Document Number 2000-18, October, 2000 1

Study of Western Power Market Prices

Summer 2000

Final Report

October 11, 2000

Northwest Power Planning Council document 2000-18

Executive Summary

Introduction

Almost two years ago, the Council initiated a study of the adequacy of the Northwest's power

supply. This study was motivated by the observation that while the region had enjoyed several years

of robust economic growth and, consequently growth in the demand for electricity, there had been

very little in the way of new generation development. At the same time, efforts to improve the

efficiency of electricity use in the region had been reduced dramatically because of the uncertainty

of utility restructuring. This raised the concern that under conditions of high stress, the system might

not be able to fully meet the region's power needs to serve load and to maintain the reserves essential

to a reliable system. Conditions of high stress involve combinations of high weather-driven loads,

poor hydropower conditions, and forced outages of thermal and hydropower generating units,

The study was completed late last winter.1

 It concluded that:

♦ There is an increasing possibility of power supply problems over each of the

next few winters (December, January, February), reaching a probability of 24 percent by

2003. This takes into account both regional resources and the availability of imports.

The level and duration of the possible shortfalls could be relatively small – a few hundred

megawatts for a few hours – or quite large – a few thousand megawatts for extended

periods.

 

1

 Northwest Power Supply Adequacy/Reliability Study, Phase 1 Report, Paper 2000-4, Northwest Power Planning

Council, March 6, 2000.
Document Number 2000-18, October, 2000 2

♦ The region would need the equivalent of 3,000 megawatts of new capacity to

reduce the probability to a more acceptable 5-percent level. That new capacity should

take the form of new generation and economic load management, i.e., reductions or shifts

in consumer loads that make economic sense for the consumer and the power system.

♦ It was unlikely that market prices would be sufficient to stimulate the

development of sufficient new generation in that time frame. This meant that in the nearterm, an even higher priority needed to be placed on developing economic load

management opportunities.

While this study generated a good deal of interest, it has been difficult for people to get too

concerned about probabilities generated by arcane computer models. This summer, however,

developments in the power system have captured the attention of the industry and the public. Those

developments resulted in unprecedentedly high prices in Western power markets, including the

Northwest. Average prices for power traded for the heavy load hours of June 28th at the MidColumbia trading hub reached almost $700 per megawatt-hour (MWhr). This is more than 10 times

the previous high and is consistent with the prices seen at other trading hubs in the West. Moreover,

even for off-peak periods and days for which prices were not at extreme levels, they were

considerably higher than past summers.

These prices have caused some economic hardship in the Northwest. The hardships have

been limited by the fact that spot market purchases represent a small portion of the total amount of

power consumed in Northwest. Relatively few retail customers purchase directly from the market or

are on market-indexed rates. However, several industrial customers who are on such rates found it

uneconomical to continue operation at these power rates. In addition, several utilities are seeking

increases in their retail rates to cover the increased cost of power purchases. Because of these

impacts, Governors Locke of Washington and Racicot of Montana asked the Council to undertake a

study to explain the reasons for the prices seen on the market and the actions that might be taken to

mitigate these prices.

The Council believes that the market prices seen this summer are a tangible manifestation of

the fundamental problems identified in the Council's power supply adequacy study of last winter.

That is, the prices are an indicator of approaching scarcity. This summer, the system, which already

is facing tight supplies, has been further stressed by combinations of unusually high loads, poor

hydropower conditions, and forced outages of thermal units. There is little in the way of priceresponsiveness in demand to mitigate these prices. Those who had available supply were able to ask

for and receive high prices. This combination of factors is precisely what leads to the power supply

adequacy problems identified in the Council's earlier study. These factors apply not only to the

Northwest but also to the entire Western Interconnected System. There were some additional factors

acting this summer related to the design of the California market, but they should not obscure the

basic underlying problem. Absent some action, the next similar event could result in not only high

prices but also a failure of the system to meet loads.

In the following paragraphs we will summarize the evidence regarding the factors affecting

Western market prices this summer, focusing in some detail on the last week in June, the period in

which the highest prices were observed. We will then offer some recommendations for actions to

mitigate future price excursions and potential power supply adequacy problems.
Document Number 2000-18, October, 2000 3

What Caused this Summer's Prices?

As noted above, we believe the prices experienced this summer are symptomatic of an

overall tightening of supply, exacerbated by a number of factors. Some of these factors are physical

and economic, others are related to the relative immaturity of the competitive electricity market and

the uncertainties involved in the transition from a regulated structure. The physical and economic

factors include:

• unusually high weather-driven demands throughout the West,

• an unusual pattern of hydropower generation,

• a high level of planned and forced outages of thermal generating units, and

• high gas prices.

The factors related to market immaturity and transitional uncertainties include:

• the lack of a demand-side price response in the market;

• inadequate utilization of risk mitigation strategies, and

• factors related to the design and operation of the California market.

Overall Tightening of Supplies

Between 1995 and 1999, WSCC peak loads increased by nearly 12,000 megawatts, or by

about 10 percent. The increase would have been even more if 1999 hadn’t been a relatively mild

weather year. Generating capacity available during peak load months did not increase to keep pace

with peak load growth. While peak loads increased by 12,000 megawatts from 1995 to 1999,

generating capacity only increased by 4,600 megawatts.

We also believe that efforts to improve the efficiency of electricity use, i.e., conservation,

have fallen off considerably in recent years. This is largely the result of the uncertainty created by

the restructuring of the electricity industry. Utilities, who were the primary vehicle for conservation

development, generally reduced their efforts because of concerns about creating potentially stranded

investment if retail access resulted in the loss of customers. There were also concerns about the need

to raise rates to cover conservation costs and the revenues lost as a result of conservation.

The effect of growth in demand outstripping the growth in resources is a narrowing of

reserve margins. This implies more efficient utilization of existing capacity and was an anticipated

benefit of moving to a competitive generation market. However, when it proceeds to the point of

putting reliability at risk and destabilizing prices, it is a problem.

Physical and Economic Factors

High Peak Loads

The period of the highest prices coincided with a period in which loads in the Northwest,

California and the Desert Southwest were at high levels as a result of high temperatures throughout

the West. In the Northwest, peak loads were approximately 3,400 MW greater than last year while

in California on the same day loads were approximately 1,400 megawatts higher. [California and the

U.S. portion of Northwest Power Pool (NWPP) combined, increased 4,826 MW from the peak on

June 30, 1999 to the peak on June 28, 2000, both Wednesdays.]

Unusual Hydropower Production

While the summer of 2000 was expected to be a more or less normal year in terms of overall

runoff in the Northwest, the runoff came in an unusual pattern. Runoff in the early spring was
Document Number 2000-18, October, 2000 4

somewhat higher than usual. But in May and particularly in June, the runoff and hydropower

generation was less than normal and much less than 1999. Hydropower generation in late June was

approximately 6,000 megawatts less than the same time in the previous year.

Planned and Forced Outages of Thermal Units

Maintenance on thermal generation is frequently planned for the May-June period when

abundant hydropower is typically available. In addition, plants do break down, sometimes when it is

least desirable to do so. We have attempted to identify Northwest thermal units that were either on

planned or forced outage status during the last week of June. This was done by examining the

generation data reported to the Western Systems Coordinating Council or supplemental data that was

provided by Northwest generators. These combined data sets comprise about 85 percent of the

capacity in the Northwest. From these data it appears that approximately 1,670 MW of capacity was

out on a long term basis, either planned or extended forced outages, and another 3,400 and 2,700

MW experienced short-term forced outages on the 27th and 28th respectively. Total generation,

thermal and hydro, for the last week of June was approximately 4,000 MW below the levels of 1999.

Load/Resource Balance for the Northwest

A preliminary analysis of loads and resources for the Northwest Power Pool - US Systems

for June 28, the peak price day of June, indicates a peak net hourly load (native load plus exports) of

about 41,000 MW. We were unable to identify more than 38,000 MW of capacity, including

imports, available to meet these loads. This analysis has a high level of uncertainty (hourly

operating data was available for about 85 percent of installed capacity and the output of the

remaining installed capacity had to be estimated and data errors are possible). Obviously, since the

lights did not go out, the system was able to balance loads and resources. It is likely that data errors

and errors in our estimates for the non-reporting generators are at fault. Nonetheless, the evidence

strongly suggests that the Northwest was operating under near-deficit conditions during the heavyload hours of that day.

Gas Prices

Between the summer of 1998 and the summer of 2000 natural gas prices at Sumas (on the

Washington-British Columbia border) increased from about $1.50 per million Btu to $3.30. Prices

into Southern California increased over the same period from about $2.40 to $4.18. Prices have

moved substantially higher during late August and September. During mid- September, prices at

Sumas were $4.60 and prices into Southern California were over $6.00, although the California

prices were affected by a serious pipeline explosion.

Higher natural gas prices, should they persist, will result in higher "normal" prices of

electricity. Depending on the generating technology used, a $2 dollar increase in natural gas prices

(roughly consistent with the doubling of gas prices seen by mid-summer) could increase electricity

prices by between $15 per megawatt-hour and $22 per megawatt-hour. Average electricity prices

during high load hours in the Pacific Northwest mid-Columbia market increased by $140 per

megawatt-hour between June 1999 and June 2000, and light load hour prices increased by $46. The

comparable price increases in Southern California were $113 and $28. The increase in natural gas

prices can not come close to explaining the observed increase in electricity prices.
Document Number 2000-18, October, 2000 5

Factors Related the Immaturity of the Competitive Electricity Market and the

Uncertainties in the Transition from a Regulated Structure

Lack of Price Responsive Demand

A systemic problem associated with the immaturity of the competitive electricity market is

the lack of a demand side to that market. Price responsive demand is important to an efficiently

operating competitive market. Price responsiveness is an essential mechanism to balancing supply

and demand. Without some degree of demand responsiveness, there is no check on the prices that

can be charged when supplies are tight, except for artificial caps. This is particularly critical when

supplies are stretched to their limits. Under those circumstances, a relatively small degree of price

responsiveness can have a relatively large reducing effect on prices, and could also mean the

difference between maintaining service and curtailments.

Currently, at any given hour, the amount of electricity demand is virtually independent of

wholesale price. This is because the vast majority of electricity consumers do not see market prices

in anything approaching real time and, for the most part, have done little if any thinking about how

they could reduce their demands if power were very expensive. The Council is not advocating retail

access as means of achieving price responsiveness. The states are making their decisions about when

and how much to open their retail markets to competition. But developing price responsive demand

does not require passing real-time market prices on to all consumers. It does mean, however, that

those the suppliers who do see wholesale prices should act as intermediaries between the market and

consumers to effect load reduction or shifting that is in the mutual economic interest of the consumer

and the power system. We believe this will develop in time and that the current high prices will help

motivate that development. However, given the tight supplies and high prices now affecting the

market, the Council believes that special effort should be devoted to encouraging and facilitating the

expedited development of the demand side of the market now.

The California Effect

Among the Western States, California's electricity industry is farthest down the restructuring

path. Their path is, in many ways, quite different than most other examples. They have created a

market structure that is quite centralized and quite complex. For most of its three-year life, the

California market demonstrated competitive power prices. However, under periods of stress, we

believe there are characteristics of the California market structure and the incentives it creates that

arguably result in prices that are higher than they might otherwise be. The California Independent

System Operator (ISO) and experts acting in an advisory capacity to the ISO have identified these

characteristics. These include restrictions on the ability of California utilities to enter into longerterm contracts, thus forcing most loads into day-ahead and hour-ahead spot markets operated by the

California Power Exchange. Other facets of the market design create incentives that, when supplies

are tight, result in as much as 20 percent of the load being met in a real-time market operated by the

ISO. This is not a situation conducive to moderating price spikes. We know California is studying

these issues and we are hopeful that they will resolve them in a satisfactory fashion.

Did Market Participants Manipulate the Market?

Much is made of market participants exercising market power during this summer's price

spikes. Clearly the prices we have seen are well above a "competitive" price, if that is defined as the

operating cost of the most expensive unit on the system that must run to meet load. The ability of

market participants to ask for and receive more than the competitive price can be defined as market
Document Number 2000-18, October, 2000 6

power. However, this is also the normal functioning of a market when supplies are tight and there is

no moderating effect of price responsiveness. It is neither illegal or immoral.

The Council did examine the generating records of most Northwest power plants to see if

there was evidence of manipulating the market by "withholding," i.e., holding power off the market

to drive up prices. We found no clear evidence of such behavior. Power plants were generally being

operated as one would expect given the characteristics of the plants. Hydro plants were typically

following load. Thermal plants were typically running "flat out" or, in the case of units with higher

operating costs, backed down during the off-peak periods. Where there were operating patterns that

might be interpreted as withholding, the quantities involved were too small to affect the market.

The Council did not have access to information that would permit analysis of the bidding

strategies of different market participants. We do not know whether that information would suggest

market manipulation.

Recommendations

Encourage the Greater Use of Risk Mitigation Mechanisms

One of the characteristics of a commodity market is the emergence of mechanisms to manage

risk, and electricity is rapidly becoming a commodity market. These mechanisms include actual

physical longer-term contracts for supply, futures contracts, financial hedging mechanisms, and so

on. These mechanisms can limit exposure to high prices. At the same time, however, there is

always the risk that they will prove more costly than the spot market. Risk mitigation comes at a

cost, and it is not realistic to be fully hedged for all risk. But the experience of this summer suggests

there could be greater use of risk management tools.

As noted earlier, we believe the limitations on forward contracting by California utilities was

a contributing factor to the price extremes of this summer. We believe the same is true of other

market participants in the Northwest and elsewhere. While opportunities to enter into forward

contracts and other hedging arrangements have existed, it may be that the protracted period of low

market prices for electricity lulled some market participants into believing they had no need of such

mechanisms. Recognizing the commodity nature of the electricity market and taking appropriate

steps to protect against the upside risk is important. Had more market participants done so, it is

likely that this summer's price volatility and its impacts would have been moderated. Forward

contracting is also a vehicle by which new entrants in the generation market can limit their downside

risk, thereby facilitating the development of new generation.

Evaluate the Need and Options for Further Encouraging Generation Development

As noted earlier, the Council's analysis of power supply adequacy indicated that market

prices would not be sufficient to support the development of "merchant" power plants, i.e., plants

selling into the spot market exclusively, until 2004. The Council has also done analyses looking at

actual market prices over the past year to see if prices had been sufficient for a new entrant to cover

its variable operating costs and its fixed costs and earn a reasonable rate of return. Until this summer

the answer has been "no."

With the electricity and gas prices experienced over the past year, the answer has become

"yes." With the higher prices, a couple of plants not considered in the Council's adequacy study

have begun construction. In the Northwest, there are now 1,276 MW of capacity under construction

that should come on line in 2001 through 2002. There are another 2,977 MW that already have site
Document Number 2000-18, October, 2000 7

certificates, 1,291 MW of which we judge to be "active" projects, and another 3,060 megawatts that

are in or have begun the siting process. The siting process does not appear to be a problem in that

there is a backlog of sites that have been permitted and many more in the process. Almost all of

these are natural-gas-fired combustion turbines, and nearly all of them are located within reasonable

proximity to natural gas pipelines and transmission lines. There is a similar story to be told

elsewhere in the West.

The degree of developer activity is encouraging. However, if we were to experience a couple

years of relatively warm, wet winters and cool summers with good hydro conditions, market prices

would probably fall and many of the active projects might become inactive. If followed by a dry

spell and a hot summer or a cold winter, we would be up against the supply limits again.

The question this possibility raises is whether we can rely on the market to provide sufficient

capacity for reliability purposes. And if not, what are the options for assuring that there is capacity

available to assure reliability and mitigate excessive price spikes? The Council intends to pursue

this question.

Accelerate Efforts to Develop the Demand Side of the Market

While the lead time for the development of new combined cycle generation is relatively

short, development will take some time. During that time, the region and the West are vulnerable to

further price spikes and possible reliability problems. Moreover, it is not certain that the long-term

market will support the level of development necessary to assure adequate reliability. Developing

the demand side of the market has the potential for somewhat shorter lead times. Price-responsive

demand can help mitigate price spikes and potentially avert reliability problems.

The Northwest has a great deal of successful experience in increasing the efficiency of

electricity end-use as a resource. The region needs to reinvigorate those efforts in light of the market

prices we are experiencing. There are cost-effective means of slowing the growth of demand that

should be exploited. However, the region in particular needs to move aggressively to implement

price-responsive demand management – reducing loads during periods of high prices or shifting the

loads to periods of the day where prices are less. The bad news is that this region has relatively little

experience with these approaches, although that is changing. The good news is that there should be

significant untapped potential.

The Council believes that market-like mechanisms wherein the consumer receives a

significant part of the benefit will be most effective. Pilot programs have been initiated this year in

the region in which the serving utility and the load-reducing consumer share the cost savings of

avoided power purchases (or the revenues from selling the freed-up power on the market). These

programs appear to have been successful although limited in scope. The greatest potential for such

partnerships probably exists within industry and large commercial buildings. What can be done will

vary from building to building and process to process. Nevertheless, if provided the incentive, the

Council believes people will rise to the challenge. Creating these incentives should be a priority for

the utilities of the region.

California Should Correct the Incentives in their Market Structure that Contribute to

Excessive Prices and Volatility

The Council believes that the California ISO and others in the California market have done a

credible job of identifying the barriers and incentives created by their market structure that have
Document Number 2000-18, October, 2000 8

contributed to excessive prices and price volatility. We know the issues are complex and politically

volatile. We hope that the state can move quickly to correct these problems.

At Least Until the Market Matures, Data for Monitoring and Evaluating the

Performance of the Market Should be Available on a Timely Basis

One thing that the experience of this summer has shown is that it is difficult to obtain the data

necessary to monitor and evaluate the performance of the market. Despite the fact that utilities in the

Northwest were extremely cooperative, there was a delay of many weeks before the relevant data

could be obtained. While the WSCC maintains a data base of generation and transmission loading

data, not all generators report to the system and of those that do, the data link is not necessarily

carefully maintained. Despite incompleteness data, the WSCC has chosen not to release the

information to independent body like the Council, even when the Council agreed to keep the data

confidential and to use the data in such a way that individual plants could not be identified. We

understand the possible commercial sensitivity of some of this information. We believe, however,

that there should be arrangements possible that both protect the commercial value of the information

and make it possible for responsible independent parties to evaluate market performance on a timely

basis. At least until the market has matured and the public has greater confidence in its operation,

this should be a high priority for market participants and organizations like the Western Systems

Coordinating Council, the California ISO and regional transmission organizations as they are

formed.

Electricity Emergency Process and Procedures Need to be in Place

If we are correct is our assessment that the electricity market prices experienced this summer

are a warning of approaching scarcity, then establishing the processes and procedures that would be

used in the event of an actual supply emergency should be a priority. Until new generation comes

on line and demand-side programs can be implemented, there is significant probability that our

emergency readiness will be tested. Necessary elements include an inventory of the actions that

could be taken, the trigger points for taking these actions, clear definition of roles and

responsibilities, and a communications plan to inform the public. We are pleased that efforts to

accomplish this are underway involving the Pacific Northwest Utilities Conference Committee, the

Northwest Power Pool, Bonneville, the Council, the Northwest states and region's utilities.
Document Number 2000-18, October, 2000 9
Document Number 2000-18, October, 2000 10
Document Number 2000-18, October, 2000 11

Study of Western Power Market Prices Summer 2000

1. Wholesale Power Prices in the Summer of 2000 and the Focus of this

Analysis

Wholesale Prices

The source of concern motivating this analysis is indicated in Figures 1-1 and 1-2. These

show heavy load hour (6 AM to 10 PM) and light load hour (10 PM to 6AM) power prices at the

Mid-Columbia (Mid-C) trading hub for May, June, and July for the years 1996 through 2000. These

prices represent the volume-weighted average prices for trades made for a given day for a block of

power covering the designated period (heavy or light load hours). These prices are determined by a

survey of traders carried out by Dow Jones. They are plotted on a logarithmic scale to allow some

definition of the prices in the years preceding this one.

Two things are evident from this data. First, a year-to-year progression in the average prices

for the periods as supply margins have tightened is apparent. However, through 1999, prices

generally do not exceed what would be thought of as a "competitive" price, i.e., the cost of operating

the most expensive generating units on the system. That price would be less than $100/MWHr for a

very inefficient oil-fired simple-cycle turbine. The data through 1999 also demonstrate the seasonal

depression of prices that typically occurs in the May-June time frame coinciding with the peak runoff in the hydropower system. However, what has captured attention is that this year average prices

for both heavy load hours and light load hours are much higher and routinely exceed a competitive

price with extreme peaks in the several hundreds of $/MWHR.

It should be noted that these market prices do not reflect the prices paid for the majority of

the power consumed in the Northwest. The volume traded at Mid-C amounts to about 3 or 4 percent

of the electricity consumed in the region. Most of that power is secured under longer-term contracts

that have lower prices associated with them. At the margin, however, market prices are the prices

paid by utilities trying to secure additional short-term resources to meet their loads. Market prices

are also paid by some industrial customers who are either meeting some or all of their needs with

spot market purchases or who are on a market-indexed rate. For several years, relying to greater or

lesser degrees on spot market purchases has been an economic benefit to those who have done so.

Market prices have typically been less than the fully allocated (fixed and operating) cost of the

system. This year that is not the case. The immediate effect of these prices has been economic

hardship for some of those industrial customers, some of whom have found it uneconomical to

operate at those prices. A delayed effect will be felt in consumer rates and/or shareholder returns as

utilities seek rate increases to cover their increased power purchase costs.

It is also clear that the Northwest is part of a broader West Coast market. Figure 1-3 shows

the June heavy load hour prices at Mid-C for the years 1998, 1999 and 2000 along with roughly

comparable prices for California.2 Power is traded freely throughout the Western Interconnection.

Market prices tend to track one another, differentiated by transmission costs and, when congestion

occurs on relevant transmission paths, congestion premiums (the cost of dispatching more expensive

generating plants). Generally this means that power prices in one part of the West will affect power

prices in other areas of the West. When congestion occurs, prices in the different markets may

 

2

 These prices were derived from the day-ahead hourly unconstrained market clearing price bid into the California

Power Exchange (Cal PX).
Document Number 2000-18, October, 2000 12

decouple. That is, lower-priced power in one region cannot get to another, requiring that higher cost

resources be dispatched within the second region.

From Figure 1-3, it is clear that Mid-C and Cal PX prices track fairly closely, with the Cal

PX prices typically being somewhat higher. In June, the Northwest typically has abundant

hydropower available and sometimes cannot sell all that it would like to into the Cal PX because the

interties are full or very close to it. This year, Mid-C prices in June were frequently as high or

higher than those in the Cal PX. As will be discussed later, we believe that is largely the result of

relatively poor hydropower conditions and planned and forced outages of thermal units. As a result,

interties were frequently far from full.

Figure 1-1

Heavy Load Hour Firm Prices at Mid C

1.00

10.00

100.00

1,000.00

24-Apr 13-Jun 2-Aug

Date

Price $/MWHR

96

97

98

99

2000

Figure 1-2

Light Load Hour Firm Prices at Mid-C

1.00

10.00

100.00

1,000.00

24-Apr 13-Jun 2-Aug

Date

Price - $/MWHr

96

97

98

99

2000
Document Number 2000-18, October, 2000 13

Figure 1-3

PX vs. Mid C HLH Prices - June

1.00

10.00

100.00

1000.00

147

10131619222528

00 PX

00 Mid C

99 PX

99 Mid C

98 PX

98 Mid C

Focus of this Analysis

Although prices have been relatively high throughout the summer, the analysis focuses

primarily on June 2000 and, in particular, the last week in June during which the highest Northwest

on-peak prices were recorded. We believe the insights gained from consideration of that period

generally are valid for other periods as well.

2. Evidence of Overall Tightening of Supplies

For the past several years, the economies of the West have been growing. This translates into

growing electricity demand. Between 1995 and 1999, WSCC peak loads increased by nearly 12,000

megawatts, or by about 10 percent. Energy use during the same four years increased by about

65,000 gigawatt-hours, or about 2.3 percent annually. The increase would have been even more if

1999 hadn’t been a relatively mild weather year.

Generating capacity available during peak load months did not increase to keep pace with

peak load growth. While peak loads increased by 12,000 megawatts from 1995 to 1999, generating

capacity only increased by 4,600 megawatts. Figure 2-1 illustrates the difference.
Document Number 2000-18, October, 2000 14

Figure 2-1

Change in WSCC Peak Loads and Resources,

1995 to 1999

0

2000

4000

6000

8000

10000

12000

14000

M egaw atts

Summer Peak Load Change

Change in Resources

Although we do not have data to fully substantiate this, we also believe that efforts to

improve the efficiency of electricity use, i.e., conservation, have fallen off considerably in recent

years. This is largely the result of the uncertainty created by the restructuring of the electricity

industry. Utilities that were the primary vehicle for conservation development generally reduced

efforts because of concerns about creating potentially stranded investment in the event that retail

access results in the loss of customers, and concerns about raising rates to cover conservation costs

and lost revenues.

Loads did not grow evenly among the geographic areas of the West. The WSCC (Western

Systems Coordinating Council) is divided into four subareas. The Northwest Power Pool (NWPP) is

the largest area geographically and in terms of average energy loads. It includes the Council’s

region of Oregon, Washington, Idaho and Montana west of the Continental Divide, as well as

Alberta and British Columbia in Canada, the rest of Montana, Utah, and substantial parts of

Wyoming and Nevada. The NWPP is the only one of the four WSCC areas that has its peak loads in

the winter. All of the other areas, and the WSCC as a total, have their peak loads in the summer.

California and a small part of Mexico is the second largest energy load area, but is the largest

summer peak load area. The other two areas are the Arizona, New Mexico, and Southern Nevada

area (AZ/NM/SNV), and the Rocky Mountain area (RMPA) which includes Colorado and Eastern

Wyoming. By far, the most rapid growth occurred in the AZ/NM/SNV area. Although this area

only accounted for 12 percent of WSCC summer peak loads in 1995, it accounted for 47 percent of

their growth from 1995 to 1999. Its loads increased by 38 percent over those four years.

Figure 2-2 shows the shares of 1999 summer peak loads and the shares of summer peak load

growth by area from 1995 to 1999. Although the NWPP is a winter-peaking area, its summer peak

loads grew substantially -- by approximately 3,900 MW. The net capacity additions in the NWPP

area during that period were 1,374 MW. The ratio of peak load growth to net capacity additions for
Document Number 2000-18, October, 2000 15

the NWPP is approximately the same as for the whole WSCC. Considering its size, California had a

pretty small contribution to the summer peak load growth.

Figure 2-2

NWPP

37%

RMPA

6%

AZ/NM/SNV

15%

CA/MX

42%

WSCC 1999 Summer Peak 

= 129059 MW

1995-99 Shares of Summer Peak Growth

NW PP

34%

RM PA

4%

AZ/NM /SNV

47%

CA/M X

15%

Growth outstripping demand inevitably means erosion of reserve margins, i.e., the amount of

capacity available in excess of peak demand. This is not necessarily a bad development. A criticism

of a regulated, vertically integrated utility system was that it resulted in over-investment in capacity.

One of the anticipated benefits of a competitive generation market was the more efficient utilization

of existing capacity and declining reserve margins. However, when reserve margins decline to the

point where they threaten reliability and lead to highly volatile prices, many would say they have

gone too far.

3. The Effect of High Coincident Peak Loads

To understand what has happened to electricity markets, it is also important to understand

that in the summer California imports electricity from the other WSCC areas in order to meet its

peak loads. Conversely, in the winter, the Northwest is frequently dependent on imports to meet its

peak loads and energy requirements. Figure 3-1 shows net exports of electricity for each of the

WSCC areas for the peak summer month. The negative values for California means that it is

importing electricity. Note that the imports available from the NWPP are dependent on hydro

conditions, but, in general, as loads have grown faster than generating capacity additions, decreasing

amounts of electricity have been available to import into California.
Document Number 2000-18, October, 2000 16

Figure 3-1

Regional Exports of Electricity

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1995 1996 1997 1998 1999

M W

NWPP

RMPA

AZ/NM/SNV

CA/MX

When weather conditions are such that periods of high peak loads in exporting and importing

regions coincide, the system is stressed more than is normally the case. During the summer of 2000,

the resource squeeze in California has been increased by much warmer weather in California, the

desert Southwest, and, at some times, in the Northwest as well. To illustrate this, we have plotted

the June 1999 and 2000 loads for the California Independent System Operator (CAISO) and the U.S.

systems of the Northwest Power Pool (Idaho, Oregon, Montana, Washington, most of Utah, and

Northern Nevada). These are shown as Figures 3-2 and 3-3.
Document Number 2000-18, October, 2000 17

Figure 3-2

Hourly Loads for California ISO

June 1999 vs June 2000

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101112131415161718192021222324252627282930

Day of Month

MW

2000

1999 1999 data offset to align days of week

Figure 3-3

Hourly Loads in NWPP - US Systems

June 1999 vs June 2000

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Day of Month

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1999 1999 data offset to align days of week

In order to understand these conditions, we have focused on three different weeks. The focus

week for this analysis is June 22 to 28, 2000. For comparison, we look at a low-load week in June of

2000 and a high-load week in June of 1999. These are June 1 to 7, 2000, and June 24 to 30, 1999,

respectively. These weeks run from Thursday to Wednesday, and we will particularly focus on the

last day of each of these weeks. Figures 3-4A, B and C compare the hourly loads in California for

the last day of each of the three weeks. These are presented side-by-side on the following page to

permit easy comparison.
18

Figure 3-4A Figure 3-4B Figure 3

Ju ne 30, 1999 C alifornia Lo ads an d P rices

0

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1000015000200002500030000350004000045000

13579

11

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LoadsDay Ahea d P X Price

June 28, 2000 Calif

0

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13579

11

Loads

LoadsDay Ahead P X Price

The loads in the last week of June 2000 were substantially higher than the loads in the other two weeks. Ho

the weeks of late June 1999 and June 2000 the loads were comparably high, and about 7,000 to 8,000 megawatts higWednesday, June 7, 2000. Figures 3-4A through C show each of these day's loads as bars measured on the left axisday-ahead prices for that day plotted as a line and measured on the right axis. Although the loads are very similar foWednesdays, the price during peak hours in 2000, capped at $750 per megawatt-hour, was about six times the price for such a dramatic change in a one-year span of time?

There are some supply and demand-related factors that made the electricity market tighter in 2000 even thou

were similar on June 28, 2000 and June 30, 1999. First, Northwest Power Pool loads were higher in 2000 by nearly the peak hours, as is clear in figure 3-3. Although we do not have the data to be sure, anecdotally, weather was hottthe desert Southwest as well.
19

Higher loads in the Northwest and desert Southwest, combined with less hydro electricity in

the Northwest, decreased the imports available to help meet California loads. Figure 3-5

demonstrates that imports were far smaller into California in 2000 than they were in 1999. Making

the situation even tighter were significant numbers of generating unit outages as is discussed in

Section 5.

Figure 3-5

Net Import Comparison

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1 3 5 7 9 11 13 15 17 19 21 23

June 28, 2000

June 7, 2000

June 30, 1999

It seems likely that the tight supply/demand conditions bring out weaknesses in the

California market structure that tend to worsen price volatility. This will be discussed in a later

section.

4. Unusual Hydropower Conditions

Although not too far from average in terms of overall runoff, the pattern of runoff in 2000

was somewhat unusual. The runoff pattern is shown on figure 4-1. This figure shows the

unregulated monthly runoff volume at The Dalles in terms of thousands of acre-feet (KAF) for 1999,

2000, and for the 61 year average. As this figure shows, for the early part of the year, the 2000

runoff was above average. Beginning in May, however, the runoff essentially flattened out at a level

below the 61-year average and well below the levels of 1999. This pattern persisted through the

month of June.
20

Figure 4-1

Monthly Unregulated Runoff Volumes at the 

Dalles

0

5000

10000

15000

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25000

30000

35000

40000

JAN FEB MAR APR MAY JUN JUL AUG

Month

KAF

61 year Average 2000 1999

In terms of hydropower generation, the weekly production for May and June of 2000 relative

to 1999 is shown on Figure 4-2.

Figure 4-2

NWPP Hydro Generation 2000 Relative 

to 1999 -- May-June

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2000

Week

1

Week

2

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3

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6

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8

Week

9

aMW

NWPP total NWPP US Systems

As Figure 4-2 shows, May-June 2000 weekly hydropower generation was down from 6,000-

7,000 Megawatt-weeks relative to 1999 throughout most of June (weeks six through nine). The

pattern of runoff probably "fooled" a number of participants in the market. The forecast was for a

more or less average year. The runoff during February and March supported that forecast. It may be
21

that decisions were made to make forward sales for June and beyond or, for those buying, to go short

on the expectation of roughly average water and relatively abundant hydropower. Similarly,

decisions to perform scheduled maintenance on thermal plants during the June time frame when high

volumes of runoff were expected were also made. The subsequent runoff pattern confounded those

decisions and significantly reduced the amount of hydropower both to meet regional loads and for

export. It also seems likely that the relatively good water conditions in 1999 obscured the tightening

of supplies.

5. Thermal Power Plant Outages

The latter part of June 2000 also experienced a significant amount of thermal power plant

capacity that was out of service for either planned or unplanned reasons. To assess the amount of

generation that was unavailable during the last week of June, 2000, staff examined hourly generation

data from the Western Systems Coordinating Council (WSCC) Extra High Voltage (EHV) Data

Base as well as supplementary data obtained through the cooperation of Bonneville and a number of

Northwest utilities (Avista, Clark Public Utilities, Energy Northwest, PacifiCorp, Portland General,

Puget Sound Energy).3

 Not all power plants report to the EHV system. Only about 70 percent of the

capacity is included. Moreover, of those plants reporting, there are numerous instances of data

lapses, i.e., the data shows no output from a particular plant although subsequent inquiry determines

that the plant was operating. It is, however, the most comprehensive data source available. With the

supplementary data, we were able to account for roughly 80 to 85 percent of the capacity in the

Northwest.

Figure 5-1 shows data for a typical coal-fired power plant for the last 10 days in June.4

 The

output of the plant is shown in terms of the percentage of its total summer capacity rating. Also

overlaid on the data is the hourly load for the U.S. systems of the NWPP area. For this particular

plant, it appears that going into the last 10 days of the month, the plant is operating at about 60

percent capacity due either to scheduled maintenance on one or more units or a prolonged forced

outage. On the 27th, the plant loses another unit, dropping output to 30 percent. That unit comes

back on the 30th. This outage we believe to be an unscheduled forced outage. This was the period of

highest prices. An operator would not willingly forgo operation and miss out on the potential

revenues, given the opportunity.

Staff reviewed the generation data to which we had access to identify outage states, focusing

on the heavy load hours of the last week of June and, in particular, June 28. There is judgment

involved as to whether a plant appeared to be in a planned outage or an extended forced outage.

Staff identified 1,670 MW of capacity was out on a long-term basis, either planned or extended

forced outages, and another 3,400 and 2,700 MW was on short-term forced outage status on the 27th

and 28th respectively.

 

3

 The EHV data set could not be obtained directly from WSCC because of limitations imposed on its distribution by the

WSCC membership. We were, however, able to obtain the data through the Oregon Public Utilities Commission who

obtained the data from PacifiCorp.

4

 As a condition of obtaining the power plant data, the Council agreed to use the data in such a way that no individual

plant could be identified.
22

Figure 5-1

Operation of a Typical Coal Fired Plant

0.0%

10.0%

20.0%

30.0%

40.0%

50.0%

60.0%

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90.0%

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480 504 528 552 576 600 624 648 672 696 720

Hour of Month

Output - % Summer 

Capability

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NWPP US Systems Load - 

MW

Output

Load

6

6/26 6/27 6/28 6/29 6/30

The total generation for the NWPP area for May and June is shown on Figure 5-2. As this

figure indicates, thermal generation was able to make up for some but not all of the decrease in

hydro generation. Thus at a time when demands were high in the Northwest and in California and

the desert Southwest, the available generation was significantly reduced from 1999, when loads here

and in California were significantly less.
23

Figure 5-2

NWPP Weekly Energy Generation -- 

May-June

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Week

aMW

2000 Hydro

1999 Hydro

2000 Total

1999 Total

6. Transmission

Because the Northwest is part of the broader Western power market, what was happening on

the transmission paths that link the Northwest with California and the desert Southwest are important

to understand. There are a number of such transmission links. The most important are the

California-Oregon Intertie (COI) or AC intertie that links the Northwest into Northern California,

and the DC intertie that links into the Los Angeles area. We looked at the utilization of the North to

South transfer capability during the month June for both 2000 and 1999. We calculated the average

transfer during the period 9AM to 6 PM divided by the average transfer capability for that period.

The period was chosen to coincide more closely to the actual hours of peak demand than the usual

6AM to 10 PM heavy load hour period.

As Figure 6-1 shows, in 1999 the AC and the DC generally operated closer to full capacity

for most of the month than in 2000. This is particularly so in the last week of June 2000 when both

the Northwest and California were experiencing high demand and high prices. The fact that the

interties were essentially unconstrained during this period means that prices in the Northwest and

California should be closely coupled and, as was shown in Figure 1-3, that was indeed the case.
24

Figure 6-1

Utilization of North to South Transmission 

Capacity -- June

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1

147

10131619222528

Day of Month

Utilitzation

AC 2000 DC 2000 AC 1999 DC 1999

9AM thru 6PM

1999 Data shifted to align days of week

7. Overall Load-Resource Balance

The Northwest and WSCC as a whole currently have a slight surplus of capacity under

average load and water conditions. However, the combination of early runoff, high loads, outages of

several large power plants and exports to the southwest market appear to have resulted in nearshortfalls in capacity in the Northwest this past summer. A preliminary analysis of loads and

resources for the Northwest Power Pool - U.S. Systems for June 28 - the peak price day of June -

indicates a peak net hourly load (native load plus exports) of about 41,000 MW. The native load

was obtained from NWPP data while the exports were determined from the WSCC EHV

transmission load data. Generation and imports were estimated from the WSCC EHV data set plus

supplementary generation data provided by Northwest utilities. We were unable to identify more

than 38,000 MW of capacity, including imports, available to meet these loads. Since loads were met

that day there are obviously errors of estimation, data errors or both. This analysis has a high level

of uncertainty. Hourly operating data was available for about 85 percent of installed capacity and

the output of the remaining installed capacity was estimated. In addition, the data set could well

have data errors. However, even considering the uncertainty, the evidence strongly suggests that the

Northwest was operating under near-deficit conditions during the heavy-load hours of that day.

8. Oil and Natural Gas Prices

In a competitive market that is not operating close to its supply limits, the price of power is

set by the operating cost of the highest operating cost plants that have to run to meet load. In the

West during peak periods, those plants are typically oil or natural gas-fired simple-cycle combustion

turbines. Consequently, the price of oil and natural gas will have an effect on the market price of

electricity.
25

Natural gas prices are currently at very high levels. Prices in the spot market at Henry Hub

in Louisiana have been over $5 recently and are expected to remain high for the next year at least.

High gas prices are a result of a commodity cycle upswing in natural gas that has coincided with a

period of high world oil prices. High oil prices can cause a surge in natural gas demand due to

switching of dual fueled facilities to natural gas from oil. Figure 8-1 shows recent trends in oil and

natural gas prices. Figure 8-2 shows how the natural gas price increase is likely associated with a

three to five year commodity cycle for natural gas that has typified that fuel since it was deregulated

in the mid 1980s.

Figure 8-1

Trends in Oil and Natural Gas Prices, 1998 to 

Summer 2000

0

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May

Natural Gas Price ($/MMbt

u

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World Oil Price ($/barrel

Natural Gas

Crude Oil
26

Figure 8-2

Natural Gas Prices: US Composite Index (Natural Gas Week)

1.00

1.25

1.50

1.75

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(Real $/MMBtu)

Monthly

12-Mon Avg

Natural gas prices in the Pacific Northwest have recently moved closer to national prices due

to the recent and anticipated completion of new pipeline capacity from Alberta, Canada, to the East.

Figure 8-3 shows Canadian natural gas prices at Sumas compared to Henry Hub spot prices and

prices delivered into California.

Figure 8-3

Monthly Gas Price Comparison

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

Jan-98

Mar-98

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Henry Hub

So Cal

Sumas

Between the summer of 1998 and the summer of 2000 natural gas prices at Sumas (on the

Washington-British Columbia Border) to be delivered into the Northwest increased from about

$1.50 per million Btu to $3.30. Prices into Southern California increased over the same period from

about $2.40 to $4.18. Prices have moved substantially higher during late August and September.
27

During mid September, prices at Sumas were $4.60 and prices into Southern California were over

$6.00, although the California prices were affected by a serious pipeline explosion. NYMEX futures

prices indicate that natural gas prices are expected to decline over time, but remain above $4 for at

least a year. A cold winter could send natural gas prices even higher.

Figure 8-4 illustrates the possible range of effects that a $2 increase in natural gas prices

could have on the variable cost of natural gas-fired generation with different technologies. Changes

in the variable cost of generation can translate directly into changes in electricity prices. Depending

on the generating technology used, a $2 dollar increase in natural gas prices (roughly consistent with

the doubling of gas prices in the last year) could increase electricity prices by between $15 per

megawatt-hour and $22 per megawatt-hour. The increase in natural gas prices does not come close

to explaining the increase in peak electricity prices. Average electricity prices during high load

hours in the Pacific Northwest mid-Columbia market increased by $140 per megawatt-hour between

June 1999 and June 2000, and light load hour prices increased by $46. The comparable price

increases in Southern California were $113 and $28. The peak hour price increases experienced in

California regularly hit the $750 per megawatt-hour price caps that were in place in June

(subsequently lowered to $250 per MWhr).

Figure 8-4

Effects of a $2 Gas Price Increase on 

Electricity Variable Cost

0

5

10

15

20

25

$ / Mwh

Combined Cycl

e

7500 Heat Rate

Gas-Fired Boiler

10,000 Heat Rat

e

Simple Cycle

11,000 Heat Rat

e

This suggests that we should expect to see higher "competitive" electricity prices, i.e., the

prices we would expect when the power system is not stressed and competitive pricing principles

hold, for some time into the future. We expect high natural gas prices to stimulate development of

additional gas resources and this is, in fact, already underway. The count of drilling rigs in the field

in North Amercia is up from a low of about 350 to almost 800 now. Increased development, if

successful, should bring down gas prices over time. The Council will be reviewing its gas supply

and price outlook in the coming months.
28

In summary, while increased gas prices have and will increase the competitive market price

of electricy, the effect of increased gas prices is relatively minor in relation to the non-competitive

electricity prices observed when the system is under stress.

9. Lack of Price-Responsive Demand

A systemic problem associated with the immaturity of the competitive electricity market is

the lack of a demand side to that market. The responsiveness of demand to price is essential to an

efficiently operating competitive market. Price responsiveness is a key mechanism to balancing

supply and demand. Without some degree of price responsiveness, there is no check on the prices

that can be charged when supplies are tight, except for artificial caps.

It may be worth reviewing a simplified representation of the basic economics that underlie

markets, including the competitive wholesale power market. Figure 9-1 illustrates supply of and

demand for electricity at a time at which the system is unstressed. The stair-step curve is the supply

curve, representing the quantity of electricity that will be supplied at a given price. The prices and

incremental quantities correspond to the operating costs and capacities of different generators on the

system at any point in time. The near-vertical line represents the demand curve. The dotted lines on

either side represent the range of variation in demand resulting from weather conditions, e.g., in the

summer, a cool day moves the demand curve to the left, a hot day moves it to the right.

The demand curve is nearly vertical because, at present, the amount of electricity demanded

is virtually independent of wholesale price. The vast majority of consumers do not see market prices

in anything approaching real time. As a result, most have done little if any thinking about what they

might do to reduce their demands if power were very expensive. Even in California, which has

theoretically opened its retail markets to competition, very few end-users see a price signal in time to

do anything about it. For most, the cost consequences of periods of high prices are averaged in with

the costs from periods of less extreme prices and what effect the consumer does feel is felt well after

the fact.

The wholesale price is determined where the demand curve intersects the supply curve. In

the situation illustrated in Figure 9-1, the lack of price responsiveness isn't particularly critical,

because the demand curve intersects the supply curve at a relatively flat portion of the supply curve.

Changing demand is not going to affect the wholesale price significantly.
29

Figure 9-1

Wholesale Price

Supply/Demand

Supply Curve

Demand

Curve

Weather-Driven

Variation in

Demand

Supply and Demand -- System Unstressed

Figure 9-2 illustrates the situation that we believe existed this summer. Growth in demand

has occurred without any appreciable additions to the supply curve. Moreover, high temperatures

and increased air-conditioning loads mean that we have been toward the right hand side of the band

of weather-driven variation. In this instance, the demand curve intersects the supply curve at the

steep part of the curve. Relatively small changes in demand can have significant effects on price or

can mean the difference between being able to meet load and not.

Figure 9-2

Wholesale Price

Supply/Demand

Supply Curve

Supply and Demand --

Demand Approaching Available Supply

Demand

Curve

Weather-Driven

Variation in

Demand
30

Figure 9-3 illustrates the benefit of developing greater price responsiveness in demand. The

effect of price responsiveness is to bend the demand curve to the left, i.e., at some point, as price

increases, the demand decreases. If demand and supply were intersecting in the relatively flat

section of the supply curve, there would be little if any affect on price. But, since we are in the steep

part of the supply curve, a relatively small increase in price responsiveness can have a fairly

significant effect on price.

Figure 9-3

Wholesale Price

Supply/Demand

Supply Curve

Demand

Curve

Price Effect

from Increasing

Price

Responsiveness

Increasing

Price

Responsivness

of Demand

The Effect of Increased Price

Responsiveness

Early Experience in Increasing Demand Responsiveness

The early experience supports the idea that increased demand responsiveness in periods of

tight supplies can be achieved. We don't yet have the kind of experience that would support a

precise estimate of the amount of demand reduction that might result from a specific price signal.

However, it seems very likely that several hundred, and quite likely more than 1,000, megawatts will

be available in the Northwest when we provide the right incentives.

The simplest way to increase demand responsiveness, in concept, would be to make sure that

retail customers see the actual cost to the power system of providing power at all times (i.e. "realtime" retail prices). Real-time prices are used in some places (e.g. in the province of Alberta) and

have resulted in substantial demand response. However, for a variety of reasons, real-time prices are

not in significant use in this region now, and we don't expect them to become common in the

foreseeable future.

There are alternatives to real-time prices, however. Instead of handing the customer a bill for

real-time costs of electricity use, we can offer a real-time opportunity to be paid (on the basis of realtime power costs) for reducing use at specific times. This approach requires prior contractual

agreements and appropriate metering and is limited in the range of customers who participate, but

can offer incentives to reduce use at peak load hours that are roughly equivalent to the incentives
31

offered by real-time prices. These are NOT interruptible contracts where the whole facility losses

power when the contract is exercised. They ARE arrangements where the participants agree to

manage their loads to achieve load reduction in return for an agreed-upon share of the power

revenues or savings.

Several utilities in the region have offered such alternatives on a pilot or limited basis in the

last year or so. B.C. Hydro offered its Price Dispatched Curtailment program on a pilot basis

beginning in 1998, and has since converted it to a continuing program. This program offers to

remarket power made available by load reductions by certain customers, with the profit from sale of

the power on the open market shared by B.C. Hydro and the customer. The program is exercised

when B.C. Hydro has no surplus of its own to market, and transmission capacity is available to move

the freed-up power to market (e.g. California). On one occasion during the pilot phase of this

program, B.C. Hydro obtained 200 MW of load reduction.

Bonneville Power Administration and Portland General Electric have both initiated Demand

Exchange programs during the summer of this year. Their programs, while not identical, are similar,

both based on the work of the same contractor, Apogee Interactive. An offer is initiated when high

prices are expected and the utility either expects to need to buy from the market to serve its

customers, or has an opportunity to sell into the market and make a margin of profit. The utility

notifies customers participating in the program of the hours and levels of reduction it is seeking, and

the level of compensation it is offering for load reductions. The customer has the option of not

responding at all, or offering an amount of load it is willing to cut in return for the offered

compensation. The utility then re-evaluates the market prospects and the load reduction offers and

notifies customers chosen to reduce load and receive compensation.

The Demand Exchange programs were functioning for only the latter part of this summer,

but the experience has been encouraging. PGE obtained load reductions from its customers 22

times. Load reductions ranged from 30 MW to over 100 MW and the total so far has been 8,300

MWh. The economic benefit of the program, compared to simply serving loads at average costs and

buying from the market when necessary, has been about $3 million, equally divided between the

utility and the participating customers. We don't have comparable data from the Bonneville

program, but we do know that they have achieved their target levels of participation and expect to

expand the program to 300 MW by this winter and to 800 MW by next year.

In addition to the formal programs, there were a few ad hoc deals made between utilities and

customers during the tight-supply episode at the end of June. Our best estimate is that those deals

have totaled 80 to 100 MW.

Large industrial and commercial customers are typically thought to be the best targets. What

can be done depends almost entirely on the nature of the facility, processes employed and the

ingenuity of the operators. For example, air separation would be a prime target, provided the

operation had sufficient storage. Similarly, paper mills employing mechanical pulping, an

electricity-intensive process, can interrupt pulping operations without disrupting production if they

have adequate pulp in storage to sustain operation of the rest of the mill or have excess pulping

capacity. Aluminum plants can rotate electric current reductions through different pot lines.

Facilities with back-up generation could either go off the grid or dispatch power into the grid. Large

commercial buildings, particularly those with modern control systems, may be able to increase air

conditioning (or heating) set points when prices are high. An apparently significant source of load

growth in the region are so-called "server farms" that house the internet servers for the growing "dot-
32

com" industry. Because these facilities require a high degree of reliability, they incorporate back-up

generation. Use of this back-up generation could help. Individually, the contributions are relatively

small. Collectively, they could be quite large.

The operators of industrial processes and commercial facilities are quick to point out that

they are not in the electricity business and don't particularly want to be. However, if the economic

signals are sufficient, that resistance may be overcome. It will, however, take a lot of hard, up-front

work to get a significant amount of demand reduction in place. That work needs to begin now. It is

noteworthy that the California Legislature, responding to this summer's price spikes, appropriated

$50 million for the development of demand management opportunities.

10. The "California Effect"

So long as transmission constraints have not "decoupled" the California market from the

Northwest, what happens in California will have a definite effect on the Northwest. California is a

larger market than the Northwest, and it has moved much farther down the path to restructuring than

any of the other Western states. Moreover, it has done so in its own way. It has created a very

complex market structure that many believe was designed as much to facilitate dealing with the

stranded cost issues of the California investor-owned utilities as it was to open markets to

competition.

The state's investor-owned utilities are required, with limited exception, to sell the power

from generation they still own (largely nuclear and hydro) into the day-ahead and hour-ahead

markets operated by the California Power Exchange (CalPX) and to meet their loads with purchases

from that market. The CalPX is a single-price market -- all sellers whose bids are accepted are paid

the market-clearing price -- the highest price accepted in order to meet loads. Operationally, if there

is an imbalance between the scheduled supply and the forecast demand, the difference is made up in

a "real-time" imbalance market operated by the California Independent System Operator(CAISO).

The primary responsibility of the CAISO is reliability as well as ensuring open, nondiscriminatory access to the transmission system and the efficient operation of electricity markets.

The CAISO provides a number of ancillary services through day-ahead and hour-ahead markets for

regulation, spinning reserves, non-spinning reserves and replacement reserves. There is no cap on

the prices that can be bid in the CalPX. However there are caps on the markets in the CAISO

markets. At the time of primary interest in this analysis, the cap was $750/MWHr. These caps

become de facto caps for the PX as well. If prices in the PX exceed the ISO cap, the incentive is for

the purchaser to submit a schedule to the ISO that does not match expected load. The ISO then must

balance the schedule in the imbalance market. There is at least one exception to the cap in the ISO.

This occurs when the ISO finds it necessary to go "out of market" to purchase energy, i.e., arrange

bi-lateral purchases with suppliers outside the ISO control area to maintain adequate reserve

margins.

For most of its existence (since May of 1998), one could probably conclude that the

California market has operated reasonably well. Figure 10-1 shows a comparison of various

Western market hub prices pre- and post CalPX. Until this year, there is little evidence of prices

going to non-competitive levels.
33

Figure 10-1

Source: Bonneville Power Administration

We have done no independent analysis of the operation of the California market. We have,

instead, relied primarily on the work of the Market Analysis group at the CAISO and a paper

prepared by the independent members of the Market Surveillance Committee of the CAISO.5 6 . The

California market structure is undergoing a great deal of scrutiny in California at the present, and

some redesign seems almost certain. It is very unlikely that anything we would have to say on the

subject will substantially affect the outcome. We would offer some observations based on our

review of the analyses cited above. We believe that when the system is strained, as it has been this

summer, the incentives inherent in the California market structure serve to exacerbate price

volatility.

Limitations on the Ability of California Distribution Utilities to Hedge with Forward

Contracts

The California Public Utilities Commission has limited the ability of the California IOUs to

hedge their risk through purchases of forward contracts. This restriction was probably a reaction to

what turned out to be quite expensive long-term purchases made by California utilities in the past.

In the current environment, it has the effect of forcing a larger proportion of the utilities' load to be

met in the spot market. Had a greater proportion of the load been covered by forward contracts, less

of the load would have been subject to volatile spot market prices. In addition, the Market

Surveillance Committee paper contends that these restrictions reduce the incentive of generators to

bid aggressively into the PX and "significantly enhance the ability of generation owners in the

California market to raise prices in the PX and ISO energy and ancillary service markets."7

 

5 Report on California Energy Market Issues and Performance: May-June, 2000, Special Report prepared by the

Department of Market Analysis, California Independent System Operator, August 10, 2000.

6

 Wolak, Frank I., Chairman; Robert Nordhaus, Member, Carl Shapiro, Member, Market Surveillance Committee of the

California Indpendent System Operator, "An Analysis of the June 2000 Price Spikes in the California ISO's Energy and

Ancillary Services Markets", , September 6, 2000. 7

 Wolak, p.7.
34

Underscheduling in the Day-Ahead and Hour-Ahead Markets

Perhaps more pernicious is the degree to which the distribution utilities and suppliers

underschedule in the day-ahead and hour-ahead markets when the system is stressed. Figure 10-2

shows the amount of underscheduling as a function of system load that occurred this June. This

chart clearly shows that the amount of underscheduling increases significantly when total load

approaches 75 to 80 percent of the maximum load experienced. The amount of underscheduling

reaches almost 20 percent of the peak load.

Figure 10-1

California ISO Average Underscheduling of Loads and Generation

By System Load (June 2000)

Source:California ISO

Absent some other mechanism, the effect of this degree of underscheduling is to require the

ISO to attempt to reconcile a large imbalance in the real-time market. Supplies are tight, time is

short and the operators must scramble to purchase resources. Their primary responsibility is to keep

the lights on. They are in no position to drive hard bargains with potential suppliers. The suppliers

can pretty much get what they ask for.

The ISO recognized this issue and implemented a scheme for purchasing replacement

reserves when schedules do not meet forecast demand. The Market Surveillance Committee paper

contends that this scheme has actually increased the incentive for suppliers to underschedule in the

day-ahead market. By selling replacement reserves, they could be paid at the cap level for capacity

and, if called upon to generate, also be paid the cap for the energy they provide.

Unfortunately, the market participants are only doing what the incentives tell them to do.

Because there is a cap in ISO but not in the PX, when supplies become tight the incentive is for the

distribution utilities to have load supplied out of the ISO. From the standpoint of suppliers, they

know that the pressure of a real-time market will work to their benefit. Moreover, there is potential

for earning twice the cap for supplying replacement reserves or for suppliers located within the ISO
35

control area to "launder" megawatts by selling them to out-of-market participants who can resell to

the ISO at uncapped prices.

We are not going to attempt to put forward remedies for the California market structure.

However, remedies are essential, not only for California but for the rest of the West. To the extent

that the incentives adversely affect the prices in the California market, they adversely affect the

market prices in the rest of the West.

11. Did Market Participants Manipulate the Market?

One of the concerns heard frequently this summer was that some market participants

manipulated the market or exercised undue market power. Clearly the prices we have seen are well

above a "competitive" price, if that is defined as the operating cost of the most expensive unit on the

system that must run to meet load. It is not clear, however, whether this is the result of the exercise

of market power, or the normal functioning of a market when supplies are tight and there is no

moderating effect of price responsiveness. If you happen to have a commodity for which demand

was high and supplies were limited, most of us would charge more than the cost of production for

that commodity. Charging what the market will bear is not illegal.

The Council examined the generating records of most Northwest power plants to see if there

was evidence of "withholding," i.e., holding power off the market to drive up prices8

. We plotted the

output of the plants along with regional demand and hourly prices in the California market. We

found no clear evidence of withholding. Power plants were generally being operated as one would

expect given the characteristics of the plants and a situation of overall tight supplies. Hydropower

plants were typically following load or operating "flat out." Thermal plants were typically running

flat out or, in the case of units with higher operating costs, backed down during the off-peak periods.

For the very few instances of operating patterns that might be interpreted as withholding, the

quantities involved were too small to affect the market. Our general impression is that Northwest

operators, at least, were trying very hard to meet loads.

The Council did not have access to information that would permit analysis of the bidding

strategies of different market participants. We do not know whether that information would suggest

market manipulation or the undue exercise of market power.

12. The Outlook for New Generation

If the fundamental reason behind the prices seen this summer is an overall tightness of

supply, what are the prospects for new development? When the Council did its analysis of regional

power supply adequacy, an attempt was made to assess the likelihood of market-driven development

of new generation using the AURORA model.9

 AURORA models the operation and expansion of

resources throughout the entire WSCC. While its primary use is for wholesale price forecasting, it

can also be used to assess development of new generation. This assessment suggested that the

principal constraint to power plant development has been wholesale power prices. That study

suggested that though favorable project-specific circumstances, such as municipal financing, might

 

8

 As noted earlier, we had access to generation data for approximately 85 percent of the generation capacity in the

Northwest.

9

 AURORA Electric Market Model, EPIS Inc., 18813 Willamette Dr., West Linn, OR 97068, www.epis.com
36

result in the development of a project or two in the next couple of years, forecast market prices

would not support the development of new capacity until about 2004 at the earliest.

Since that assessment was completed, two things have happened. About 750 megawatts of

new gas-fired combined-cycle combustion turbine capacity has begun construction. And market

prices of both electricity and natural gas have risen to much higher levels than those included in our

earlier analysis. Staff has analyzed the ability of a new combined cycle power plant to cover its

fixed and operating costs and reasonable return based on the revenues it would earn by selling at

historical market prices. In earlier years, the results of this analysis have been negative. This year,

the result is positive. Figure 12-1 shows the duration curve of weighted average wholesale prices at

Mid-C for the period October 1999 through September 2000. The shaded area shows days in which

prices were high enough to justify operation of a combined-cycle combustion turbine (CCCT), i.e.

prices are at least as great as the variable operating cost of the CCCT. This analysis takes into

account the higher gas prices paid this year. As this chart shows, a CCCT would have operated all

but about 50 days of the year. The break even line indicates that if prices had not gotten above about

$65/MWHr, the plant would have fully covered its fixed and variable costs. As it was, the prices

exceeded that level for over 100 days. A CCCT receiving market prices for the October through

September period would have earned almost 1.6 times its annual revenue requirement. The "excess"

would be profit, or revenues that help make up for years when prices are not so good.

This is consistent with the results reported by the California Energy Commission (CEC).10

The CEC reports that for August of this year, a new plant would have earned something like 75 to 85

percent of its total revenue requirement for the year and that over the last 12 months (September

1999 through August 2000), such a plant would thus far have earned 2.5 to 3 times its annual

revenue requirement.

 

10 California Energy Commission., http://www.energy.ca.gov/electricity/wepr/2000-08/index.html
37

Figure 12-1

Duration Curve of Prices and Potential Revenues

October 1999 -- September 2000

0

50

100

150

200

250

300

350

400

450

500

1 101 201 301

Days

Price ($/MWh)

Days paying to be dispatched

Breakeven price curve

Mid-C prices

Breakeven Price

From these analyses, it appears that if the electricity and gas prices of the past year were to

continue, there would be substantial incentive for the construction of new generation.

New Power Plant Development Activity

Looking at the entire WSCC, there is a significant amount of new generation that is either

under construction, construction is pending, is fully sited but not scheduled, or is at least under

consideration. The inventory in shown on Figure 12-2.
38

Figure 12-2

Generating Capacity Additions in the WSCC

19700 MW potential 

projects (most in 

permitting) 2750 MW fully 

permitted, not 

scheduled

1980 MW construction 

scheduled

4850 MW under 

construction

1590 MW recently 

completed (Post 97)

The scheduled on-line dates of the planned capacity additions is shown on Figure 12-3. As

this chart indicates, the under-construction and scheduled capacity will just about keep pace with the

growth in peak summer loads in the WSCC over the next two years. Construction lead times are

such that developers need not commit to construction earlier than two years before the on-line date.

This, however, presumes the developer has ordered a turbine in advance or can purchase delivery

from someone else. The lead time for a new turbine is supposedly 46 months.

Figure 12-3

Schedule of WSCC Capacity Additions (On-Line Year)

0

1000

2000

3000

4000

5000

6000

1998 1999 2000 2001 2002 2003 2004 2005

(MW)

Capacity scheduled for construction

Capacity under construction

Capacity recently completed, 1998 to present

WSCC annual load growth (summer peak)

Figure 12-4 shows the scheduled addtions by type. As this clearly shows, development is

weighted overwhelmingly toward gas-fired combustion turbines.
39

Figure 12-4

WSCC Capacity Additions (Recently Completed, Under Construction and Scheduled)

by Type

Nat Gas Combinedcycle

58%

Nat Gas Combinedcycle w/ Cogen

29%

Wind

1% Nat Gas Simplecycle w/ Cogen

1% Nat Gas Simplecycle

10%

Hydro Upgrades

1%

Total = 8205 MW

Figure 12-5 shows the location and status of the "active" Northwest projects of which we are

aware. Again, natural gas-fired units are by far the largest component. As Figure 12-6 shows, the

inventory of active projects in the Northwest has increased substantially over the last year,

suggesting developers are seeing a favorable climate for development. The siting process does not

appear to have been a significant barrier in that there is a backlog of permitted sites at which

construction has yet to begin.
40

Figure 12-5

Location of NW Projects

Williams (NWP) PGT

To Southern

California

To Northern

California

Rathdrum

Klamath Falls

Hermiston

Coyote Springs

Chehalis

Cowlitz

Satsop Frederickson

Everett

Sumas

Creston

From BC

From San Juan

Basin

From Alberta

Starbuck

Umatilla

Stateline GoldendaleWallula

Condon

Interstate gas pipelines

500 kV transmission grid

NGCC plants under construction

NG CC sites permitted

NG CC sites being permitted

Windpower sites being permitted

DC intertie

Figure 12-6

Inventory of NW Projects Under Development

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

1999 2000

Capacity (MW)

Under construction

Fully permitted

Being permitted

How Much Development Actually Will Take Place?

Developer activity certainly suggests that a substantial amount of new generation will be

developed over the next two to three years. Still, we can only be sure about the 1,300 MW under

construction. Should the next couple of years see good hydropower conditions, mild winters and

cool summers, market prices could fall substantially. If that were to be the case, some of the

currently anticipated new generation could be delayed.
41

This raises the question of whether we can rely on the market to develop sufficient resources

to assure reliability and mitigate extreme price spikes. The variability of the hydropower system

introduces an uncertainty for power plant developers in the Northwest that does not exist in most

other parts of the country. When we have tried to simulate the development of new generation using

the AURORA model, we have typically assumed that developers would look at whether they could

cover their costs under "average price" hydropower conditions and average loads. The amount that

gets developed with these assumptions is not sufficient to meet needs under poor hydro conditions

and extreme loads. This analysis requires a number of assumptions, many of which are about things

we don't know very much about. In particular, the results are very sensitive to assumptions

regarding the amount and cost of demand reduction that is available. For that reason, we are

reluctant to treat the results as being definitive. Still, for reliability purposes, it may be necessary to

provide incentives for some capacity that can be dispatched for reliability purposes or to mitigate

extreme price spikes. How the costs of such capacity would be borne and who would control this

capacity are open questions.

The issue of natural gas supply and deliverability is also of some concern. There are

concerns that under extreme winter conditions we might be unable to fully meet the requirements of

existing gas-fired generation and other gas users, let alone additional thousands of megawatts of gasfired generation. As noted earlier, exploration activity is underway that we expect will result in

additional gas supplies. Similarly, pipeline capacity can be expanded relatively easily through

compression and looping of the system. Nonetheless, this all takes time and the commitment of

resources. The Council is looking into the deliverability issue for this winter as well as longer term

supply and deliverability questions.

Recommendations

Encourage the Greater Use of Risk Mitigation Mechanisms

One of the characteristics of a commodity market is the emergence of mechanisms to manage

risk and electricity is rapidly becoming a commodity market. These mechanisms include actual

physical longer-term contracts for supply, futures contracts, financial hedging mechanisms, and so

on. These mechanisms can limit exposure to high prices. At the same time, however, there is

always the risk that they will prove more costly than the spot market. Risk mitigation comes at a

cost and it is not realistic to be fully hedged for all risk. But the experience of this summer suggests

there could be greater use of risk management tools.

As noted earlier, we believe the limitation on forward contracting by California utilities was

a contributing factor to the price extremes of this summer. We believe the same is true of other

market participants in the Northwest and elsewhere. While opportunities to enter into forward

contracts and other hedging arrangements have existed, it may be that the protracted period of low

market prices for electricity lulled some market participants in to believing they had no need of such

mechanisms. Recognizing the commodity nature of the electricity market and taking appropriate

steps to protect against the upside risk is important. Had more market participants done so, it is

likely that this summer's price volatility and its impacts would have been moderated. Forward

contracting is also a vehicle by which new entrants in the generation market can limit their downside

risk, thereby facilitating the development of new generation.

Evaluate the Need and Options for Further Encouraging Generation Development

As noted earlier, the Council's analysis of power supply adequacy indicated that market

prices would not be sufficient to support the development of "merchant" power plants, i.e., plants
42

selling into the spot market exclusively, until 2004. The Council has also done analyses looking at

actual market prices over the past year to see if prices had been sufficient for a new entrant to cover

its variable operating costs and its fixed costs and earn a reasonable rate of return. Until this summer

the answer has been "no."

With the electricity and gas prices experienced over the past year, the answer has become

"yes." With the higher prices, a couple of plants not considered in the Council's adequacy study

have begun construction. In the Northwest, there are now 1,276 MW of capacity under construction

that should come on line in 2001 through 2002. There are another 2,977 MW that already have site

certificates, 1,291 MW of which we judge to be "active" projects, and another 3060 megawatts that

are in or have begun the siting process. The siting process does not appear to be a problem in that

there is a backlog of sites that have been permitted and many more in the process. Almost all of

these are natural-gas-fired combustion turbines, and nearly all of them are located within reasonable

proximity to natural gas pipelines and transmission lines. There is a similar story to be told

elsewhere in the West.

The degree of developer activity is encouraging. However, if we were to experience a couple

years of relatively warm, wet winters and cool summers with good hydro conditions, market prices

would probably fall and many of the active projects might become inactive. If followed by a dry

spell and a hot summer or a cold winter, we would be up against the supply limits again.

The question this possibility raises is whether we can rely on the market to provide sufficient

capacity for reliability purposes. And if not, what are the options for assuring that there is capacity

available to assure reliability and mitigate excessive price spikes? The Council intends to pursue

this question.

Accelerate Efforts to Develop the Demand Side of the Market

While the lead time for the development of new combined cycle generation is relatively

short, development will take some time. During that time the region and the West are vulnerable to

further price spikes and possible reliability problems. Moreover, it is not certain that the long-term

market will support the level of development necessary to assure adequate reliability. Developing

the demand side of the market has the potential for somewhat shorter lead times. Price responsive

demand can help mitigate price spikes and potentially avert reliability problems.

The Northwest has a great deal of successful experience in increasing the efficiency of

electricity end-use as a resource. The region needs to reinvigorate those efforts in light of the market

prices we are experiencing. There are cost-effective means of slowing the growth of demand that

should be exploited. However, the region in particular needs to move aggressively to implement

price-responsive demand management – reducing loads during periods of high prices or shifting the

loads to periods of the day where prices are less. The bad news is that this region has relatively little

experience with these approaches, although that is changing. The good news is that there should be

significant untapped potential.

The Council believes that market-like mechanisms wherein the consumer receives a

significant part of the benefit will be most effective. Pilot programs have been initiated this year in

the region in which the serving utility and the load-reducing consumer share the cost savings of

avoided power purchases (or the revenues from selling the freed-up power on the market). These

programs appear to have been successful although limited in scope. The greatest potential for such
43

partnerships probably exists within industry and large commercial buildings. What can be done will

vary from building to building and process to process. Nevertheless, if provided the incentive, the

Council believes people will rise to the challenge. Creating these incentives should be a priority for

the utilities of the region.

California Should Correct the Incentives in their Market Structure that Contribute to

Excessive Prices and Volatility

The Council believes that the California ISO and others in the California market have done a

credible job of identifying the barriers and incentives created by their market structure that have

contributed to excessive prices and price volatility. We know the issues are complex and politically

volatile. We hope that the state can move quickly to correct these problems.

At Least Until the Market Matures, Data for Monitoring and Evaluating the

Performance of the Market Should be Available on a Timely Basis

One thing that the experience of this summer has shown is that it is difficult to obtain the data

necessary to monitor and evaluate the performance of the market. Despite the fact that utilities in the

Northwest were extremely cooperative, there was a delay of many weeks before the relevant data

could be obtained. While the WSCC maintains a data base of generation and transmission loading

data, not all generators report to the system and of those that do, the data link is not necessarily

carefully maintained. Despite incompleteness data, the WSCC has chosen not to release the

information to independent body like the Council, even when the Council agreed to keep the data

confidential and to use the data in such a way that individual plants could not be identified. We

understand the possible commercial sensitivity of some of this information. We believe, however,

that there should be arrangements possible that both protect the commercial value of the information

and make it possible for responsible independent parties to evaluate market performance on a timely

basis. At least until the market has matured and the public has greater confidence in its operation,

this should be a high priority for market participants and organizations like the Western Systems

Coordinating Committee, the California ISO and regional transmission organizations as they are

formed.

Electricity Emergency Process and Procedures Need to be in Place

If we are correct in our assessment that the electricity market prices experienced this summer

are a warning of approaching scarcity, then establishing the processes and procedures that would be

used in the event of an actual supply emergency should be a priority. Until new generation comes

on line and demand-side programs can be implemented, there is significant probability that our

emergency readiness will be tested. Necessary elements include an inventory of the actions that

could be taken, the trigger points for taking these actions, clear definition of roles and

responsibilities, and a communications plan to inform the public. We are pleased that efforts to

accomplish this are underway involving the Pacific Northwest Utilities Conference Committee, the

Northwest Power Pool, Bonneville, the Council, the Northwest states and region's individual

utilities.