Winter 2001-2002 Power Supply Adequacy 

FRANK L. CASSIDY JR. 

"Larry"

CHAIRMAN 

Washington 

Tom Karier 

Washington

NORTHWEST POWER PLANNING COUNCIL 

851 S.W. SIXTH AVENUE, SUITE 1100 

PORTLAND, OREGON 97204-1348

ERIC J. BLOCH 

VICE CHAIRMAN

Oregon 

John Brogoitti

Oregon

Jim Kempton 

Idaho 

Judi Danielson 

Idaho 

Fax: 

503-820-2370

Phone:

503-222-5161

1-800-452-5161

Internet: 

www.nwcouncil.org

Leo A. Giacometto

Montana 

Ed Bartlett 

Montana 

Analysis of Winter 2001-2002 Power Supply Adequacy 

1.0 Overview 

The Council released its last assessment of Northwest power supply adequacy for the 

winter of 2001-2002 in early June of this year. That assessment relied on data, 

assumptions and analysis largely developed over the previous month. It found that given 

the then-current assessments of the demands for electricity across summer and 

subsequent fall and winter, new generation, and hydro conditions, the probability of 

winter season power supply inadequacy was approximately 17 percent.1

 The analysis 

went on to assess the efficacy of storing additional energy in Arrow reservoir in Canada 

in reducing winter power supply problems. It was found that storing an additional 1,500 

megawatt-months of energy (in addition to 1,200 megawatt-months already planned to be 

stored) reduced the probability of inadequacy to about 12 percent. Additional amounts of 

storage did not significantly reduce the probability, largely because of restrictions on the 

rate at which water could be withdrawn from the reservoir. On the basis of this and other 

similar analyses, decisions were made to dramatically reduce spill at federal hydroelectric 

projects and seek additional opportunities for reducing electricity demands. 

The Council recently completed a reassessment of the winter power supply situation 

based on updated data and analyses. This analysis found the probability of winter season 

power supply inadequacy to be well under the target level of 5 percent. This is attributed 

primarily to two factors. First, expected demands for electricity are significantly lower 

than estimated in the May analysis. This is attributable to several factors: efforts on the 

part of utilities to buy out industrial loads, particularly the aluminum industry; 

conservation efforts, the expected effects of retail rate increases and the general 

slowdown of the economy. The other major factor is improved hydro storage conditions. 

Instead of 1,500 megawatt-months of energy stored in Canada, 3,700 megawatt-months 

were stored.2

 This additional storage was made possible by the drastically reduced spill 

this summer and by the fact that loads were lower that expected throughout the West. In 

 

1

 The winter season is defined as the months of December, January, February and March. A winter season 

was judged to have an inadequate power supply if loads exceeded available energy by a seasonal average of 

10 average megawatts or more. 2

 This is in addition to the storage of 1,200 megawatt-months of energy that was already planned and was 

included in both the May and October studies. 

11/15/2001 1
Winter 2001-2002 Power Supply Adequacy 

addition, the constraints on the rate at which this energy could be withdrawn were 

relaxed, making the stored energy more effective in addressing periods of high demand. 

The analysis and the results are described in more detail in the following sections. 

2.0 Modeling System 

Power supply inadequacy is generally the result of a combination of adverse events. 

Energy shortfalls are typically the result of a combination of low hydropower production 

as a result of poor water conditions, high loads as a result of extreme temperatures, 

reduced thermal powerplant output as a result of forced outages and the inability to fully 

compensate for these factors with additional energy from either regional resources or

imports. It is possible to conduct a scenario analysis that shows that if certain conditions 

occur, there is or is not a problem and the magnitude of that problem. However, that does 

not predict how likely such a situation is. To determine the probability of power supply 

being inadequate, it is necessary to look at the probability of circumstances combining to 

cause the situation. 

The Council’s power supply adequacy studies have used a Council-developed model of 

the Northwest power system called GENESYS. The structure of the model is illustrated 

in Figure 2-1. 

Figure 2-1 – GENESYS Structure 

PNW-W PNW-E

BC AB

N CA

Seasonal, On-Off Peak S CA/DSW

Supply Curves for

areas outside NW

Seasonal, On-Off Peak 

Supply Curves for

areas outside NW

Forecast loads for normal weather, known 

extra-regional contractual commitments; 

forecast generating resource schedules

Forecast loads for normal weather, known 

extra-regional contractual commitments; 

forecast generating resource schedules

Monte Carlo 

simulation of hourly 

system operation 

including:

• Hydro generation as 

function of water year;

• Scheduled and forced 

generation outages;

• Temperature-driven 

loads;

• Transmission flows

• Imports

• Reserves

Monte Carlo 

simulation of hourly 

system operation 

including:

• Hydro generation as 

function of water year;

• Scheduled and forced 

generation outages;

• Temperature-driven 

loads;

• Transmission flows

• Imports

• Reserves

11/15/2001 2
Winter 2001-2002 Power Supply Adequacy 

GENESYS models the operation of Northwest power system in detail. It can be run for 

different time intervals down to hourly simulations. The important stochastic variables 

are the hydro conditions, temperatures as they affect electricity loads and forced outages 

on thermal generating units (both occurrence and duration). The model runs hundreds of 

simulations of the study period. For each simulation it samples hydro conditions, 

temperatures and the outage state of thermal generating units according to their 

probability of occurrence in the historic record. The percentage of simulations that result 

in resource inadequacy is the probability of inadequacy or “loss of load probability”. The 

output can also be analyzed to look at the frequency of problems as a function of their 

magnitude. 

The model splits the region into an eastern portion and a western portion to capture the 

possible effects of cross-Cascade transmission limits. A monthly load forecast 

corresponding to “normal” temperatures is an input to the model. The model shapes 

monthly loads to sub-daily loads for the East and West parts of the region for the 

temperature year being modeled. The amount of non-hydro generation in the region is 

also an input to the model as are contractual commitments for import or export from the 

Northwest and the availability of additional spot-market imports to the region. 

An important feature of the model is the ability to model the operation of the system

more like it would actually be run in an emergency situation. In such a situation, the 

hydro system would be drafted deeper to meet loads. Operators would subsequently try 

to restore reservoir levels by running thermal units harder and purchasing imports. 

In the following sections, the assumptions and analyses going into the inputs for the 

model for the winter 2001-02 period are described. 

3.0 Demand Forecast 

3.1 Recent Electricity Demand Patterns 

Before trying to predict future electricity demand, it is important to look at where it has 

been and how it has responded to the recent chaos in western electricity markets. 

Figure 3-1 gives a long-term perspective on regional electricity demand growth. The first 

growth interval illustrated in Figure 3-1 is 1970 to 1980. During this period, electricity 

use grew at 3.6 percent annually. This was a substantial reduction from the growth rates 

experienced in the previous 20 years; from 1950 to 1970 electricity demand grew by 

about 7 percent a year, adding over 400 megawatts of demand each year. Although the 

growth rate was cut in half during the 1970s, the number of megawatts added to demand 

each year increased to 500 megawatts per year, a result of growing from a larger base. 

11/15/2001 3
Winter 2001-2002 Power Supply Adequacy 

Figure 3-1 

Total Regional Electricity Sales 

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197019721974197619781980198219841986198819901992199419961998

Average Megawatts

3.6 % Annual Growth

1.6% Annual Growth 1.2 % Annual Grow

Beginning in 1980, the region experienced a watershed in terms of electricity demand 

growth. The growth rate halved again and the number of megawatts of demand added 

each year fell to 300, from 500 in the previous decade. In some ways the influences 

acting on electricity demand in the early 1980s are similar to current conditions. 

Regional power costs increased by nearly 500 percent between 1979 and 1984, and the 

region experienced a serious economic downturn during 1982 and 1983. Growth during 

the 1990s has averaged 1.1 percent annually, adding only 220 megawatts of demand each 

year. 

The long-term electricity demand forecasts in the Council’s Fourth Northwest Power 

Plan medium case grew at 1.3 percent per year from the 1994 actual level to the year 

2015. Evaluation of those forecasts during the late 1990s shows that the forecasts are 

tracking actual demand quite closely through 1999.3

 However, recent events are causing 

a cyclical departure from the Council’s long-term forecasts that will continue for the next 

few years. 

Figure 3-2 illustrates the magnitude of demand reductions that have taken place in recent 

months. The figure shows the percent change in temperature-adjusted electric loads from

the same month in the previous year. Significant declines started in the second half of 

2000 and reached a decrease of 20 percent for July 2001 from July 2000 levels. This 

amounts to a decrease of about 4,000 megawatts of load. 

 

3

 “Economic and Electricity Demand Analysis and Comparison of the Council’s 1995 Forecast to Current 

Data.” Council Publication 2001-23, September 2001

11/15/2001 4
Winter 2001-2002 Power Supply Adequacy 

Figure 3-2 

Monthly Load Changes from Previous Year 

-25.0

-20.0

-15.0

-10.0

-5.0

0.0

5.0

January

February

March

A

pril

May

June

July

August

Septem

ber

Octo

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N

ovem

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Decem

ber

January

February

March

A

pril

May

June

July

August

Percent Change

2000 2001

Seventy percent of this load reduction was a result of large electricity-using industries 

closing, most notably aluminum smelters(see Figure 3-3). Bonneville or other regional 

utilities bought out many of these loads in order to save money on expensive power 

purchases. Some of these buyouts were of irrigation loads during the summer months. 

The other 30 percent of load reductions were savings by residential, commercial, or 

smaller industrial users. Retail consumers had seen price increases on average of about 9 

percent by July 2001 and their response with about a equal percentage drop in demand is 

a greater demand reduction than would be expected based on typical short term price 

elasticity estimates. The larger demand response was undoubtedly due to a high degree 

of publicity surrounding the California market problems, high wholesale electricity 

prices, Governors’ appeals for conservation, and enhanced utility conservation programs. 

Combined, these factors probably reduced demand by the equivalent of four 250 

megawatt combined cycle power plants. 

11/15/2001 5
Winter 2001-2002 Power Supply Adequacy 

Figure 3-3 

Composition of Summer 2001 Load Reductions

DSI

58%

Other

30%

Shutdowns

7%

Buyouts

5%

3.2 Load Forecasts 

3.2.1 Methods 

The basic hypothesis in predicting how loads might behave over the next few years is that 

loads will return to the long-term forecast trend over the next two to four years. There 

are several key factors to consider: 

• The effects of further retail price increases 

• The extent and duration of the economic recession and its effect on loads

• The effect of sharply lower wholesale prices and the avoidance of outages last 

summer 

• Potential renegotiation of buyouts and their timing 

• The duration of recent retail price increases in the face of dropping wholesale 

prices 

• The persistence of electricity use reductions that are not the result of “permanent” 

measures (e.g., installing a more efficient water heater) as prices are lowered from

crisis levels

• The effect of currently depressed aluminum prices on resumption of aluminum

production. 

For the present, the forecast is limited to one path. This is not to imply that there is great 

certainty about the forecast. The effects of the factors listed above are not known with 

any certainty. The forecast is intended to reflect a realistic future, but it is also intended 

to be somewhat optimistic about the recovery of electricity loads. When exploring the 

reliability of the electricity system it is prudent to erron the high side of demand while not 

being overly optimistic because errors on either side of future demands have potential 

costs for the region. 

11/15/2001 6
Winter 2001-2002 Power Supply Adequacy 

The Council has no models that are practical and useful for addressing the near-term

future of electricity loads. Therefore the forecasts are judgmental and intuitive. The 

approach has been to try to predict the further reduction and recovery of each of the 

major categories of load reductions shown in Figure 3-3. The return of direct service 

industry loads (primarily aluminum smelters), bought out industries and other large 

industrial shutdowns were each assumed as to timing and degree. Similarly, the pattern 

of recovery for the remaining loads has been hypothesized. The assumptions reflect 

thinking about the factors listed above, but the links are not direct or automatic in the 

absence of some type of model to tie the assumptions to the results. 

3.2.2 Results 

The electricity load forecast approach and results are summarized in Figure 3-4. It shows 

the Council’s Fourth Northwest Power Plan forecast allocated to monthly patterns in the 

upper line. The lower line is the new short and mid-term forecast. The forecast shows a 

recovery from the current situation, shown in the shaded area of the graph, back to the 

long-term trend forecast of the Fourth Northwest Power Plan. Loads remain depressed 

through the remainder of 2001 and into the middle of 2002. In mid-2002, loads begin to 

recover toward the long-term trend. By 2004 the mid-term load forecast has nearly 

recovered from the recent electricity crisis and the economic weakness of the economy. 

The forecast is generally consistent with the expectation of an economic recession that 

stretches through the first quarter of next year. It also reflects an assumption that 

although retail prices of electricity have increased significantly more in the past weeks 

than in the year to date, the impact on demand will be more in line with traditional 

elasticity estimates than what has been observed to date this year. The reasoning is that 

(1) the crisis is widely believed to be a thing of the past and will receive far less attention, 

and (2) that wholesale prices have fallen to low levels and will exert less influence on 

utilities and large consumers that may be exposed to wholesale prices. At the same time, 

the economic recession and the depressed state of the aluminum industry will likely delay 

the reopening of most electricity-intensive plants until at least next spring or summer 

even though relatively low-priced wholesale electricity may be available. 

11/15/2001 7
Winter 2001-2002 Power Supply Adequacy 

Figure 3-4 

Total Regional Electricity Loads 

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1999200020012002200320042005

4th plan Loads

Forecast

Forecast History

Figure 3-5 shows the difference in the demands used in the May study compared with 

those in the current study. Some of the difference is attributable to assumptions about the 

DSI loads. At the time of the May study, not all of the direct service industries had 

signed buy-back contracts and it was believed that it was possible some of them could put 

load back on as early as October. The May analysis also did not take into account 

quantitatively the several factors noted earlier that could keep loads down through this 

winter. 

Figure 3-5 

Comparison of Loads from May and Current Studies 

Demand Comparison

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Jan-02

Mar-02

May-02

Jul-02

Averag

e M

e

g

a

w

atts

May Study

Oct Study

Oct-Mar Difference = 11000 MW Mo

11/15/2001 8
Winter 2001-2002 Power Supply Adequacy 

Figure 3-6 illustrates the assumed recovery of the Bonneville direct service loads. A 

couple of the most viable plants come back on line in April 2002 with additional restarts 

spread over the next couple of years. It is not expected that all aluminum plants will 

return to production in the long run. Other large consumers that were bought out or shut 

down are assumed to fully recover by September 2002. 

Figure 3-6 

DSI Load Assumptions 

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200020012002200320042005

Average Megawatts

Apr-02

4.0 Hydro Conditions 

For a reliability assessment, three factors are important: the initial reservoir contents for 

the U.S. reservoirs at the beginning of the water year (September 1) the amount of 

additional energy that may have been stored by mutual agreement in Canada’s Arrow 

Lake and the runoff volume. 

4.1 Storage 

The hydroelectric system’s annual operation begins in September when reservoirs should 

be at their highest elevations, in anticipation of the peak demand season. This year U.S. 

reservoirs effectively refilled to the levels specified in the Biological Opinion (BiOp). 

This is what was assumed in the May analysis. In addition, water equivalent to 

approximately 3,700 megawatt-months of energy was stored in Canada’s Arrow Lake. 

This is 2,200 megawatt-months more than was assumed in the May analysis. This was 

made possible by the reduction in spill at federal projects across the summer as well as 

lower than anticipated summer loads throughout the West.4

 In total, approximately 7,000 

megawatt-months of energy that normally would have been spilled to aid the downstream

migration of juvenile salmon and steelhead, was not spilled. That energy was used to 

meet loads, particularly in the late spring and early summer when much thermal 

 

4

 Spill passes water over dams rather than passing water through the turbines to produce electricity. 

11/15/2001 9
Winter 2001-2002 Power Supply Adequacy 

generation was down for scheduled maintenance; to help restore reservoir contents to 

desired levels after they had been drafted deeply in the early summer to meet loads; and 

to allow the storage of energy in Canada.5 

There is another difference from the May study, a change in the Canadian operation for 

this winter. The operation of Canadian reservoirs is guided by analysis done jointly by 

U.S. and Canadian entities. Under the Columbia River Treaty, very specific constraints 

are used to produce operating rule curves for Canadian reservoirs. The operation of 

Canadian reservoirs is then held constant for any scenarios involving U.S. operations. 

The Canadian operation used in the current analysis shows higher outflows from Canada 

in December and January and lower outflows in February. The higher outflows increase 

U.S. hydro capability in those months. 

4.2 Runoff 

The runoff forecast is also important because of the great variation in energy production

between dry and wet years. On average, the hydroelectric system produces about 15,800 

average megawatts of energy annually. In the driest year, it produces only about 11,800 

average megawatts -- a difference of about 4,000 average megawatts, enough to power 

more than threecities the size of Seattle. Assessing the Loss of Load Probability (LOLP) 

for the 2002 winter season depends highly on the anticipated runoff conditions. 

How we approach runoff estimates is in part dictated by the characteristics of our 

analytical system. Our system explicitly accounts for the variability in the output of the 

hydro system. The approach is to do Monte Carlo simulations of the operation of the 

system where historical runoff conditions associated with specific water years are one of

the stochastic variables (along with forced outages and temperatures). We do not yet 

have the capability of running so-called synthetic water years for a large number of 

conditions.6

 Secondly, once we have begun a simulation, we can’t (and it would make no 

sense to) shift to another water year in the middle of that simulation. This means that the 

weighting of a given water year, which determines how many times that year gets 

sampled in the several hundred simulations that are done in a study, must be the same for 

the fall period and the subsequent January through July period. 

For the May analysis, we examined the fall and winter runoffs as a function of the runoff 

of the preceding January through July runoff and determined that there was a weak 

correlation. We are somewhat more likely to have a dry fall and winter on the heels of a 

dry spring and summer. We approximated this by limiting the water years that we used 

in the simulations to the driest two thirds (annual runoff volumes of 114 million acre feet 

and less) and assigned equal weights to each of the years within that group. For this 

analysis we attempted to have a somewhat better rationale for the weighting of the water 

years. 

 

5

 Outflows at Arrow Lake were reduced to store more water. The downstream generation that was lost as a 

result of the reduced outflows was made up by foregone spill. 6

 The May analysis analysed a limited set of synthetic water years spanning the anticipated range of runoff 

volumes for the rest of the January-July period. 

11/15/2001 10
Winter 2001-2002 Power Supply Adequacy 

4.3 Current Runoff Estimates 

Based on forecasts from the Climate Prediction Center (CPC) and using statistical 

information from the historical record, the Council staff has estimated both the Octoberthrough-December and the January-through-July runoff volume forecasts at The Dalles 

Dam. The fall runoff volume is expected to be about 15 million acre-feet (the 50-year 

average is 16.4) and the spring-summer runoff volume is expected to be about 94 million 

acre-feet (the 50-year average is 103.2). The level of uncertainty is large, with the 95-

percent confidence interval estimated to be about plus or minus 30 million acre-feet for 

the January-through-July forecast. In comparison, Bonneville Power Administration’s 

forecasts for the October-through-December and January-through-July runoff volumes 

are 13.6 and 94 million acre-feet, respectively. 

4.3.1 Expected Runoff Based on Historical Record

For each of the 50 historical water records from 1929 through 1978, the relationship 

between the January-through-July runoff volume and the ensuing October-throughDecember runoff volume was plotted. This relationship is illustrated in Figure 4-1. A

weak linear relationship was derived using regression analysis. The observed 2001 

January-through-July volume of 58.2 million acre-feet yields a fall runoff volume 

forecast of about 15 million acre-feet. The same methodology was used to generate a 

January-through-July runoff volume forecast. Again we observe a low correlation 

factor. Nonetheless, proceeding with this technique yields a January-through-July runoff 

volume forecast of about 99 million acre-feet. 

Figure 4-1 

Oct-Dec Runoff vs. Previous Jan-Jul Runoff

Y = 13400 + .033X

5000

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50000 60000 70000 80000 90000 100000 110000 120000 130000 140000 150000

Jan-Jul Runoff (kaf)

Oct-Dec Runoff (kaf)

4.3.2 Expected Runoff Based on Climatological Indices 

The El Nino Southern Oscillation (ENSO) and the Pacific Decadal Oscillation (PDO) are 

increasingly used to forecast future climate patterns and precipitation. However, the 

11/15/2001 11
Winter 2001-2002 Power Supply Adequacy 

Climate Prediction Center currently sees no clear indication that precipitation will be low, 

average or high, but does project that there will be higher variability in the weather. 

Because the Northwest’s soil is dry and aquifer levels are low due to this past season’s 

drought, some of the anticipated precipitation will be absorbed by the soil or depleted 

aquifers. Estimates of how much water will be absorbed are difficult to come by and will 

vary by location. However, rough estimates range between 10 and 20 percent, depending 

on the anticipated runoff volume. The historical runoff records include some soil 

absorption for those years following dry conditions. As a very, very rough estimate for 

the runoff forecast, we can assume that on average, an additional 10 percent of 

precipitation could potentially be absorbed because of the extremely dry conditions this 

year. Using this estimate yields an October-through-December forecast of 14.8 million

acre-feet and a January-to-July forecast of 92.9 million acre-feet. 

4.3.3 Runoff Distribution 

For the January-through-July runoff, staff assumed a normal runoff volume distribution 

with a mean of 94 million acre-feet and a standard error of 13.8 million acre-feet. This is 

the standard error associated with the January runoff forecast. Each of the historical 

water year runoff volume values was “fit” to this curve and weights (relative frequency) 

for each water year were derived from this curve. These weights determine how 

frequently each water year is sampled in the Monte Carlo simulation. The same

weightings are used for both the October-through-December and the January-throughJuly runoffs. 

Figure 4-2 shows the current distribution for the January-July runoff compared to the 

distribution assumed for the May study. As can be seen in this figure, the May study 

distribution has a higher likelihood of drawing the driest water years, even though the 

average of both distributions is nearly the same. Because of the particular bias of the 

May study distribution toward the dry end, the loss of load probability will be higher (all 

else being equal). 

11/15/2001 12
Winter 2001-2002 Power Supply Adequacy 

Figure 4-2 

May Study vs. Current Study Runoff Distribution

January-July 2002

0.0

5.0

10.0

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35.0

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45-55

55-65

65-75

75-85

85-95

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105-115

115-125

125-135

135-145

145-155

Runoff Range (maf)

Pro

b

a

bility

May Study 93.6 Avg

Current 94.4 Avg

5.0 Non-hydro Generating Resource Prospects for 

Winter 2001-02 

The year 2001 has seen substantial addition of new generating capacity in the Northwest. 

On net, it is expected that about 2,140 megawatts7

 of new capacity will enter service 

during the year. This represents a 5-percent annual increase in capacity and a 7-percent 

increase in energy production capability. This rate of expansion has not been 

experienced in the Northwest since 1984. 

An even greater increase in generating capacity is expected in 2002. Little of that 

capacity will enter service prior to June 2002, so will not be available to support winter 

loads. Our current estimates of new capacity for winter 2001-02 service do not 

substantially differ from those used for the May 2001 assessment of reliability (Figure 5-

1). For this reason, non-hydro generating capacity additions do not account for the 

observed changes to winter system reliability. However, as discussed in Section 8.1, the 

treatment of non-hydro generating unit reliability has been refined for this assessment and 

may account for some of the improvement in system reliability for this coming winter. 

 

7

 Because of additional information becoming available since completion of this reliability analysis, the

figures for capacity additions appearing in this report differ slightly from the values used in this reliability 

analysis and reported earlier. The differences are unlikely to significantly affect the findings or conclusions

of the study. The figures used in the analysis are as follows: Net capacity additions during 2001 - 2180

MW; permanent component - 1650 MW; temporary component - 530 MW. 

11/15/2001 13
Winter 2001-2002 Power Supply Adequacy 

Figure 5-1 Pacific Northwest net capacity additions: October vs. May 

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Jan-01 Jul-01 Jan-02 Jul-02

Capacity (MW)

May 2001 Estimate

October 2001 Estimate

Over the longer-term, scheduled capacity additions are expected to increase Northwest 

generating capacity by nearly 3,500 megawatts by January 2003 (Figure 5-2). This is 500 

megawatts in excess of the 3,000 megawatts of capacity identified in the Council’s March 

2000 reliability assessment as needed to reestablish conventional system reliability 

standards by winter 2002-03. About 400 of the 3,500 megawatts, however, are wind 

turbines. Wind turbines are generally given a capacity credit for reliability purposes of 

about a third of that given dispatchable plants. 

Figure 5-2: Pacific Northwest scheduled capacity additions 

0

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Jan-00 Jul-00 Jan-01 Jul-01 Jan-02 Jul-02 Jan-03 Jul-03 Jan-04

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11/15/2001 14
Winter 2001-2002 Power Supply Adequacy 

5.1 Permanent generation 

About 1,650 megawatts of the 2,140 megawatts of net additional generation expected to 

be placed in service during 2001is permanent. Nearly half (46 percent) of this capacity is 

at two large gas-fired combined-cycle plants, Klamath Cogeneration and Rathdrum

Power. These were under construction prior to the appearance of the West Coast energy 

crisis in June 2000. A substantial portion (23 percent) of the new permanent capacity is 

composed of simple-cycle gas turbines, also fired by natural gas. Most of these units are 

highly modular aeroderivative gas turbines requiring little construction time. Though 

largely initiated in response to the capacity shortages and high market prices, several of 

these projects are owned by utilities that intend to use them over the longer-term for 

firming hydropower. 

Wind turbine-generators represent the third major component (17 percent) of the 

permanent capacity installed during 2001. Though wind development of this magnitude 

is new to the Northwest, most of the wind capacity entering service in 2001 was under 

development prior the energy crisis. High market pries undoubtedly helped drive 

completion of these projects; although an important factor is the pending expiration of 

federal incentives at the end of 2001. Other factors driving wind development include 

the emerging green tag market, demand for retail green power products and the lowcarbon resource acquisition policies adopted by several Northwest utilities. 

The availability of this permanent capacity for winter 2001-02 is reasonably certain. 

About 70 percent of the 1,650 megawatts has entered service, and all of the remaining 

capacity is under construction. 

5.2 Temporary generation 

From late 2000 through June 2001, approximately 1,600 megawatts of temporary 

generating capacity were proposed for development in the Northwest. Those proposing 

temporary capacity included utilities and industries exposed to market prices, 

independent developers holding contracts with utilities or industries exposed to market 

prices, and some apparently developing on a purely speculative basis. 

Most temporary projects consist of clusters of reciprocating engine-generator sets or 

small aeroderivative gas turbines. Projects range from less than one to over 150 

megawatts. Most reciprocating units operate on fuel oil, though some use natural gas. 

Most of the gas turbines operate on natural gas. These projects operate under temporary 

permits ranging from 90 days to 24 months duration. 

Approximately 890 megawatts of this capacity will have been in service at some time

during the year. Declining power prices are the leading reason for termination of 

hundreds of megawatts of planned projects and removal of nearly 400 megawatts of 

installed temporary capacity. Some projects were terminated or removed because of air 

emission and noise concerns, permit expiration or replacement by permanent generating 

units. 

11/15/2001 15
Winter 2001-2002 Power Supply Adequacy 

Mosttemporary generation has been idle since the decline in power prices beginning in 

mid-June. These projects have variable costs in the range of $90 to $125 per megawatthour and are not economic to operate in the current market. Based on discussions with 

the operators of most of the remaining temporary capacity, we anticipate that about 500 

megawatts of temporary capacity will be available for service during winter 2001-02. 

Because these units are relatively expensive to run, they would run only in an emergency. 

The ability to dispatch the remaining temporary generation under the current FERC price 

caps mechanism has been questioned. The operating costs of the temporary units 

generally exceed the current price cap, and the cap mechanism does not permit caps to be 

reset for reliability events outside of California. Much of the remaining temporary 

generation is under utility or industrial control, or is contracted to utilities. This capacity 

could presumably be dispatched, if needed by the controlling entity. At question is 

whether generation not needed by the controlling entity could be dispatched under 

bilateral contracts or “spark spread” agreements. For this study we assumed that all 

temporary generation would be available for service as needed. FERC is re-examining 

the issue and may have a favorable resolution before the winter. 

6.0 Contract Obligations 

Contract obligations are firm agreements that Northwest parties have for delivery of 

power to extra-regional parties or that extra-regional parties have for delivery to the 

Northwest. The former represent an additional load, the latter represent an additional 

resource. We have relatively poor information on contract obligations. The Council 

queried the major utilities in the region regarding their commitments. In its request, the 

Council included a confidentiality agreement under which the Council is obligated not to 

disclose individual party data and use the data only as a regional aggregate. 

We received a very poor response to this query. This is largely the result of the nature of

the competitive power industry. For one, it is difficult to know whether the ultimate 

disposition of a sale or source of a purchase is in-region or out of region, particularly if a 

purchaser or seller is a marketer. Secondly, there are concerns about the competitive 

value of such information that were apparently not satisfied by the Council’s willingness 

to hold such data confidential. It is also true that we should have probably sought 

information directly from marketers operating in the region. However, the lack of 

responsiveness from regional entities with which the Council has had a relationship over 

the years does not make us believe that marketers would be anymore forthcoming. 

For this analysis we have used the contract data from the most recent published 

Bonneville “White Book.”8

 In addition, we included 200 megawatt-months of energy in 

January that is the return of energy to Bonneville from exchanges made with California 

earlier this year. We have subsequently been able to corroborate the data we used with 

data submitted by the control areas to the Northwest Power Pool. Our initial data appear 

to be very close to the Power Pool data although slightly conservative, i.e. a somewhat

 

8

 http://www.bpa.gov/power/pgp/whitebook/whitebook.shtml 

11/15/2001 16
Winter 2001-2002 Power Supply Adequacy 

higher level of exports. Nonetheless, we believe the lack of responsiveness of the 

industry is potentially a problem, if not for this particular analysis, then in the analysis of 

some future period when power supply adequacy is an issue. 

7.0 Availability of imports 

In addition to contractual obligations to deliver energy to Northwest parties, there is also 

the possibility of making short-term market purchases from parties in California and 

elsewhere in the West in the event of a period of shortfall here in the Northwest. 

Although this has traditionally been the case, last winter there was very little energy 

available from California and the Southwest. We believe this was the case because of a 

variety of factors surrounding the dysfunction affecting the operation of the California 

market that resulted in large amounts of capacity being unavailable. These factors 

include the fact that a number of plants had been run very hard in the summer and fall of 

2000 and were shut down for maintenance during the winter, other plants had used up 

their allowances for emissions of nitrogen oxide and were required to shut down or face 

very large fines, and other plants that were shut down because their owners were 

concerned they would not get paid given the financial difficulties facing Southern 

California Edison and Pacific Gas and Electric. 

While there are still issues regarding the California market, much has changed: 

• Generation was not run as hard last summer with generally lower loads; 

• Approximately 3,500 megawatts of new generation have come on line; and 

• Approximately 3,500 megawatts less existing generation is scheduled to be outof-service for overhaul this winter compared to last winter. 

For this analysis we have used the same import assumptions used in the May analysis. 

We assumed that there would be up to 1,000 megawatts available during the peak period 

(6 AM until 10 PM) and an additional 3,000 megawatts during the off-peak period. We 

believe these are conservative assumptions and that more energy would be available if 

necessary. 

8.0 Changes in Methodology 

For this analysis, logic improvements were made to GENESYS in two principal areas, 

generation unit forced outages and transmission loop flow. 

8.1 Treatment of forced outages on thermal units 

GENESYS previously used an algorithm that simply sampled twice a week for unit 

availability states, and then held those states constant until the next sample. This 

produces individual outages consistent with unit forced outage rates, but overall system 

outage patterns that could be somewhat blocky. This logic has been replaced in the 

current version with a frequency and duration method for unit outages. The algorithm

uses time-to-failure and time-to-repair distributions to simulate the uncertainty in both 

how long a unit runs before an outage occurs, and in the length of outage. The method 

produces a more realistic system outage pattern, allowing individual units to fail or return 

11/15/2001 17
Winter 2001-2002 Power Supply Adequacy 

to service at any time step within the simulation, not just at the beginning of specific days 

as in the previous implementation. Similar to the original method, the frequency and 

duration method assumes units are either fully available or completely out of service. 

Though the assumed outage rates used in this assessment are equivalent (i.e., including 

the net effect of both full and partial outages), partial capacity outages are not currently 

modeled. 

8.2 Treatment of transmission 

GENESYS previously ignored transmission loop flow. It would treat each transmission 

path and its associated constraints independently from other paths. This has the potential 

effect of overstating transmission capability between areas where loop flow exists. The 

current implementation recognizes loop flow constraints and will limit transmission 

capability for any node-to-node transaction by the amount that causes constraints to be 

reached in any of the legs comprising the loop flow path. 

9.0 Results 

9.1 Loss of Load Probability 

The overall probability of power supply inadequacy of greater than 10 average megawatts 

(LOLP or loss of load probability) for the four-month winter period is shown on Figure 

9-1. 

Figure 9-1 

Winter Season Loss of Load Probability

0

2

4

6

8

10

12

14

May Study October

Study

LOLP - % 5% Target

Winter Season Loss of Load Probability

0

2

4

6

8

10

12

14

May Study October

Study

LOLP - % 5% Target

The loss of load probability is just under 1 percent compared with the almost 12 percent 

found in the May study and the goal of 5 percent. This does not mean that there could 

not be a significant problem this winter given the right combination of extreme 

temperatures, poor water conditions, and forced outages. But the probability of 

occurrence is quite small. 

11/15/2001 18
Winter 2001-2002 Power Supply Adequacy 

There are a number of factors affecting this outcome. The runoff distribution used in the 

current analysis does contribute to the lower loss of load probability, but its effect is 

small. If the same assumption were used as in the May study (using only water years 

with runoff volumes less than 114 million acre feet) the LOLP increases only to slightly 

over 1 percent. The increased energy in storage in Canada and the greater flexibility with 

which it could be used appears have reduced the loss of load probability by 3 to 4 percent 

from the May study values. 

The most significant factor is the effect of loads. The sensitivity of the loss of load 

probability to loads is illustrated in Figure 9-2. 

Figure 9-2 

0%

5%

10%

15%

20%

25%

30%

LOLP - perc

e

nt

Oct. Study +1000 +2000 "Normal" Loads

Loads - Average MW

Sensitivity to Loads

For this study, the basic loads used in the October analysis were incremented as shown. 

“Normal” loads correspond to the Council’s forecast from the last power plan. These 

loads are approximately 4,500 to 5,000 average megawatts greater than those used in the 

October analysis. The loads in the May study were approximately 2,000 average 

megawatts over the current estimates. From this chart, the non-linearity of the loss of

load probability is evident. 

Leading Indicators 

Although the current analysis indicates a low probability of power supply problems this 

winter, the probability is not zero. Combinations of poor water, extreme weather that 

increases loads, and forced outages could occur that could pose power supply problems. 

Moreover, many of the parameters that have gone into this analysis are derived from

estimates or forecasts that may prove wrong. This raises the question of whether there 

might be “leading indicators” of potential problems that should be tracked. Given the 

sensitivity of the loss of load probability to loads indicated in Figure 9-2, it will be very

important to track actual loads and net exports (which have the same effect) through the 

fall and winter. If these appear to be diverging significantly from the forecast used in this 

analysis, there may be cause for concern. 

11/15/2001 19
Winter 2001-2002 Power Supply Adequacy 

Weather is always an issue in that high loads are driven by extreme weather. For every 

degree decrease in the regional average temperature, loads go up by approximately 300 

megawatts. The industry tracks weather carefully. Forecasts of severe weather events 

can provide a few days in which to prepare short-term operational responses. 

Water conditions are more difficult to predict. In the analysis, we can determine under 

what water conditions we observed problems. However, we will not know except within 

a very wide range what water conditions we are actually going to have. Staff is in the 

process of looking the level of unserved load observed in the simulations on a weekly 

basis as a function of streamflows and average temperatures for the week. This is being 

done for both the base case and a case where the loads are 2000 megawatts over the base 

case loads. This information, given a week-ahead forecast of streamflows and 

temperatures, would give an indication of the likelihood of supply problems in that week. 

9.2 April Reservoir Contents 

One objective of the 2000 Biological Opinion is to achieve reservoir levels at their flood 

control elevations by early April. This is to assure adequate water for flow augmentation 

during the spring migration season. However, the Biological Opinion recognizes that it is 

not always possible to reach the flood control levels. Consequently, it aims for achieving 

a relatively high probability of reaching flood control over the historic range of water 

conditions. The targeted probabilities are 85 percent at Grand Coulee and 75 percent at 

Hungry Horse and Libby reservoirs. 

One factor that can affect the likelihood of refill to flood control is the use of “hydro 

flexibility.” Hydro flexibility is the ability to draft reservoirs below their normal drafting 

limits during emergency situations, such as cold snaps or the loss of a major resource. 

Generally these situations only last a few days, after which the drafted water is replaced 

by running surplus Northwest resources or by importing energy from outside the region. 

When the Northwest power supply is adequate, replacing hydro flex water is typically not 

a problem. However, if the system is not adequate, emergency drafts cannot always be 

refilled in time for the spring fish migration season. This leaves less water in reservoirs 

for flow augmentation and can affect the survival of juvenile salmon and steelhead. 

The current analysis uses hydro flexibility to the extent necessary to accommodate 

periods of high loads and/or reduced non-hydro resources. The Council’s estimate for 

this winter’s loss of load probability is under 1 percent, given the current demand and 

resource forecasts. However, the use of hydro flexibility is essential to maintaining a 

reliable power system. Curtailing the use of emergency drafts raises the loss of load 

probability to about 16 percent. 

To assess the impact of the use of hydro flexibility on the probability of reaching flood 

control reservoir levels by April 15, refill probabilities were analyzed both without and 

with the use of hydro flexibility. This year, expected runoff volumes are forecast to be 

slightly less than average for both the fall and spring seasons. US reservoirs are about 

where they should be for this time of year but the Canadian reservoirs are at lower-than11/15/2001 20
Winter 2001-2002 Power Supply Adequacy 

desired elevations. This will likely reduce inflows into the U.S. sometime between now 

and the end of next summer. 

As a consequence, the probabilities of reaching flood control elevations are about 61 

percent at Grand Coulee and about 40 percent at Hungry Horse and Libby, even without 

the use of hydro flexibility. Using hydro flexibility in emergency situations does not 

significantly affect these probabilities. The forecast load and resource situation is such

that it is possible to replace the water used during the emergency draft by running thermal 

generation and using imports. These probabilities are consistent with the language in the 

Biological Opinion. Under normal conditions and a full range of expected runoff 

volumes, the resulting probabilities should be at or very close to the targeted levels. 

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