 Unavailable 1,718 118 0 0 1,656

 Net Resources 52,578 54,379 54,497 54,497 52,841

 Net Imports and Exports -4,960 -5,605 -5,605 -5,602 -5,634

 Margin MW 15,193 11,738 8,728 8,489 9,628

 Margin % 39.1 26.3 17.7 17.4 21.3

Table 2-7. Projected Cal-ISO Peak Loads and Resources

 (Megawatts)

Load Condition Peak In-Area

Load

Generation Net Imports Excess (+) or Deficiency (-)

Normal 46,250 38,000 8,400 150

High 48,940 38,000 7,000 -3,940
2-9

B. Summer 2000

This section presents the results of staff’s examination of the performance of

western markets during the summer of 2000, concentrating on the key findings from the

study relating to supply and demand conditions. Much discussion and attention have been

focused on the problems in California and its market, but review of the events of the

summer needs to start with the overall western pattern of load and supply. Accordingly, this

section starts with a review of western demand and its underlying determinants.

1. Demand Growth

Demand has been steadily growing in the West, particularly in areas driven by

technology such as California and the Northwest. In addition, summer demand in 2000 was

driven by extreme weather conditions throughout the West. Figure 2-4 summarizes the May

through August 2000 temperature patterns in western regions. California is shown separately

from the California/Nevada region. The figure shows the rank of the regional temperature

over the last 106 years. It is clear from the figure that the Southwest, including Arizona, New

Mexico, Utah and Colorado, was very hot for the entire summer. It is also clear that all areas

were hot early in the summer, in May and June, when signs of high prices and price spikes

first surfaced in California. 

While May and June were extremely hot throughout the West, July and August show a

mixed pattern, with moderate to below normal temperatures outside the Southwest in July

and hotter than normal temperatures throughout the region in August, but falling short of the

extreme hot weather of June. The weather pattern in June over the last 3 years is shown in

Figure 2-5. Regardless of the absolute rank of the summer of 2000, it is easily seen that the

summer marked a departure from the mild summers since 1998 when California began to

implement restructuring. The wide geographic distribution of hot weather in June 2000

placed new stresses on the generation and transmission system throughout the West, taxing

the ability of exporting areas to keep up with both internal and external demands.
2-10

Source: NOAA web site: @http://www.ncdc.noaa.gov/ol/climate/climateresearch.html

0

20

40

60

80

100

120

May-00 Jun-00 Jul-00 Aug-00

Rank of Regional Temperature 

Over Last 106 Years

Southwest Northwest California/Nevada California

Figure 2.4. Rank of Regional Temperatures: May to August 2000

0

20

40

60

80

100

120

Southwest Northwest California/Nevada California

Rank of Regional Temperature 

Over Last 106 Years

Jun-98 Jun-99 Jun-00

Figure 2.5. Rank of Regional Temperatures: June 1998 to 2000
2-11

These weather patterns are reflected in the load growth statistics for western states in

May and June, shown in Table 2-8, which compares loads in 2000 for May and June with

corresponding loads in 1999. In June, overall load is estimated by EIA to have grown 13.7

percent in California and 7.3 percent in the West outside California. Heat-sensitive

residential load grew even more: 23.8 percent in California and 9.0 percent outside

California. States bordering California, Nevada and Arizona, experienced comparable or

higher changes from 1999 to 2000: Arizona residential load grew 22.3 percent in June, and

Nevada grew 27.2 percent.

Table 2-8. Load Growth in the West, May and June 1999 to May and June 

 2000

 (Thousand Megawatthours)

All Sectors Residential

State 1999 2000 % Change

1999 to 2000

1999 2000 % Change

1999 to 2000

May

Arizona 4,421 5,247 18.7 1,415 1,928 36.3

Colorado 3,096 3,580 15.6 972 974 0.2

Idaho 1,730 1,787 3.3 483 431 -10.8

Montana 906 787 -13.1 298 241 -19.1

Nevada 2,125 2,518 18.5 583 786 34.8

New Mexico 1,549 1,542 -0.5 341 358 5.0

Utah 1,670 1,849 10.7 434 446 2.8

Wyoming 994 1,041 4.7 169 148 -12.4

Oregon 3,897 4,064 4.3 1,339 1,224 -8.6

Washington 7,768 7,061 -9.1 2,595 2,456 -5.4

West Outside California 28,156 29,476 4.7 8,629 8,992 4.2

California 17,626 18,649 5.8 5,194 5,625 8.3

June

Arizona 5,248 5,827 11.0 2,058 2,517 22.3

Colorado 3,130 3,823 22.1 949 1,060 11.7

Idaho 1,898 2,249 18.5 460 446 -3.0

Montana 626 825 31.8 262 247 -5.7

Nevada 2,475 2,730 10.3 850 1,081 27.2

New Mexico 1,554 1,601 3.0 373 414 11.0

Utah 1,952 1,979 1.4 528 533 0.9

Wyoming 1,037 1,039 0.2 139 145 4.3

Oregon 3,859 4,312 11.7 1,139 1,185 4.0

Washington 7,462 6,978 -6.5 2,233 2,171 -2.8

West Outside California 29,241 31,363 7.3 8,991 9,799 9.0

California 19,225 21,867 13.7 5,720 7,084 23.8

Source: Energy Information Administration, Electric Power Monthly, August and September 2000.
2-12

Turning to the Cal-ISO area, Figure 2-6 shows daily peak-hour load from May to

August 2000. As the figure shows, peak load is volatile over a fairly wide range, sometimes

swinging rapidly from under 30,000 MW to over 40,000 MW. Managing these fluctuations

is a complex task under any circumstance, but it becomes even more difficult in a complex

market environment in transition. Forecasting load then becomes particularly important for

maintaining the reliability of the system.

Table 2-9 shows the average, day-ahead forecast and actual loads for the Cal-ISO area

over the last three summers. These data confirm the main conclusions from the temperature

and the state-level load data in Table 2-8. The Cal-ISO experienced much higher loads in

May and June compared with previous years. July was much more moderate and August loads

were higher but not as high relative to previous years as June loads. The percentage

differences in actual average loads from previous years, shown in Figure 2-7, bear these

conclusions out.

Figure 2-7 also shows that, on average, day-ahead forecasts and actual loads are close

as one would expect. While examining average loads is instructive, peak load forecasting is

central to reliable system operation. Accurate forecasting of peak loads is

25,000

27,000

29,000

31,000

33,000

35,000

37,000

39,000

41,000

43,000

45,000

1-May6-May

11-May16-May21-May26-May31-May

5-Jun

10-Jun15-Jun20-Jun25-Jun30-Jun

5-Jul

10-Jul15-Jul20-Jul25-Jul30-Jul4-Aug9-Aug

14-Aug19-Aug24-Aug29-Aug

Peak Load in Megawatts

Figure 2-6. Cal-ISO Load Curve, May to August 2000
2-13

Table 2-9. Cal-ISO Day-Ahead Forecast and Actual Average Loads, 1998 to

2000

May June July August May-August

Forecasts

1998 22,963 24,847 29,423 30,996 27,075

1999 24,276 26,736 29,022 29,113 27,291

2000 26,906 30,075 29,926 31,505 29,599

Actuals

1998 22,960 24,852 29,122 30,691 26,923

1999 24,171 26,609 28,878 29,016 27,173

2000 26,883 29,981 29,461 31,104 29,352

 essential for estimating peak supply requirements. The peak forecast and actual loads shown

in Figure 2-8 indicate how difficult peak conditions and forecasting became in 2000. While

May forecasts and actuals both tracked 1999 and 1998, the forecasts in 2000 began to

deviate as the summer progressed. Forecasts consistently exceeded actual loads. In August,

for example, forecasted loads increased over previous years (e.g., by 7.5 percent over 1999),

but actual loads decreased (e.g., by 0.9 percent over 1999) . 

 Percentage Changes in 2000 Compared to 1998 and 1999

0

5

10

15

20

25

Percentage Change 

Forecast 1999

Actual 1999

Forecast 1998

Actual 1998

Forecast 1999 10.8 12.5 3.1 8.2 8.5

Actual 1999 11.2 12.7 2 7.2 8

Forecast 1998 17.2 21 1.7 1.6 9.3

Actual 1998 17.1 20.6 1.2 1.3 9

May June July August May-Aug

Figure 2-7. Average Loads in the Cal-ISO, Day Ahead Forecast and Actual 
2-14

Part of this deviation between forecast and actual loads can be attributed to the

number of system emergencies that the Cal-ISO experienced in 2000, since during these

emergencies interruptible customers must reduce loads and public appeals are made for

voluntary load reduction. Cal-ISO issued 38 emergency notices over the summer, far more

than in prior years. These actions are summarized in Table 2-10.

The discussion thus far has concerned overall average or peak loads, but the offpeak

period (from 11:00 p.m. to 6:00 a.m.) also can be critical during the summer. This time is

used to pump water at pumped storage hydropower facilities, so these facilities can be used

to meet peak demands. These requirements create additional demand for energy to pump the

water and can be important in years with high temperature and low water such as 2000. Other

shifts in demand to offpeak can occur if customers can shift loads to avoid high onpeak

energy costs. Table 2-11 shows how the average offpeak loads increased in 2000 compared

with 1999.

Percentage Changes in 2000 Compared to 1998 and 1999

-10

-5

0

5

10

15

20

25

30

35

40

45

Percentage Change

Forecast 1999

Actual 1999

Forecast 1998

Actual 1998

Forecast 1999 20.3 11.4 -0.5 7.5

Actual 1999 20.8 6.2 -4.9 -0.9

Forecast 1998 36.2 29.3 6.4 1.6

Actual 1998 38.1 28.9 0.5 -2.8

May June July August

Figure 2-8. Peak Loads in the Cal-ISO, Day-Ahead Forecast and Actual 
2-15

Table 2-10. Electrical Emergencies Declared by the Cal-ISO (May- 

 August)

Emergency Type Action Taken 1998 1999 2000

Stage One: May be declared when

operating reserves of less than 7

percent are unavoidable or exist in

real time. 

Utility customers are urged to reduce their

use of electricity voluntarily to avoid more

severe conditions

3 3 24

Stage Two: May be declared when

operating reserves of less than 5

percent are unavoidable or exist in

real time. 

Voluntary interruption of services to select

customers is required to avoid more severe

conditions. These customers receive a

reduced rate electrical service as

compensation for their willingness to be

curtailed

3 0 14

Stage Three: May be declared when

it is clear that operating reserves of

less than one-and-a-half percent are

unavoidable or exist in real time. 

Utility customers are advised that

involuntary interruptions of service have

begun and will continue until the

emergency has passed.

0 0 0

Total 6 3 38

Table 2-11. Offpeak Loads in the Cal-ISO Area

 (Megawatts)

Average Hourly Loads Maximum Hourly Loads

1999 2000 1999 2000

May 20,036 21,609 25,475 29,043

June 21,245 23,567 30,096 32,439

July 23,007 23,318 33,702 31,848

August 23,035 24,268 31,132 32,946

May-August 21,835 23,187 33,702 32,946

2. Increased Exports from California

Increased exports from California are a key factor in understanding western supply in

the summer of 2000. These increases require offsetting imports to meet any given level of

load within the Cal-ISO area. Net imports, the total imports reduced by the amount of

exports, were significantly lower in 2000 compared with 1999. Figure 2-9 shows both

scheduled (through the hour ahead) and actual imports in real time in 1999 and 2000. Net

imports fell dramatically throughout the summer, in both scheduled and real-time categories. 

The biggest differences between 1999 and 2000 occurred in the scheduled net imports in

August, when scheduled net imports were 6,502 megawatts per hour in 1999 and 1,673 in
2-16

2000. An additional 1,542 megawatts of imports appeared in real time, reducing the

difference from last year.

The decrease in net imports is generally attributable to increases in exports, not

decreases in imports, as Figure 2-10 clearly shows. In 2000, imports remained virtually

unchanged throughout the summer. In 1999, some increases in imports occurred, but the

leading fact shown in Figure 2-10 is the increase in exports for each month from May to

August 2000, from an hourly average of 1,831 megawatts in May to 4,851 megawatts in

August, an increase of 3,020 megawatts. Comparable export increases in 1999 occurred, but

they were small. Compared with August of 1999, August 2000 exports averaged 3,136

megawatts above the August 1999 level. This period of increased exports corresponds to the

periods in July and August when the price cap in the ISO was reduced from $750 to $500 and

then to $250. This correspondence does not necessarily show price caps caused increased

exports; however, other things being equal, lower price caps may provide for greater profits

from exports if conditions outside California lead to high prices and create greater

opportunity costs.

Although most exports are from the SP15 zone in southern California, increases were

not limited to SP15 (see Table 2-12). SP15 experienced an increase in offpeak exports from

May to August of 1,385 megawatts over a May quantity of 1,038; the NP15 zone in northern

California had an increase of 766 megawatts over the much smaller base of 223 megawatts in

May. Exports from the NP15 zone are typically offpeak and may be related to pumping at

hydropower facilities or maintaining storage levels at conventional hydro facilities to

conserve water, particularly later in the summer. Offpeak exports followed the same pattern

as overall exports, as the daily graph of offpeak exports in Figure 2-11 shows, when

compared to the overall pattern of increases from May through August.
2-17

Average Hourly Net Energy Imports, Scheduled and Real Time

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Net Imports, Megawatts

Scheduled 1999 6107 5804 6748 6502 6294

Real Time 1999 6050 5812 6740 6664 6321

Real Time 2000 5489 4501 3770 3215 4241

Scheduled 2000 4704 3598 2960 1673 3231

May June July August May-August

Figure 2-9. Net Summer Imports into Cal-ISO, 1999 and 2000

-6,000

-4,000

-2,000

0

2,000

4,000

6,000

8,000

10,000

Megawatted Imported(+)/Exported(-)

Imports 1999 7214 7471 8784 8489 7994

Imports 2000 6534 6593 6807 6524 6615

Exports 1999 -1107 -1667 -2036 -1987 -1700

Exports 2000 -1831 -2995 -3846 -4851 -3384

May June July August May-August

Figure 2-10. Imports and Exports, Average Hourly, 1999 and 2000
2-18

Table 2-12. Summary of California Exports and Imports by Zone

May June July August May-August

SP15 Zone

Imports 1999 4,441 4,222 5,426 5,645 4,939

Imports 2000 4,590 4,841 4,547 4,790 4,691

Exports 1999 -859 -1,310 -1,171 -1,088 -1,105

Exports 2000 -1,038 -1,758 -1,828 -2,423 -1,762

Net Imports 1999 3,582 2,912 4,255 4,557 3,834

Net Imports 2000 3,552 3,083 2,719 2,368 2,929

Real Time 1999 3,554 2,811 4,132 4,533 3,765

Real Time 2000 3,784 3,169 2,846 2,447 3,061

NP15 Zone

Imports 1999 1,561 2,147 2,408 2,090 2,051

Imports 2000 1,074 1,210 1,113 1,182 1,144

Exports 1999 -61 -7 -34 -91 -49

Exports 2000 -223 -385 -580 -989 -546

Net Imports 1999 1,500 2,140 2,374 1,999 2,002

Net Imports 2000 851 825 533 193 598

Real Time 1999 1,444 2,123 2,335 2,029 1,981

Real Time 2000 1,187 1,177 770 717 961
2

 RDI Powerdat, September 2000.

2-19

3. Increased Plant Outages

An increased level of unplanned outages at generating plants is another key factor 

limiting available generation supply in 2000. California has a large number of natural gas

fired plants. Natural gas steam plants make up most of this capacity and constitute 36

percent of the total generating capacity in the state. These steam plants are old and hence

prone to outages; 82 percent of these plants are over 30 years old, and 37 percent are over 40

years old.2 Outages in 1999 and 2000 are shown in Figure 2-12 for January through August. 

The level of unplanned outages increased through August compared with last year; there were

3,391 megawatts out of service (hourly average megawatts out during the month) in August

2000 compared with 604 megawatts in August 1999. This difference of 2,787 megawatts has

a clear effect on supply at peak times, even though the level as a percentage of the 45,000

megawatts of installed capacity may not be out of the normal range for comparable plants. It

is not clear exactly why these plants went out of service. Detailed analysis of specific causes

was not possible for this investigation. Review of cited reasons by plant operators in

available records showed the normal pattern of explanations for a peak summer period, such

as tube leaks at steam facilities and other 

Hourly Averages by Day, May 1 to Aug 31

0

1,000

2,000

3,000

4,000

5,000

6,000

1-May8-May15-May22-May29-May5-Jun12-Jun19-Jun26-Jun3-Jul10-Jul17-Jul24-Jul31-Jul7-Aug14-Aug21-Aug28-Aug

Average Exports (Megawatts)

Exports 1999

Exports 2000

Figure 2-11. Offpeak Export Demand, 1999 and 2000
2-20

similar causes, but it was not possible to confirm the accuracy of such judgments. Most

outages were for short durations (see Table 2-13), with 59 percent occurring for one day or

less, so a detailed analysis would be very time consuming.

There are several potential explanations for the increased level of outages. Figure 2-

12 indicates a much lower level of planned maintenance in January through April 2000

compared with January through April 1999, so one possibility is that fewer resources are

being devoted to planned maintenance. Lack of planned maintenance could be particularly

important for older facilities. Given the short duration of outages, the increased number

could reflect attempts to fix small problems in preparation for high load conditions. New

owners, for example, could be attempting to maximize the availability of their facilities at

peak times when the price is high. A final possibility is just the opposite: owners could be

withholding by taking plants out of service at critical times to drive up prices. The difficulty

here is twofold. First, the same general pattern of events permits completely contrary

explanations in terms of efficient behavior. Second, specific instances alone may not serve

to prove a general pattern, will be hard to substantiate, and cannot be fairly attributed to

individual participants without further investigation of these specific cases.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Month

Average Megawatts Out of Service

Planned 1999

Planned 2000

Unplanned 1999

Unplanned 2000

Planned 1999 4145 5791 6735 8774 3361 882 660 586

Planned 2000 2886 3083 3531 6140 2702 1349 1039 724

Unplanned 1999 801 957 1506 1508 1877 1516 1204 604

Unplanned 2000 2187 1158 1420 1124 2331 2688 2666 3391

Jan Feb Mar Apr May Jun Jul Aug

Figure 2-12. Comparison of Average Megawatts Out of Service in the Cal-ISO 

 Planned and Unplanned, 1999 and 2000
2-21

Table 2-13. Percent of Unplanned Outages by Duration, Cal-ISO 

 Units, 1999 and 2000

Duration 1999 2000

1 day or less 65.0 59.0

1 to 2 days 69.9 67.6

Less than 2 weeks 85.7 91.7

Some information can be gained by examining the level of outages and their timing. 

By examining the correlation between outage levels and price increases in the PX, one can

roughly measure the association of the two series. These correlations are presented in Table

2-14, which shows the correlation of outage levels and PX prices, as a function of when the

outage occurs. For example, the correlations in the category “Day of price increase” is

measured between the outages on a particular day and the PX price on that day for deliveries

on the following day. The category “1 Day before price increase” measures the correlation

based on the level of outages on the day before the price is determined in the PX, and so on. 

Table 2-14. Correlation of Outages with the PX UMCP, May to August 

 2000

Outage Occurs Correlation

2 days before price increase 0.38

1 day before price increase 0.50

Day of price increase 0.46

1 day after price increase 0.40

The correlations show an association between outage levels and price increases, which

is not surprising in itself. Outage levels would be expected to increase when prices are high,

simply because loads increase and less reliable facilities are pressed into service under

conditions of stress. The data also indicate, however, that the correlation is highest when the

outages occur one day before the price increase. As noted above, facts such as these can be

explained in a number of ways, but they do suggest that there may be more to the explanation

than a simple physical response to running generating plants at higher levels under high load

and price conditions.

4. Scheduling of Supply and Demand in California
2-22

California day-ahead and hour-ahead markets saw a marked migration of supply and

demand to real time markets and exports. Many of the imports were not scheduled and

arrived in real time. A similar pattern for loads is shown in Figure 2-13, which shows the

degree of underscheduling relative to day-ahead markets faced by the Cal-ISO. Figure 2-13

shows the change in underscheduling from 1999, as well as the amounts forecast and the

actual results. As seen from the figure, in June and August, forecasts of load were much

higher than in 1999, but scheduled load was much lower. The result is that the Cal-ISO is

forced to purchase supplies in order to be able to meet load in real time. It can do this either

by buying more replacement reserve or going out of market for real-time energy 

when insufficient generation is scheduled to meet final hourly forecast quantities. The CalISO pursued both of these approaches in 2000.

The problem of underscheduling is not new in 2000, as can be seen in Figure 2-14,

which examines day-ahead underscheduling. What has changed, however, is the level of load

at which underscheduling occurs. In Figure 2-14, which shows the detailed pattern of 

-15

-10

-5

0

5

10

15

20

25

Percentage Change 2000 v 1999 

Forecast 2000 v 99

Sched 2000 v 99

Actual 2000 v 99

Forecast 2000 v 99 20.3 11.4 -0.5 7.5

Sched 2000 v 99 9.4 -2.5 -7.2 -12.3

Actual 2000 v 99 20.8 6.2 -4.9 -0.9

May June July August

Figure 2-13. Percentage Change from 1999 in Year 2000 Peak Forecast

 Scheduled and Actual Loads
2-23

-10,000

-5,000

0

5,000

10,000

15,000

20,000

15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

Forecast Load (Megawatts)

Forecast Megawatts minus Scheduled Megawatts

Underscheduled 2000

Underscheduled 1999

Underscheduled 1998

Figure 2-14. Scatter Diagram of Underscheduling, PX Day-Ahead Market

-4,000

-2,000

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Minimum Megawatts Underscheduled

Under 20 GW 20 to 25 GW 25 to 30 GW 30 to 35 GW 35 to 40 GW 40 to 45 GW Above 45 GW

June

July

August

Figure 2-15. Underscheduling: Minimum Megawatts Underscheduled in PX Day- 

 Ahead Market, by Load Range and Month
2-24
2-25

underscheduling as a function of load levels in 1998, 1999 and 2000, the observations for

2000 stretch out above the observations for 1998 and 1999 whenever the load grows above

35,000 megawatts. It also appears as if the load levels where underscheduling begins were

lower in August than in June or July. Figure 2-15 shows the minimum underscheduling

within load ranges. The minimum is the smallest difference between the forecasted load (day

ahead) and the amount of load scheduled day ahead, for all hours when load fell within the

range. This number will be negative if more supply/load is scheduled than forecast

(overscheduling), and positive if less load/supply is scheduled (underscheduled.) 

Underscheduling normally increases as load increases, so that when load reaches a certain

level, underscheduling always occurs and the minimum underscheduling will be positive. In

August, the graph shows that underscheduling always occurred when the load was above

25,000 to 30,000 megawatts. The graph shows that underscheduling began to occur at lower

and lower load levels from June through August, indicating that the problem of

underscheduling became greater through the summer.

5. Generation Capacity Availability and Utilization

Previous sections have discussed factors contributing to limiting supplies of

generation capacity in California and the western states generally. These factors bear on the

reasons for any scarcity of available generation capacity. In this section, we review the

evidence available to this investigation to assess the degree of that scarcity. We first review

the role of hydropower in the supply of power in the West, and note the impact of

hydropower availability on generation in May and June. Next we describe the availability of

generation in the WSCC for a key summer week when California experienced several

emergency periods and made a number of out of market calls for emergency imports of

energy. Finally we look in greater detail at the availability of generation within the Cal- ISO

during one hour of that week. 

Hydropower Availability

Hydropower resources are central to the western resource mix. Although most

regions depend on hydropower to some degree, the presence of such a large proportion of

hydropower resources in the West introduces operational complexities not present in power

systems in other regions. The capacity to produce power from hydro facilities depends on

the availability of water, which in turn is heavily dependent on the amount of water run-off in

the spring. Adding to these limitations are environmental restrictions that determine the

amount of water that must be “spilled,” that is, the amount required to pass 
2-26

over a dam or through a generating facility without going through the turbines and generating

electricity. Because these types of restrictions vary with time, and in order to put the water

to its highest-valued use, the dispatch of hydropower needs to carefully balance current and

future values to optimize the use of the underlying resources. As a result of these factors,

the actual physical capability of a generating unit is often not the element limiting the ability

of a hydropower facility to provide power to the grid.

0

20

40

60

80

100

120

140

160

180

1992 1993 1994 1995 1996 1997 1998 1999 2000

Water Year (Oct-Sept)

Million Acre Feet (MAF)

Source: Bonneville Power Administration, web page: http:\www.bpa.gov

30-year average 106 MAF

Figure 2-16 Volumes of Run-Off at the Dalles, January to July
2-27

These limitations played a large role in the availability of hydropower in the summer

of 2000. The volume of spring run-off was the lowest in several years in the 

Northwest, as shown in Figure 2-16. In California, the run-off fell below the 50-year average

after 5 years of higher than normal flows (see Figure 2-17.) The impact of low water levels

was seen in dramatically reduced generation from hydropower in May and June 2000

compared with 1999. Table 2-15 shows how extensive the shortfall in generation was:

outside California, June 2000 generation from hydropower was 23.2 percent below June

1999 levels.

With reduced hydropower generation and increased load, the West needed much more

generation from thermal and other non-hydropower resources. Generation from non-hydro

resources increased by 15.1 percent in May and 24.9 percent in June (Figure 2-18).

Table 2-15. Hydroelectric Generation in the West, 1999 to 2000

 (Thousand Megawatthours)

0

10

20

30

40

50

60

70

80

1993 1994 1995 1996 1997 1998 1999 2000

Water Year (Oct-Sept)

Million Acre Feet

Source: California Department of Water Resources, web page: http:\cdec.water.ca.gov

50-year average 41 MAF

Figure 2-17. Volumes of Run-Off, California Statewide Total, October to July
2-28

May June

State 1999 2000 % Change 

1999 to 2000

1999 2000 % Change 

1999 to 2000

Arizona 1,005 1,051 4.6 937 654 -30.2

Colorado 166 163 -1.8 161 178 10.6

Idaho 1,262 814 -35.5 1,201 939 -21.8

Montana 1,057 564 -46.6 1,328 757 -43.0

Nevada 279 294 5.4 254 208 -18.1

New Mexico 27 21 -22.2 31 24 -22.6

Utah 156 105 -32.7 160 80 -50.0

Wyoming 173 96 -44.5 205 127 -38.0

Oregon 3,999 3,576 -10.6 4,277 2,853 -33.3

Washington 8,087 8,131 0.5 8,131 6,988 -14.1

West Outside California 16,211 14,815 -8.6 16,685 12,808 -23.2

WSCC Capacity and Generation, July 31 to August 4, 2000

Aggregate monthly totals suggest that power supplies were often tight during the

summer, but they do not provide very specific evidence about whether overall western

supplies were scarce when California experienced emergency conditions and required

emergency imports to prevent the loss of firm load. The week of July 31 to August 4 was

such a period in California. The Cal-ISO had emergency conditions each day during that

week and had a high number of out of market calls for power from external sources. To

determine what other supplies were available in the West, each control area in the WSCC was

asked to provide information on loads, generating capacities and generation for hour 16 on

each day. From this information, it was possible to determine the percentage of capacity in

the West available and used for generating electricity. The results are shown in Table 2-16.
3The forced outage rate depends on how the category, "capacity online but not

generating" was treated in the projected August capacity, and could be higher if these

capacities were not included in the projected amounts.

2-29

The first line in Table 2-16 shows the percent of projected capacity that was

unavailable. This percentage is approximately equal to the forced outage rate, because the

projected August capacity included reductions for any planned outages.3 These percentages

range from 4.4 to 5.4. Given the way hydropower resources are used, some hydropower

capacity that was not forced out may have been available, but not placed online for generating

power due to environment and other limitations on its use for power generation, discussed

above. For this reason, a separate category was used for resources available but not on line. 

As shown in Table 2-16, this percentage varied from 3.6 to 6.2 during the week.

-30

-20

-10

0

10

20

30

Percent Change, 1999 to 2000

May

June

May -4 15.1 7.3

June -22.9 24.9 4.8

Hydro Non-hydro All Sources

Figure 2-18. Percent Change in MWh Generated in WSCC, 1999 to 2000
2-30

Table 2-16. Summary of WSCC Capacity Availability During the Week July 31

to August 4, 2000

31-Jul 1-Aug 2-Aug 3-Aug 4-Aug

Percentages

Projected August Capacity Unavailable 4.8 5.0 5.0 4.4 4.7

Capacity Available but Not Online 4.3 4.7 3.6 4.7 6.2

Available Capacity Online but Not Generating 11.0 9.5 12.0 11.0 10.1

Online Hydro not Generating 17.6 16.0 20.1 17.2 17.6

Online Non-Hydro Not Generating 6.6 5.0 6.4 6.8 4.8

Projected August Generating Capability=155,283 MW.

Finally, the remaining capacity after the reductions discussed in the last paragraph will

be online for use either to generate electricity or to provide reserves. The percentages of

total online capacity not generating output vary from 9.5 to 12.0 percent. For nonhydropower resources, these percentages are much lower than for hydropower resources:

from 4.8 to 6.8 percent of online capacity. Hydropower resource percentages are higher,

from 16.0 to 20.1 percent, but these resources may not be available for export outside the

local control area, or may be available only for short periods.

These data show that online supplies of non-hydropower resources were very limited

during the week of July 31 to August 4, not more than 6.8 percent, and do not suggest that

additional online hydropower was likely to be available for export to California.

Capacity Utilization at the Cal-ISO on August 4

Further specific information on the use of resources in California is provided in Table

2-17, which shows the use of resources by category of resource at hour 16 on August 4. The

table shows high utilization of all resources except hydro and must take resources. The

percentage of hydro resources not generating was 26.0 percent, the percentage of nonnuclear must take resources not generating was 30.9 percent. The hydropower resources

may be subject to the types of limitations discussed above, and the percentages shown are

only slightly higher than those in the overall statistics for the West discussed above. Thermal

must-take resources include a large number of qualifying facilities, which includes capacity

used for other purposes, such as internal uses or steam generation, so these resources may be

used for alternate purposes. Discussions with Cal-ISO staff confirmed that these resources

are generally limited by the quantity of energy available for bid, rather than by the total

physically installed capacity. For all remaining resources combined (coal, nuclear, and other

thermal categories,) only 2.7 percent were not scheduled or bid. One category where the

owner of the facility has the discretion to bid or schedule the unit without bidding, the “Other
2-31

Thermal (excluding RMR)” category, shows a higher percentage unscheduled or not bid than

others, 8.6 percent. This quantity may represent owners holding back capacity to use if other

scheduled units have outages, but it is not clear whether this is the reason or not. In any case,

this quantity is a small amount of the total capacity neither scheduled nor bid, and does not

suggest a large amount of withholding, regardless of the intent underlying the failure to

schedule the capacity.

Table 2-17. Summary of Capacity Available and Energy Supplied in the Cal- 

 ISO at Hour 16 on August 4, 2000

Resource Category

Coal Hydro Nuclear

Other Thermal

(Excluding

RMR)

Reliability

Must Run

(RMR)

Must

Take

All

Categories

Total Capacity 1,540 12,117 4,414 5,533 14,175 8,579 46,358

Capacity Unavailable for

Scheduling 790 26 572 1,889 3,277

Net Available 750 12,091 4,414 4,962 12,286 8,579 43,081

Capacity Scheduled/Bid 680 8,952 4,347 4,533 12,241 5,927 36,680

Capacity Not Scheduled or

Bid 70 3,138 67 429 45 2,652 6,401

Percent Not Scheduled or

Bid vs. Net Available 9.3 26.0 1.5 8.6 0.4 30.9 14.9

For the peak hour shown in Table 2-17, there does not appear to be a significant

concern about resources not used. It is possible that resources are fully used at peak times

when prices are high, but resources that are economic at other times are held off the market

in an attempt to drive up prices. Further work would be necessary to study other hours to

examine whether patterns vary at other times. This work could not be conducted within the

time frame of the present investigation.

6. Transmission Congestion

Transmission patterns on California paths during May through August shifted from

1999 to 2000. Table 2-18 shows the percent of hours when transmission congestion

occurred on major California paths in 1999 and 2000. In 1999 during peak hours, there was a

lot of congestion on paths into California from the Northwest. The California Oregon

intertie (COI) and the DC tie (NOB) were both congested a substantial portion of the time, as

seen in Table 2-18. In 2000, much of this congestion was not present, due in part to the

reductions in net imports, but a greater amount of congestion occurred on the major paths

within California, Path 15 and Path 16. 
2-32

Offpeak periods saw shifts as well. Congestion arising from imports from the

Northwest and the Southwest virtually disappeared, but export congestion, mainly on paths

from south to north, began to be important. These flows from south to north became more

prominent in July and August. For example, NOB was congested for exports (south to north)

for 40 percent of the offpeak hours and Path 15 south to north was congested 88 percent of

the time during offpeak hours.

Table 2-18. Percentage of Time Major California Transmission Paths 

 Congested, May through August, 1999 and 2000

Transmission Path 1999 2000

Difference

 (2000 minus 1999)

Onpeak Congestion

Imports over Cal-Oregon Intertie (COI) 36.1% 0.3% -35.8%

Imports from Oregon over DC Tie (NOB) 17.6% 8.0% -9.6%

North to South on Path 15 1.0% 7.9% 6.9%

North to South on Path 26 0.0% 29.2% 29.2%

Offpeak Congestion

Imports over Cal-Oregon Intertie (COI) 21.9% 0.0% -21.9%

Imports from Southwest over Eldorado

Path

21.0% 3.0% -18.0%

Exports Oregon over DC Tie (NOB) 0.2% 13.5% 13.3%

South to North on Path 15 28.1% 49.6% 21.5%