3-1

3. Prices and Costs

Wholesale power prices were high throughout the West in the summer of 2000, but

their implications for consumers were felt most acutely in the San Diego area of

California. Because supplies were tight and prices were high throughout the West,

recourse to imports could not relieve pressure on California prices when loads rose. The

principal findings of the report on western prices and costs during the summer of 2000 are:

• Prices in the Cal-ISO spiked in May and June and average June prices reached

record high levels. With an ISO price cap of $750 for the first time during the

summer, prices became highly volatile and the hourly price hit the $750 cap on 3

days in June. Average June prices reached record levels of $120 in the PX in June.

• Average hourly prices were lower in July than in June, but August prices were

higher than June prices. Caps of $500 in July and $250 in August had a dampening

effect on high hourly prices, but average prices in August rose to $166 in the PX

after falling below June levels to $106 in July. The lower price caps may have

played a role in increasing exports in July and August.

• Prices at other hubs in the West were highly correlated with California prices,

suggesting that opportunities to sell at high prices existed in these regions when

California prices were high. However, it is not yet clear how scarce supplies were

in these regions. Nor is it clear to what extent prices outside California were based

on importing power into California rather than consuming it in other regions. 

Information from other regions in the West for the week of July 31 to August 4

suggests that supplies were in fact scarce, but it is not possible to assess the overall

level of scarcity in the West throughout the summer without additional information.

• Costs for fuel and environmental (NOx) compliance increased significantly in

July and August. Gas prices rose from around $2 per MMBtu early in the year to

around $5 in August and the cost of credits for complying with the NOx standards

rose from around $6 per pound in May to $35 in August and $45 in September. 

Lowered price caps in July and August reduced the ceiling on market prices while, at

the same time, these fuel and environmental costs raised the floor. As a result,

prices traded over a narrower range. Offpeak prices tracked upward with increases

in offpeak demand while exports reduced available supply and outages increased

during these months.

• Prices in some hours appear to be above those that would have prevailed in a

competitive short-term (hourly) market, if the competitive prices were determined

from short-term marginal costs. A Market Surveillance Committee (MSC) analysis
1

“An Analysis of the June 2000 Price Spikes in the California ISO's Energy and

Ancillary Services Markets,” Market Surveillance Committee of the California ISO,

September 6, 2000.

3-2

indicates June prices were significantly above competitive levels using a simulation

approach to defining the competitive price, but results are not available for July or

August.1

• Examination of bid patterns in the PX and in the ISO replacement reserve

markets and a review of ISO out of market purchase activity do not suggest

substantial or sustained attempts to manipulate prices in these markets. Supply

curves bid into the PX show higher bids, on average, when the price caps are

lowered. However, the increases are not correlated with particular classes of

bidders, suggesting that the pattern may reflect increased costs for most participants

rather than a general pattern of attempts by individual bidders or classes of bidders

to exercise market power. 

These results are discussed in three subsections. The first subsection discusses

prices in western markets and California, addressing the first three points above. The next

subsection discusses the relationships between costs and prices, including input costs such

as natural gas prices and environmental compliance, and relates these to the prices observed

in western markets and markets at the California PX and ISO. The final section discusses

bidding in PX and selected ISO markets. 

A. Prices

During the summer of 2000, most of the Western Interconnection experienced

unusually hot temperatures which triggered several price increases throughout the region. 

The volatile wholesale prices that plagued the Pacific Northwest caused some aluminum

plants, pulp mills, cold storage facilities and mines to layoff workers and curtail

production. With respect to California, the price increases that occurred in May and June

were largely caused by unusually high temperatures coupled with robust economic growth

that led to record high growth in electric loads. Prices in July were slightly lower than the

previous month partly due to the California ISO (Cal-ISO) lowering its price cap from

$750/MWh to $500/MWh effective July 1, 2000. However, in August, prices increased

significantly higher than July even though the price cap was lowered again from $500 to

$250 per megawatthour. 
3-3

The following discussion provides an overview of the market, including: market

participants, ownership and market structure, trading patterns, pricing points, risk

management and recent price trends in western markets.

1. Market Players and Ownership

The Western Interconnection has an active wholesale market, comprised of a diverse

group of market participants. Market players in the West fall into the general categories

found in other regions, with some key differences, particularly the large role played by

publicly owned hydropower resources. 

The shares of capacity by class of ownership for each subregion are shown in Table

3-1. In the Rocky Mountain and Arizona-New Mexico-S. Nevada regions, generation

Major California Market Players

IOUs. The three major investor-owned utilities (also known as Utility Distribution Companies) in

California are PG&E, SDG&E and SoCal Edison. The IOUs must buy from and sell all of their

generation through the California PX until the end of the transition period in March 2002, or until

they have recovered their competitive transition charges.

Non-Utility Generators. Generators provide energy and ancillary services either through the

CalPX market or by contracting directly with buyers for ancillary services. Generation owned by

the three IOUs comprised more than 90 percent of the market share during the CalPX's first

months of operation. Between the first and second years of operation the IOUs divested

generation units totaling 17,863MW, resulting in a share of 71 percent for the IOUs and 11

percent for the non-utility generators.

Federal Owners. Much of the hydropower is federally owned, with a large portion held by the

Bonneville Power Authority (BPA.) Since California is so dependent on the availability of

external resources, these owners can have a large impact on the California market as well as the

rest of WSCC.

Municipal and other Public Owners. Municipals, cooperatives and other public entities control

a significant portion of transmission and load in addition to generation. This ownership means that

a significant portion of the transmission system in California is not under the direct control of the

Cal-ISO.

Power Marketers. Market participants buy and sell energy in the Cal PX and Cal-ISO and also

transact in bilateral markets. Many power marketers operating in California markets also own
3-4

capacity is dominated by utilities. In the Northwest, federal entities are the largest

generation owners. The largest share of generation capacity in California is held by nonutility owners, as a result of the state’s generation divestiture.

Table 3-1. Ownership of Plants in the WSCC by Class of Owner

 (Megawatts)

WSCC Subregion

Owner Class Arizona California NorthwestUSNorthwestCanRockies Grand Total

IOU 12,292 10,088 16,019 13 4,699 43,110

NON-UTILITY 2,154 25,439 4,698 951 1,004 35,084

FEDERAL 4,278 2,083 22,050 1,026 29,437

CANADIAN 20,062 20,062

PUBLIC AUTH 4,473 4,346 6,553 831 16,203

MUNI 1,271 7,304 4,986 1,234 14,796

COOP-GEN 795 564 1,863 3,221

MEXICAN 1,506 1,506

All Other 383 1,915 236 543 19 3,192

Total All Classes 25,646 52,682 55,106 21,569 10,674 166,611

Source: RDI Powerdat, August 2000.

As shown in Table 3-1, ownership of generation in the WSCC is divided among

IOUs, non-utilities, and federal, public and municipal utilities. IOUs are the largest class of

owner in the WSCC (26%) with non-utilities holding the second largest share (21%). In

California, however, non-utilities hold more than 50 percent of the generation assets. This

is a significant change from the period before the enactment of California restructuring

legislation, and is a direct consequence of the forced divestiture of most of the IOU

generating capacity. Municipals also hold a larger share (14%) of the generation capacity

in California than in the WSCC as a whole (9%). Prior to the divestiture by the IOUs,

generation capacity in California was more highly concentrated. In 1994, PG&E owned 49

percent of the state's generation, SCE owned 44 percent and SDG&E owned 7 percent. 

After divestiture, in 1999, the total owned by the three IOUs was 43 percent of the

generation capacity in the state, with the other 57 percent divided among several new

generation owners.

 
3-5

2. Trading Patterns and Hubs

While energy is traded at many

locations, prices are reported at hubs

where significant wholesale or bilateral

activity occurs either for ultimate

delivery to load in that area or as a

convenient selling/delivery point for

resale elsewhere.

Trading patterns and prices in

western markets are driven to a large

degree by the geographic placement of

resources. With a heavy reliance on

hydroelectric power as its dominant

generation resource, the Pacific

Northwest has typically provided the

cheapest power in the West. Because of

the importance of hydroelectric power to

the region, the amount of rainfall and

snowmelt in the area tends to have a

significant impact on the market. 

Inexpensive power also originates

in the Rocky Mountains and the

Southwest, where coal-fired generation

is a large contributor to the generation

mix. Because many of the generation

resources in California are oil- and gasfired, power generated there tends to be

more expensive.

The import and export patterns of the West help to explain prices in the region at

any given time. California and Arizona are typically net importers. The Rocky Mountain

Power Area is a net exporter. The Pacific Northwest exports a large volume of power,

although it is seasonal in nature and varies from year to year.

With the deregulation of wholesale power markets, risk management has become a

necessary part of trading in energy markets. Prior to Order 888, utilities traded to balance

loads, buying power mostly from their neighbors with spare capacity. In that cooperative

Western Market Trading Hubs

Palo Verde (PV) is the nuclear plant switchyard in

southwestern Arizona of that name. This hub is a key

selling point for wholesale sales into the Desert

Southwest and southern California. It is accessible

through several 500 kV lines. NYMEX has a futures

contract for this hub.

COB (California Oregon Border) is the location for

deliveries at the Captain Jack and Malin substations in

southern Oregon, immediately north of the California

border. Several 500 kV lines have interties there. This

is often a proxy for sales into northern California in

addition to sales into the Pacific Northwest. NYMEX

has a futures contract for this hub.

Mid-Columbia (Mid-C) is a delivery hub at ties for a

number of dams on the Columbia River. A NYMEX

futures contract at Mid-C began trading on September

15, 2000.

Mead is the delivery point for a number of

transmission lines outside of Las Vegas.

Four Corners is the hub at Shiprock and San Juan

substations in northwestern New Mexico.

North Path 15 (NP15) is a delivery point north of

transmission path 15 in California on selected ties

between Los Banos and Gates.
2Based on information from NYMEX web site: http://www.nymex.com.

3-6

environment, risk management was not a priority. In the competitive market environment,

risk management is an essential component of doing business. 

Traders can hedge their contracts to reduce exposure to adverse price movements. 

A hedge is the purchase of a financial instrument to establish a position to offset the

purchase or sale of energy. A hedge provides a form of insurance that the buyer or seller of

power can obtain or pay a certain price for that power. Only a small percentage of hedge

transactions actually result in the delivery of the energy. A number of hedging instruments

are available to traders in western power markets. 

A commonly used hedging instrument is the option contract. Options grant the

right, but not the obligation, to buy or sell power for an agreed upon price over a specific

period of time. An option allows a trader to exercise a “call” (the right to buy power) or a

“put” (the right to sell power) at a given “strike” price before it expires. Options can take

the form of futures contracts, swaps or the commodity itself. 

Futures contracts are used by market participants to offset the price risk associated

with buying and selling power. NYMEX also offers options contracts which give the holder

the right to purchase or sell the underlying futures contract at a specified price within a

specified period of time in exchange for a one-time premium payment.2 There are three

electricity futures contracts in the West—one based at the California-Oregon border

(COB), one at Palo Verde, and one at Mid-Columbia. All of the contracts are offered by the

New York Mercantile Exchange (NYMEX). The COB and Palo Verde contracts began

trading on March 29, 1996. The Mid-Columbia contract, a recent addition, was launched on

September 15, 2000. The standard trading unit for all of the contracts is 432 MWh onpeak

power delivered over a monthly period. 

Western market participants also rely heavily on forward contracts to protect

themselves from price risk. A forward contract is a supply contract for future delivery of a

fixed quantity of power at a predetermined price, time and location. Forward contracts are

tailored transactions resulting from direct negotiation between a buyer and seller. They

differ from futures contracts in that they are non standardized and non transferable. 

Forward contracts provide price certainty to both the buyer and seller, obligating them to

accept the agreed-upon price, regardless of the market price when delivery takes place.

California has two specialized institutions that came into being during restructuring

and alter the character of the California market when compared with the rest of the West:

the Power Exchange (PX) and the Independent System Operator (Cal-ISO). The PX

conducts day-ahead, day-of and block-forwards markets. The day-ahead market is
3The Cal-ISO Department of Market Analysis reports “..only a nominal amount of

ancillary service capacity traded in the Cal PX BFM,” as of July 28, 2000. Cal-ISO

Department of Market Analysis, Request to Extend Price Caps, filed with FERC August 14,

2000, ER00-3673, Attachment C, p. 8.

3-7

essentially an auction system of 24 one-hourly markets, bid simultaneously and cleared all

at once. The day-of market also consists of 24 auctions, although they are conducted in

three batches over the course of the day. The block-forward market commenced on July

31, 1999, allowing market participants to hedge price risks. The original block-forward

contracts were for the delivery of one MW for 16 hours per day, Monday through Saturday

for a month. Contracts can be made in block multiples of 25 or singly in any quantity. The

contracts were originally specified for delivery in either NP15 or SP15, through either the

CalPX or the bilateral markets. Quarterly block- forward contracts became available on

December 31, 1999. Super-peak and shoulder-peak contracts became available on March

1, 2000. In addition, the CalPX instituted a block-forward market for ancillary services on

May 1, 2000.3

The ISO does not run a day-ahead energy market, but does conduct auctions for

seven separate products: incremental and decremental energy; spinning, non-spinning and

replacement reserves; and upward and downward regulation. These auctions are used to

construct hour-ahead schedules for energy and ancillary services. Energy bids for ancillary

services and supplemental energy are combined to create a real-time supply curve for

energy. These bids are capped by the Cal-ISO price limits, which were $750 at the start of

the summer, but were reduced to $500 in July and $250 in August. In extreme conditions,

the Cal-ISO also engages in out-of-market (OOM) purchases for emergency supplies of

energy. These emergency supplies are not subject to the price cap.

3. Recent Price Trends in Western Markets

Western price spikes during the summer of 2000 far exceeded prices seen in

previous summers. Figure 3-1 shows index prices for all the western market hubs dating

back to 1997. Previous price spikes exceeded $100 per MWh only once prior to the

summer of 2000. Beginning in May 2000, prices spiked over $100 per MWh and the

spikes increased continued through the summer. 
3-8

May price spikes. The first spike of the season was in early May. Prices at Palo

Verde prices rose well over $100 per MWh in response to hot weather and diminished

supplies, with several generation units down for maintenance. The Northwest could not

send supplies south because of its own demands and a large number of coal units were

offline with unplanned outages. Daily index prices at Mid-Columbia reached over

$65/MWh, but did not exceed prices at the typically higher-priced COB and Palo Verde. 

In late May, a heat wave caused western prices to spike again, almost doubling the

spike that occurred two weeks earlier. Hot weather, combined with 6,000 MW of off-line

generation drove day ahead prices at all the western hubs over $200 per MWh. The Cal-ISO

implemented State 2 emergency measures as reserves fell below 5 percent. Some nonfirm loads were cut and the ISO bought supplemental power to prevent rolling blackouts. 

Real-time prices in the California PX rose to the ISO’s $750 cap on ancillary services for

several hours. The California PX average, onpeak day-ahead price topped $316/MWh, an

all-time high. 

June price spikes. In mid-June, western markets experienced another price spike,

with prices reaching an unprecedented level for western markets. Daily index prices at

$0

$100

$200

$300

$400

$500

$600

$700

$800

1-Jan971-May971-Sep971-Jan981-May981-Sep981-Jan991-May991-Sep991-Jan001-May001-Sep00

$/MWh

COB/NOB Mid-Columbia Palo Verde 4 Corners NP 15 SP15

Figure 3-1. Daily Price Indices for Western Market Hubs, 1997-2000
4

 “Traders See Northwest More Easily Outbidding California Under New ISO Cap,”

Power Markets Week, July 3, 2000, pp. 1, 12.

5

“West Prepares for High Temps, Loads; Traders Brace for Vote on Price Caps,”

Power Markets Week, July 31, 2000.

3-9

Palo Verde reached $450, with prices at COB reaching $430 and prices at Mid-Columbia

reaching $400. Real-time prices in California hit the ISO’s $750/MWh cap on ancillary

services for three days straight. Hot weather, the shortage of hydro generation, and plant

outages were cited in trade press reports of the spikes. Temperatures in San Francisco

reached 105 degrees, breaking a 34-year record. The Cal-ISO ordered rolling blackouts,

curtailed interruptible loads, and cut a small amount of firm power to customers in the San

Francisco Bay area. 

In the final week of June, bilateral prices rose to their highest levels to date as

Bonneville Power Administration and the Northwest utilities outbid California and the

Southwest, reportedly paying as much as $1,400/MWh to buy power in hourly bilateral

markets.4 Market players noted that, with caps in place in California markets, adjacent

regions were able to outbid California, buying power out of the state. Hot weather, unit

outages and hydro shortages were again cited by market participants as reasons for the

spike. Daily index prices rose to $677 per MWh at Mid-Columbia, $648 per MWh at

COB, $497 at NP-15 and $513 at Palo Verde. 

July price spikes. Daily prices reached over $100 per MWh several times in July,

mostly at the southwestern hubs. Prices showed a large spike near the end of the month,

during a period of hot weather in the Southwest, with index prices at Four Corners and Palo

Verde reaching over $320 per MWh, with prices $246 at COB and $233 at Mid-Columbia. 

Loads in Arizona set record highs, with the two utilities in Phoenix setting new highs on

five days in July.5 High loads in the Southwest left little power to import to California. 

Hot weather, combined with supply shortages sent up prices throughout the West.

August price spikes. Western hub prices remained at a significantly higher level for

the month of August. Starting around mid-July, prices at the western hubs never fell below

$110. The average index price for August was $211.33 at SP15, and $188.73 at NP15.

In early August, prices at Palo Verde reached $1,500 per MWh in hourly markets,

with Palo Verde index prices escalating to $523 per MWh. Index prices at COB and MidColumbia reached almost $500 per MWh, hitting $481 and $472, respectively. High

temperatures in the Southwest and in parts of California were partially responsible, but

wildfires threatened transmission facilities and increased the pressure on prices.
6

“N.W. Prices Escalate as Hydro Dwindles; Dams Store Water, Runoff Disappears,”

Power Markets Week, August 28, 2000.

7California PX Report on June 29, 2000, “Price Behavior in the CalPX Markets,

May-June 2000.”

3-10

Prices generally remained over $200 per MWh at the southwestern hubs for the

duration of August. For the remaining hubs, prices fell below $200 for several days. But in

late August, prices surged in the Northwest when hydro generation was restricted. Hydro

supplies came to an abrupt halt as dam operators were forced to fill reservoirs so

they could continue to provide power through the rest of the year.6 Day-ahead prices at

Mid-Columbia and COB increased to $260 per MWh.

Increase in overall price levels. The summer 2000 price levels greatly surpassed the

price levels of prior years. Figures 3-2 to 3-4 compare prices at COB, Palo Verde and

Mid-Columbia for the past three summers. The summer 2000 prices show a dramatically

different pattern from the previous 2 years, with large spikes in May and June. In mid-July

through August 2000, lower price caps limited the prices in hourly markets, but the general

level of prices was significantly higher, hovering around $200. A similar trend can be seen

at Palo Verde and Mid-Columbia, with extreme price spikes or high overall prices

occurring throughout the summer in 2000, compared with much lower price levels for the

previous two summers. 

Prices in western markets show a close relationship to the prices in the California

PX from which 80 percent of load, served by IOUs in California, must purchase energy. 

The California PX noted this relationship on an average basis for the May and June period.7

Figure 3-5 shows daily onpeak prices for NP15 and SP15 for bilateral markets and

the California PX. While the prices track very closely, the PX prices show much larger

spikes than the bilateral prices. The California PX products are not identical to the bilateral

market products. The bilateral market prices are index prices for 16-hour blocks 
3-11

$0

$100

$200

$300

$400

$500

$600

3-May7-May

13-May19-May25-May

1-Jun7-Jun

11-Jun17-Jun23-Jun29-Jun

7-Jul

13-Jul19-Jul23-Jul29-Jul5-Aug

11-Aug17-Aug23-Aug27-Aug

2-Sep

Dollars per MWh

1998 1999 2000

Source: Power Markets Week .

Figure 3-2. Bilateral Index Prices at Palo Verde

$0

$100

$200

$300

$400

$500

$600

$700

3-May7-May

13-May19-May25-May

1-Jun7-Jun

11-Jun17-Jun23-Jun29-Jun

7-Jul

13-Jul19-Jul23-Jul29-Jul

5-Aug

11-Aug17-Aug23-Aug27-Aug

2-Sep

Dollars per MWh

1998 1999 2000

Source: Power Markets Week .

Figure 3-3. Bilateral Index Prices at COB
3-12

$0

$100

$200

$300

$400

$500

$600

$700

$800

3-May7-May

13-May19-May25-May

1-Jun7-Jun

11-Jun17-Jun23-Jun29-Jun

7-Jul

13-Jul19-Jul23-Jul29-Jul5-Aug

11-Aug17-Aug23-Aug27-Aug

2-Sep

Dollars per MWh

1998 1999 2000

Source: Power Markets Week .

Figure 3-4. Bilateral Index Prices at Mid-Columbia

$0

$100

$200

$300

$400

$500

$600

1-May8-May

15-May22-May29-May

5-Jun

12-Jun19-Jun26-Jun

3-Jul

10-Jul17-Jul24-Jul31-Jul

7-Aug

14-Aug21-Aug

Dollars per MWh

NP15 SP15 CalPX NP15 CalPX SP 15

Source: RDI PowerDat. Bilateral prices are Power Markets Week 16-hour on-peak prices.

Figure 3-5. Western Market Prices for Summer 2000: Bilateral Markets 

 vs. California PX
8The PX prices have been averaged for a 16-hour block period to correspond to the

16-hour block traded in bilateral markets, but the products are not the same because buyers

and sellers in the PX set individual hourly prices whereas bilateral buyers and sellers trade

at a single price for the entire block. Buying a block at a single price does not permit the

buyer to tailor hourly prices to expected hourly levels, and is consequently less flexible,

particularly if the buyer plans to resell in hourly markets.

3-13

of power. The PX prices and sells power on an hourly basis.8 It is possible that, because

these products are slightly different, they are valued differently at peak times. 

The pattern of prices was different in July and August. The PX and bilateral market

prices tracked more closely, with bilateral market prices often higher than PX prices at

NP15 and PX prices remaining higher at SP15.

Forward market prices were much lower earlier in the year and were used by some

market participants to hedge potentially high prices over the summer. Figure 3-6 shows

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

1-Jul971-Oct971-Jan981-Apr981-Jul981-Oct981-Jan991-Apr991-Jul991-Oct991-Jan001-Apr001-Jul001-Oct001-Jan011-Apr011-Jul01

$/MWh

LOWDEAL HIGHDEAL

3Q 1998 Contract 3Q 1999 Contract 3Q 2000 Contract

Source: Power Markets Week

3Q 2001 Contract

Figure 3-6. Palo Verde Forwards: 3rd Quarter Contracts
3-14

forward contracts for the third quarter for the last 3 years (1998 through 2001) at Palo

Verde, COB and Mid-Columbia. Forward prices have risen in each of the past 3 years. A

substantial number of forward contracts were made in early 2000 at prices between $60 and

$80 per MWh. Market participants who purchased forward contracts for the summer of

2000 received prices well below spot market prices. COB and Mid-Columbia had similar

patterns, with somewhat lower prices for those hubs.

Figure 3-7 shows the July futures contract at COB for 1998 through 2001. While

no July 1998 contracts were traded prior to March 1998, trading for both the 1999 and

2000 contracts began as early as one year earlier, as market players recognized the need to

prepare for summer price spikes. Prices for July 2000 were as low as $50 per MWh up

until April 2000. After April, the July contract escalated, reaching almost $140 per MWh

prior to expiration. Futures prices that seemed high earlier in the year resulted in

significant savings to those who used futures contracts to hedge their positions in the

market. A similar pattern occurred for the August contracts at COB and Palo Verde.

The number of futures contracts traded declined substantially in 1999 and 2000. 

Market participants have noted in discussions that they find the futures contracts less

flexible than individually tailored forward contracts, preferring to use over the counter

forwards instead. A contract structured around a monthly market may not be sufficiently

flexible to attract a large number of buyers in a market given to a high level of daily and

hourly volatility, where both buyers and sellers may have different supply and demand

profiles. Over-the-counter products customized to buyer and seller needs, while more

expensive to arrange than current futures market products, may be the best alternative in the

absence of greater ability to develop attractive standardized products.
3-15

4. Correlation of Prices in Western Markets

Bilateral and PX Markets

Table 3-2 shows the correlations of western market onpeak prices for the summer

2000 period. The correlations between California PX prices and western market bilateral

prices are quite strong. As one would expect, the correlations between the California PX

prices and bilateral prices at NP15 and SP15 are high. By the same token, CalPX NP15 and

Mid-Columbia are highly correlated, as are CalPX SP15 and Palo Verde because of the

geographic proximity of the points and the general absence of transmission limits into

California. Correlations between all of the western onpeak prices show correlations of

0.858 or above.

0

100

200

300

400

500

600

700

800

900

1000

1-Jul-97 1-Oct-97 1-Jan-98 1-Apr-98 1-Jul-98 1-Oct-98 1-Jan-99 1-Apr-99 1-Jul-99 1-Oct-99 1-Jan-00 1-Apr-00 1-Jul-00

# of Contracts

$0

$20

$40

$60

$80

$100

$120

$140

$160

$/MWh

Volume Traded Day High Price $/MWh Day Low Price $/MWh Day Close Price $/MWh

July 1998 Contract July 1999 Contract July 2000 Contract

Source: RDI POWERdat

Figure 3-7. COB Futures: July Contracts
9

“N.W. Prices Escalate as Hydro Dwindles; Dams Store Water, Runoff Disappears,”

Power Markets Week, p. 11.

3-16

Table 3-2. Correlations of Western Market Prices: Onpeak Prices from 

 Megawatt Daily and California Power Exchange

 (May 1-August 21, 2000)

COB/

NOB

MidColumbiaPalo

Verde

4 Corners

NP15 SP15

Cal PX

NP15

Cal PX

SP15

COB/NOB 1.000

Mid-Columbia 0.997 1.000

Palo Verde 0.971 0.963 1.000

4 Corners 0.961 0.953 0.995 1.000

NP 15 0.992 0.987 0.974 0.966 1.000

SP 15 0.969 0.960 0.992 0.983 0.977 1.000

CalPX NP15 0.912 0.908 0.865 0.858 0.919 0.876 1.000

CalPX SP15 0.915 0.906 0.932 0.932 0.922 0.937 0.930 1.000

Table 3-3 shows the correlations of offpeak western market prices. The

correlations of offpeak prices show strong relationships between prices in bilateral

markets, but the relationships between prices in the CalPX and bilateral markets are

weaker. The CalPX SP15 price shows a higher correlation to all the bilateral prices than

does the NP15 price. One would expect the CalPX NP15 to more closely correlate to the

COB/NOB price because it is closer in proximity. 

During summer 2000, power flowed into the Northwest from California especially

during offpeak hours to allow hydro generators to store water for more costly onpeak

hours.9 It is possible that the demand for exports of offpeak power from California to the

Northwest created a different pattern of prices for markets in northern California.
10Report on the California Energy Market Issues and Performance: May-June

2000, prepared by the Department of Market Analysis, California Independent System

Operator, August 10, 2000.

3-17

Table 3-3. Correlations of Western Market Prices: Offpeak Prices from 

 Megawatt Daily and California Power Exchange

 (May 1-August 21, 2000)

COB/NOB

MidColumbiaPalo

Verde 4 Corners

CalPX

NP15

CalPX

SP15

COB/NOB 1.000

Mid-Columbia 0.963 1.000

Palo Verde 0.946 0.942 1.000

4 Corners 0.848 0.881 0.946 1.000

CalPX NP15 0.499 0.568 0.422 0.596 1.000

CalPX SP15 0.742 0.699 0.700 0.554 0.702 1.000

ISO Energy and Ancillary Services Markets

Ancillary Services prices showed a similar pattern to that of energy prices in the PX

and ISO during the summer of 2000. As shown in Figure 3-8, spinning, non-spinning and

replacement reserves reached the level of the price cap ($750 per MW in May and June,

$500 per MW in July and $250 per MW in August) for periods throughout the summer. 

These patterns track with the energy market price and reflect the opportunity cost of

generators' providing ancillary services. That is, if generators are holding a portion of their

units in reserve, they are foregoing the revenue they could have earned by providing energy

in the day-ahead, hour-ahead, or real-time markets. 

The ISO instituted an additional purchase price cap for replacement reserves at $100

per MW as part of a strategy to reduce out-of-market calls associated with underscheduling. As shown in Figure 3-9, the ISO increased the amount of replacement reserves

it purchased in July and August relative to the level it had purchased in May and early June.

The Cal-ISO reports that the strategy to reduce the reliance on out-of-market calls

may have increased generators' incentive to withhold capacity from the day-ahead PX

energy market and shift capacity into replacement reserve and real-time energy markets

during the high load periods.10 Suppliers could benefit by not scheduling capacity in the

day-ahead markets, and instead bidding into the replacement reserve market so that they

have a high probability of receiving both the capacity payment for replacement reserves and
11California ISO, “Minutes of Special Board of Governors Meeting,” June 28,

2000.

3-18

also the real time energy price. During high load periods, the replacement reserve price

can be high and a high proportion of all available energy is likely to be taken by the Cal-ISO,

so this can be a profitable strategy. In July, the Cal-ISO lowered the price cap on

replacement reserves in an attempt to limit the attractiveness of this strategy.11

Real-time energy prices in the Cal-ISO closely follow the PX prices for the same

period. As described above, these two markets are linked since one is effectively a

substitute for the other from both the supply and demand perspectives. It is also clear that

the real-time energy and PX prices experienced longer periods of prices at or near the

price cap than the ancillary service price. 

$0

$100

$200

$300

$400

$500

$600

$700

$800

May June July August

Dollars per MWh

Spinning Reserves Price

Non-Spinning Reserves Price

Replacement Reserves Price

Figure 3-8. Day-Ahead Spinning, Non-Spinning and Replacement Reserves 
3-19

-400

-200

0

200

400

600

800

1,000

1,200

1,400

1,600

May June July August

MWh

Day - Ahead Replacement Reserve Hour- Ahead Replacement Reserves

Figure 3-9. Day-Ahead and Hour-Ahead Replacement Reserve MWh, NP15

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

1-Jan 1-Mar 1-May 1-Jul 1-Sep 1-Nov 1-Jan 1-Mar 1-May 1-Jul 1-Sep

Dollars per MMBtu

Malin NW Sumas Stanfield El Paso San Juan Non-Bondad

Source: Gas Daily. Data through Sept. 13, 2000.

Figure 3-10. Daily Spot Prices for Western Natural Gas Markets in 2000 
3-20

B. Cost Factors in Prices and Price Increases

1. Input Price Increases

One of the reasons for the higher prices in the West during the summer of 2000 was

the increase in input prices, specifically increases in natural gas prices and NOx

compliance costs. As shown in Figure 3-10, natural gas prices roughly tripled from January

2000 to September 2000 in the West.

Since natural gas-fired units are usually the marginal units during peak demand

periods, input price increases can have a significant impact on the market clearing price. 

For example, for a gas-fired unit with a heat rate of 10,000 Btu/kWh, if the natural gas price

goes from $2.00/MMBtu to $5.00/MMBtu, the fuel cost rises from $20.00/MWh to

$50.00/MWh. 

In addition, the price of the NOx credits necessary to run gas units also increased

significantly. As shown in Figure 3-11, the price of NOx RECLAIM credits rose from

$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

$50

May-00 June-00 July-00 August-00 September-00

Dollars per pound

Figure 3-11. NOx RECLAIM Prices for SCAQMD, May to September, 2000
12The prices in Figure 3-11 are averages based on sales reported by Cantor

Fitzgerald Environmental Brokerage Services, www.cantor.com/ebs. The May, June and

July and August figures reflect both vintage 1999 and 2000 RECLAIM allowances. The

September figure is for vintage 2000. June 1999 RECLAIM allowances expired at the end

of August 2000.

13Both examples assume an increase in the natural gas price from $2 per MMBtu to

$5 per MMBtu and an increase in the NOx emissions credit price from $6.00/lb to $40/lb. 

Under extreme conditions gas-fired units with heat rates exceeding 16,000 Btu/kWh may

be called on to produce energy in the PX or real-time energy markets. The ISO DMA uses

somewhat more extreme emissions and heat rate assumptions in Market Analysis Report,

September 2000, basing costs on a NOx rate of 4 lb/MWh and at heat rate of 20,000 for a

combustion turbine. These extremes can be reached, but only in the most extreme

emergencies. However, they use $35 for NOx costs, the approximate August average,

rather than the end of August price. They estimate a price of just under $250 rather than the

lower number we provide here. Given the uncertainties in the information, either estimate

is consistent with high prices close to $250 in August.

3-21

approximately $6.00/lb to over $40/lb at the end of August.12 A combined-cycle gas

generator typically emits around 1 pound of NOx per MWh. A combustion turbine gas

peaking unit can emit more than 2 pounds of NOx per MWh. At a price of $40/lb, the

emission reduction cost of a gas peaking unit would be approximately $80/MWh as

opposed to $12.00/MWh when the NOx credit price is only $6.00/lb. Taken together, the

increases in natural gas and NOx credit prices raised the marginal running cost of a

combined cycle generation unit with a heat rate of 10,000 Btu/kWh and a NOx emission

rate of 1 lb/MWh by approximately $64.00 per MWh (from $26.00 to $90.00 per MWh). 

Most critically, in times of peak demand when internal and external transmission

constraints limit transfers, the least-efficient plants are called on to provide energy and

thus set the market-clearing price. These plants have the highest heat rates and some of the

highest NOx per MWh emission rates. In these cases, the marginal running cost of the

plant is significantly above $100/MWh. For example, for a combustion turbine gas-fired

peaking plant with a heat rate of 16,000 Btu/kWh with a NOx emission rate of 2 lbs/MWh,

marginal running cost would have risen from $44/MWh to $160/MWh.13 Therefore,

market clearing prices that approach the $250/MWh price cap may simply reflect the true

cost of the resource and be solely the result of tight supply, not the exercise of market

power. Figure 3-12 shows the effect of rising natural gas prices and NOx emission permit
14Cost estimates based on stated heat rates, average western hub gas prices from the

four hubs shown in Figure 3-10, assumed NOx emission rates of 1 and 2 lb per MWh, for

the 10,000 and 16,000 Btu/kWh heat rates respectively, and a linear estimate of NOx

reclaim prices ranging from $6.00/lb. on May 1 to $40.00/lb on August 31. Note, the NOx

emission rate is not simply of function of the heat rate, it also depends on the unit-specific

NOx burn rate. That is, two different combustion turbines with the same heat rates could

have different NOx emission rates.

3-22

rates on the running cost of gas-fired generation from a combustion turbine emitting 2 lbs

NOx per MWh over the summer of 2000.14

C. Bidding in the CalPX and Selected Cal-ISO Markets

This section discusses bidding patterns in the PX and the ISO replacement reserve

market, and the role of out-of-market purchases by the ISO. These discussions provide

information on the patterns that appear to have driven the high prices encountered in the

summer of 2000. The PX bidding is discussed first, followed by bidding in the ISO

replacement reserves and out of market purchases.

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

1-May8-May

15-May22-May29-May

5-Jun

12-Jun19-Jun26-Jun

3-Jul

10-Jul17-Jul24-Jul31-Jul

7-Aug

14-Aug21-Aug28-Aug

4-Sep

11-Sep

Dollars per MWh

10,000btu/kWh

16,000btu/kWh

Figure 3-12. Estimated Running Cost for Gas-Fired Generation in Southern 

 California
15 California Power Exchange Corporation Compliance Unit, Price Movements in

California Electricity Markets, September 29, 2000.

16 For further discussion of incentives for shifting supply away from the day-ahead

PX market, see California PX Report, September 29, 2000, ISO Market Surveillance

Committee Report, September 6, 2000, and report from the ISO Department of Market

Analysis, August 10, 2000.

3-23

1. Bidding in the CalPX

In the last section, the decrease in the amount of power scheduled through the PX on

a day-ahead basis was described. Given the requirement for balanced schedules in the

California design, the reduction in the proportion of power scheduled day-ahead is the joint

result of bidding by both supply and demand. However, much of the change has been driven

by suppliers migrating to other markets, such as the real-time market or the export market. 

As a result, there is a clear reduction in the total supply available in 2000 compared with

1999. This result has been documented by the recent analysis provided by the PX.15 This

section further examines bidding patterns over the last summer to determine how the

pattern changed as the Cal-ISO price cap changed over the summer. Although the PX has

no price cap, the Cal-ISO cap provides a de facto cap, since the Cal-ISO markets provide an

alternative for both loads and supply. Loads will have an incentive to move their purchases

to the Cal-ISO rather than bid to raise prices in the PX above the Cal-ISO price cap. And

suppliers have incentives to shift sales to Cal-ISO markets at peak times in hopes of gaining

a capacity payment for replacement reserves and also being paid at the price cap for realtime energy.16

For these reasons, one would expect the level of the price cap to have some

detectable impact on bidding behavior. This impact is examined from two primary

perspectives. First, differences in the total amount of supply offered into the day-ahead PX

market are examined. Second, changes in the shape of bid curves are examined by studying

the proportion of supply offered at selected price levels.

Quantities of Supply Bid into the PX

To examine how supply quantities bid into the PX changed over periods with

different Cal-ISO price caps, the quantity of supply made available under the price cap was

calculated from bidding data by participants. Participants were classified by the following

categories used by the PX. The three largest participants are the California IOUs, the new

generation owners (NGOs) who have acquired the divested units previously owned by the

California IOUs, and the power marketers. These entities account for over 90 percent of
17 The $750 period extends from May 1 to June 30, the $500 period from July 1 to

August 6, and the $250 period from August 7 to September 20. Although the $250 period

extends past the end of August, used as the end date for other statistics in the report, it was

used here to make use of the additional information gained by the extension.

3-24

the quantities bid into the PX market. Other participants with smaller shares include

municipal and other governmental participants and IOUs outside California. 

Figure 3-13 shows the quantity bid into the PX under the Cal-ISO price cap for three

time periods defined by the level of the Cal-ISO price cap17 and the three major participant

categories. The quantities represent the average total quantity bid hourly during onpeak

hours over the period. There appears to be little or no change in the total quantity bid for

any of the participant categories. Figure 3-13 includes all supplies bid, and includes the

quantities bid in at zero prices, which make up around two-thirds of the total and may not

change appreciably when the price cap changes. However, it is interesting to note that the

price cap seemed to have a relatively small impact on the total quantity bid. 

In each participant category, slightly more supply is bid into the PX in July, when the

price cap was at $500, than in the other two periods when the cap was lower or higher. This

period corresponds to the time when the supply/demand picture was less tight than it was

before, in June, or afterwards, in August. Under these conditions, there may be fewer

opportunities to sell outside of California because supplies in the West were generally

more abundant. 
3-25

Changes in Bid Shape

August prices were higher than June prices on average in both the PX and the ISO,

even though the ISO cap was reduced from $750 to $250 over the period. The higher price

in the PX is a result of upward shift in the supply offered in the PX. This upward shift can

be seen by calculating the percentage of supply offered at any given price level. Table 3-4

shows the percentage of supply offered at $100, $150 and $200. Figure 3-14 depicts the

percentages offered at $100. These percentages clearly show that all participant categories

changed the supply they offered as the price cap was reduced, particularly when the price

cap fell to $250. However, it may be incorrect to attribute the change in bidding patterns

solely, or even primarily, to the price cap reduction. As 

0

5,000

10,000

15,000

20,000

25,000

Megawatts Bid Into PX Day-Ahead Market

ISO Cap=$250 18,018 4,445 3,506

ISO Cap=$500 19,270 5,277 3,615

ISO Cap=$750 18,514 4,441 3,483

Onpeak Total 18,544 4,647 3,523

Cal IOUs New Generaton Owners Power Marketers

Figure 3-13. Comparison of PX Onpeak Supply Bid Under ISO Cap 

 for Selected Participant Types
3-26

Table 3-4. Bidding in the CalPX by Participant and Cal-ISO Price Cap, May to 

 September 2000

ISO Price

Cap

California

IOUs

Municipal/

Government

New

Generation

Owners

Northwest

IOUs

Power

Marketers

Southwest

IOUs

All

Participants

Percent of Non-Zero Supply Offered at $100

250 63.4 76.9 55.5 81.0 51.1 84.0 59.6

500 77.2 82.5 77.5 86.3 73.2 86.5 76.8

750 84.4 94.1 82.0 95.2 73.1 87.7 81.3

Percent of Non-Zero Supply Offered at $150

250 83.3 81.6 72.9 86.9 66.6 91.7 74.9

500 88.1 85.3 82.6 92.8 79.9 90.9 83.7

750 88.7 96.7 88.0 97.7 75.6 90.7 85.4

Percent of Non-zero Supply offered at $200

250 89.6 87.4 84.3 91.7 76.6 94.9 83.2

500 91.4 90.0 86.5 96.3 83.0 93.0 87.2

750 91.1 97.2 91.2 98.8 77.8 92.2 87.8

30

40

50

60

70

80

90

100

California IOUs

MUNI/GOVT

New Generation Owners

Northwest IOUs

Power Marketers

Southwest IOUs

All Participants Combined

Percent

ISO Cap=750

ISO Cap=500

ISO Cap=250

Figure 3-14. Percentage of Non-Zero Supply Bid at $100 or 

 Below
3-27

discussed in the last section, costs rose over the same period, shifting costs upward and

changing the underlying cost structure. Since all participant categories exhibit the same

pattern, the changed bid shapes are unlikely to be the result of individual participants or

classes of participants changing their bidding behavior in an attempt to manipulate prices.

2. Cal-ISO Replacement Reserve Markets and Out-of-Market Purchases

Both replacement reserve markets and out of market purchases by the Cal-ISO were

closely related to the problem of underscheduling in the Summer of 2000. When

underscheduling in the day-ahead and hour-ahead markets occurred, the ISO turned to

replacement reserve markets or out-of-market (OOM) purchases to procure capacity

needed to provide energy for meeting the difference between the forecasted load and the

scheduled supply. The policy of purchasing replacement reserves for this purpose was

motivated in part by the desire to limit the use of out of market calls, which take place

outside the structure of the normal market during emergencies and are not subject to the

price cap. As a result of these policies, OOM purchases were only a small portion of total

energy costs in May through August. OOM purchases totaled $93 million dollars, less than

1 percent of the total energy costs of $11.6 billion. Around half of the cost and quantity of

OOM purchases were for power from public entities or scheduled through public entities

as scheduling coordinators.

Replacement reserve total costs were much greater than OOM purchase costs,

totaling $217 million dollars in June alone, almost half the total ancillary service costs of

$436 million dollars for the month. Examining bids and bid patterns for two high-costs

weeks in June showed a pattern of increased bidding into the replacement reserve market as

the week progressed. The quantities bid into the replacement reserve markets are shown in

Figure 3-15, where these quantities are compared with quantities bid into the PX for the

week of June 12 to 16. Replacement reserve costs for Tuesday to Thursday of this week

were over $120 million. It appears that more offers are placed in the replacement reserve

markets this week as the hotter weather sets in, while the quantity bid into the PX falls or

remains level. This information confirms that bidders are following their incentives to

place supplies in the replacement reserve market, where they can obtain payment for both

reserve capacity and for replacement energy when called. Given these incentives, bidders

would shift additional supplies to the day-ahead or hour-ahead replacement reserve market,

rather than the day-ahead PX energy market, in order to obtain additional payment for

reserve capacity. While there are a range of bidding patterns in the replacement market, no

one participant or class appears to dominate others in setting the overall pattern. It is also

interesting to note that the higher level of bidding into replacement markets continues even

on Friday, June 16, when replacement reserve costs and purchases by the ISO have fallen to

low levels.
3-28

3. Transmission Congestion Costs and Prices

Transmission was not a major issue in 2000 in most discussions with market

participants. However, as noted in Section 2.B.6, transmission congestion patterns shifted

in 2000 compared to earlier years, but congestion remained significant. Transmission

congestion on paths into California generally lessened, but congestion on major paths

within California, Path 15 and Path 26, worsened during some periods. Overall, day-ahead,

interzonal congestion costs were $141 million in May to August 2000 compared with $27

million in 1999. However, $81 million of the cost was for congestion on Path 26, which

not counted as interzonal congestion cost prior to the start of zone ZP26 in February,

2000. If these charges are removed, year 2000 costs are $60 million in 2000. This

indicates that comparably-compared congestion costs about doubled from 1999, a

somewhat smaller increase than overall energy costs.

Table 3-5 shows the congestion charges on the major transmission paths in 1999

and 2000. In general, the total cost impact of imports was less in 2000, particularly during

peak periods. Costs for imports were much lower in 2000 on COI, during both peak and

offpeak periods. As shown earlier in Table 2-18, import flows on NOB and Eldorado were

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

12-Jun 13-Jun 14-Jun 15-Jun 16-Jun

MW Average Onpeak Hour

$0

$100

$200

$300

$400

$500

$600

$700

$800

Replacement Energy Cost ($/MWh)

PX MW Bid Replacement DA Bid MW Replacement Energy $/MWh

Figure 3-15. CalPX Bids, Replacement Reserves and Real-Time Payments

 to Replacement Units, June 12 to June 16 
3-29

much lower in 1999, so the higher charges in 2000 for these paths, shown in Table 3-5 did

not have as much impact. However, internal California paths, that affected the price

difference between NP15 and SP15, Path 15 and Path 26, were both congested more often

in 2000 than in 1999 and had cost per MWh of congestion. Exports flowing north offpeak

were also more frequent and more costly per MWh, as show in Table 2-18 and in Table 3-5. 

Table 3-5. Transmission Congestion Price During Congested Hours on Major 

 Congested Paths, May through August, 1999 and 2000

Transmission Path 1999 2000

Difference 

(2000 minus 1999)

Onpeak Congestion

Imports over Cal-Oregon Intertie (COI) $13.96 $0.50 -$13.46

Imports from Oregon over DC Tie (NOB) $5.15 $16.47 $11.32

North to South flow on Path 15 $12.18 $34.78 $22.60

North to South flow on Path 26 $0.00 $61.21 $61.21

Offpeak Congestion

Imports over Cal-Oregon Intertie (COI) $9.19 $0.00 -$9.19

Imports from Southwest over Eldorado Path $4.83 $7.86 $3.03

Exports Oregon over DC Tie (NOB) $4.83 $27.25 $22.42

South to North flow on Path 15 $5.91 $24.99 $19.08