1Price Movements in California Electricity Markets, California Power Exchange

Corporation Compliance Unit (PX September report), September 29, 2000, at 10.

2Edison International, SEC 8K Filing, September 25, 2000; "California Utilities' Losses On

Electricity Pose Risk, Wall Street Journal Interactive Edition, September 27, 2000; Joint Motion for

Emergency Relief and Further Proceedings of Pacific Gas and Electric Company, et. al., San Diego

Gas & Electric v. Sellers of Energy and Ancillary Services, Docket No. EL00-95-000 et. al., pp. 5-7,

October 16, 2000.

5-1

5. Why Were Prices High This Summer?

The West experienced unusually high electricity prices during the summer of 2000, with large

spikes in May and June, and high average prices throughout the summer. As discussed in Section 3,

prices in western markets showed a close relationship to prices in the California PX. Prices in the PX

reached as high as $750/MWh during individual hours.1 Average PX prices were high all summer:

$47/MWh in May, $120 in June, $106/MWh in July, and $166 in August. Many end-users were

insulated from these wholesale price spikes, by rate freezes in most parts of California, or by traditional

utility regulation in other western states. However, others were not insulated from high prices. Endusers in the San Diego area were not protected by a retail rate freeze and saw their electricity bills

increase several-fold. Some industrial users in the Northwest also experienced price volatility. The

three IOUs in California have seen their financial position significantly weakened by these increased

prices.2

There are three possible factors that can contribute to high prices. This section is divided into

three subsections to discuss the effect of each factor on western prices in the summer of 2000:

A. Competitive market forces. Prices can be driven up by the normal forces of a

competitive market, such as increases in costs of fuel or environmental compliance, or

by scarcity of supply. 

B. Market design problems. The rules of market institutions may contribute to prices

higher than those that would prevail under competitive forces or with more efficient

rules.

C. Market power exercise. If sellers possess market power, they have the potential to

influence price. If conditions are conducive, the market price can be raised significantly

above competitive levels. 

In principal, it is important to distinguish among these three factors, because each factor calls

for somewhat different regulatory approaches. In the absence of flawed market rules or the exercise of

market power, competitive market forces may not call for regulatory action, or may only call for further
5-2

monitoring of overall market developments. Market design problems are generally best addressed by

changing the market rules. Approaches to dealing with the exercise of market power may vary from

compliance actions, to development of new rules, or to broader policy measures.

In practice, one single type of explanation seldom dominates the others, especially under

extreme conditions such as those observed in the West over the past summer. Market rule problems

with new institutions during a transition period, scarcity or near scarcity supply conditions, and rapid

increases in input prices with their associated uncertainty may all be conducive to the exercise of market

power. At the same time, these conditions make the detection of the market power exercise more

difficult, because they can lead to many of the same results. For example, scarcity can lead to price

spikes in competitive markets and rapid increases in input costs can lead to increases in average prices

in competitive markets. Policymakers addressing these issues will need to consider all three

explanations of high prices.

This staff investigation found that all three factors played some role in the high prices seen in the

West in the summer of 2000. The data clearly show that a general scarcity of power in the West and

increased costs to produce power were factors causing these high prices. It is also clear that existing

market rules exacerbated the situation and contributed to the high prices. The data also indicate some

attempted exercise of market power, if the standard of bidding above marginal running cost is used, and

some actual market power effects, to the extent that prices, at least in June, were significantly above

competitive levels. However, the data do not isolate specific exercises of market power or suggest that

the exercise of market power was more important than other explanatory factors.

A. Market Forces: Costs and Scarcity

1. Increased Power Production Costs

As discussed in Section 3, suppliers' costs of generating electricity increased over the summer. 

The primary causes of the increase were rising prices for natural gas and NOx credits. Natural gasfired combustion turbine units are usually the marginal units during peak demand periods, so increased

natural gas prices can have a substantial impact on the market clearing price. In addition, a combinedcycle gas generator typically emits from 1 to 1.5 pounds of NOx per MWh, so increased prices for

emission credits can also affect the market clearing price. Since many of the resources in California are

oil and/or natural gas-fired generation, and prices in California closely correlate to prices in the rest of

the West, increases in the cost of purchasing natural gas or NOx credits in order to generate power

have a significant impact on electricity prices in the West.

Natural gas prices roughly tripled from January 2000 to September 2000 in the West, from less

than $2/MMBtu in January to more than $6/MMBtu in September (see Figure 3-10). At the same

time, the price of NOx credits increased from about $5 per pound to over $40 per pound (see Figure

3-11). As a result, the marginal operating cost of generation needed to meet peak load in California
3Western Systems Coordinating Council, Summary of Estimated Loads and Resources,

May 2000, p. 86.

4PX September report at 13-25.

5-3

rose over the summer. As discussed in Section 3, these input price increases drove up the marginal

operating cost of a combustion turbine from about $70/MWh in May to more than $190/MWh in

August. As a result, market clearing prices that approached the $250/MWh price cap in August may

have reflected the true cost of the resource rather than the exercise of market power.

2. Scarce Resources Throughout the West

It is clear that resources were scarce throughout the West during the summer of 2000. 

Unusually high temperatures and strong economic growth in California, the Northwest and the

Southwest resulted in increased demand for electricity. Lower than expected hydropower output and

increased unplanned plant outages in California contributed to the general scarcity of power to meet

demand. Circumstances in California were exacerbated by increased exports of power from California

to other parts of the West.

This section discusses the factors that contributed to a shortage of power in the West. Even in

a well functioning market, prices can be driven up when costs increase or supplies become scarce. 

The following section discusses whether the exercise of market power could have allowed market

participants to push up prices by withholding supplies from the market. 

The generation shortage began long before the summer of 2000. Growth in demand over time

was not matched by increases in generation capacity. Load outpaced generation capacity additions

throughout the West in the 1990s. Load in the WSCC region increased by an average of around 3

percent per year, while capacity grew less than 1 percent. This trend resulted in a scarcity of supplies

in the region, with the importing areas vulnerable to shortages. California has relied on imports to meet

much of its load.

Reserve Margins

Going into the summer, the WSCC's forecast indicated ample reserve margins for the entire

WSCC (Table 2-5). However, reserve margins for the California/Mexico (California) subregion

(Table 2-6) were slightly lower than those for the total WSCC. The reserve margin for the neighboring

Arizona-New Mexico-Southern Nevada (Arizona) subregion was also tight, with forecasts predicting a

reserve margin of 13.5 to 13.8 percent for most of the summer (June-August).3 While the California

PX Compliance Unit noted that these were unrealistically rosy predictions,4 a close reading of the
5Western Systems Coordinating Council, Assessment of the 2000 Summer Operating

Period, revised May 25, 2000, p. 1.

6PX September report at 16.

7Staff Report to the Federal Energy Regulatory Commission on the Causes of Wholesale

Electric Pricing Abnormalities in the Midwest During June 1998, issued September 22, 1998.

5-4

WSCC forecasts shows that they contained stipulations. The WSCC concluded that projected

regional capacity margins and reliability would be adequate only if normal temperatures prevailed and

normal unplanned generator outages occurred. The forecast stated that, if higher than normal

unplanned generator outages were to occur, and an area experienced significantly higher than normal

temperatures, or the load in multiple areas peaked simultaneously, portions of the region might need to

issue public appeals for customers to reduce their electrical consumption or that other measures might

be necessary. 5 

In particular, the WSCC concluded that the southwest portion of the WSCC (New Mexico,

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

to accommodate a widespread severe heat wave or higher than normal generating outages. The

forecast raised the specific concern that the California subregion was dependent on contracted supplies

that might not be available under emergency conditions. Unfortunately, most of the conditions that

posed problems for the region were in place during the summer of 2000.

 The higher-than-normal planned and unplanned outages during the summer of 2000 illustrate 

the impact of the stipulations on the WSCC reserve forecast. The WSCC forecasted no unavailable

capacity for the California/Mexico subregion in July and August of 2000, with small volumes of

unavailable capacity for May and June of 2000. The same assumptions applied to the Arizona

subregion. Factoring in the actual planned and unplanned outages that occurred in the California

market (see Figure 2-12), and holding the other assumptions equal, the reserve margins in the California

subregion dropped from 26.3 to 17.5 percent for June, from 17.7 to 10.2 percent for July and from

17.4 to 8.98 percent for August. Because the reserve margins were already tight in the Arizona

subregion, a small generator outage could drive reserve margins in that region below 10 percent and

increase the demand for imports. 

 

As the California PX Compliance Unit has indicated,6 a significant change in spot prices can be

expected when reserve margins drop below established reliability standards. Spot prices spike when

reserve margins fall below the 15 to 20 percent range. The connection between reserve margins and

price spikes was also observed in the Midwest in 1998.7 

As noted in Section 2, during May through August of 2000, the Cal-ISO declared 24 Stage

One and 14 Stage Two alerts (see Table 2-10). The Cal-ISO declares Stage One alerts when

operating reserve levels fall below 7 percent and Stage Two alerts when operating reserve levels fall
8PX September report at 15, Figure 3, citing a study by Cambridge Energy Research

Associates, The Summer 2000 Spot Electricity Markets Outlook: Divergent Trends n Price

Volatility, July 2000. 

9PX September report at 19, Figure 5, adapted from information on the NOAA web site.

5-5

below 5 percent. During 1998 and 1999, when prices were significantly lower than the summer of

2000, the Cal-ISO declared only three Stage One and three Stage Two alerts for 1998 and three

Stage One alerts for 1999. The Cal PX has noted a strong correlation between spot prices and low

reserve margins this past summer.8

Unusually High Temperatures

Temperatures throughout the WSCC were higher than normal for the summer of 2000. 

Temperatures in the Arizona subregion were particularly high, averaging 3 to 5 degrees higher than

normal.9 The summer of 2000 was also significantly warmer than the previous two years for California. 

As shown above, in Figure 2-5, western temperatures ranked high relative to other periods over the

last 106 years, and particularly relative to the last two summers. For example, the California/Nevada

region was ranked 99th out of 106 in June of 2000, compared with 59th and 14th in 1999 and 1998,

respectively. Some areas, such as the Southwest, were hot all summer. However, in California high

temperatures were more of a factor in May and June than they were in July and August (see Figure 2-

4).

Increased Demand

Energy consumption and average daily loads during the summer of 2000 grew rapidly

compared with the same period in 1999 (see Figure 2-7). Energy consumption in the WSCC states,

excluding California (see Table 2-8), increased by 4.7 percent in May 2000 versus May 1999 while

energy consumption in California increased by 5.8 percent over the same period. The increase in

energy consumption for June 2000 versus June 1999 was even greater—7.3 percent for the WSCC

states, excluding California, and 13.7 percent for California. Within the ISO, average daily peak loads

grew by 11 percent in May and 13 percent in June compared with those same months of 1999. 

California residential energy consumption increased by 8.3 percent in May 2000 compared with May

1999 and 23.8 percent in June 2000 compared with June 1999. Arizona, New Mexico and Nevada

experienced even larger increases in residential energy consumption with increases of 36.3, 5.0, and

34.8 percent, respectively for May 2000 over the previous year and 22.3, 11.0, and 27.2 percent

respectively for June 2000 over the previous year. These are significant increases in energy

consumption from the previous year which can be directly tied to the higher temperatures across the

region. 
10RDI Powerdat database, September 2000.

5-6

Forecasts of peak loads made day-ahead were also higher than in 1999 (see Figure 2-8),

adding price pressures, even though peak loads ultimately were below peak loads in 1999, primarily as

a result of emergency alerts and demand reduction.

Reduced Imports to California

In the past, California has relied upon large amounts of imports from neighboring systems within

the WSCC to serve load. However, the amount of imports into California for May through August

2000 were less than the levels for the same period in 1999 (see Figure 2-9). Scheduled net imports to

the Cal-ISO fell from an average of 6,294 MW in 1999 to 3,231 MW in 2000; real-time imports from

6,321 MW in 1999 to 4,241 MW in 2000. The trend toward reduced imports was more evident in

July and August than it was in May and June; while real-time May 2000 net import levels were 561

MW below 1999 levels. August 2000 real-time net imports were 3,449 MW below 1999.

The amount of imports available into California were reduced because of shortfalls in hydro

supply during the summer. Hydro generation from outside California was 8.6 percent below 1999

levels in May 2000, and 23.2 percent below 1999 levels in June 2000 (see Table 2-15). 

There appears to be a correlation between the amount of exports and the lowering of the CalISO's buyers cap. When the ISO's buyers cap was lowered from $750/MWh to $500/MWh on July

1, exports rose from 2,995 MW in June to 3,846 MW in July (see Figure 2-10). When the Cal-ISO's

buyers cap was further reduced from $500/MWh to $250/MWh on August 7, the amount of exports

rose to 4,851 MW in August, an increase of 1,005 MW from the previous month. Thus, the capacity

situation in California was tightened by lower supplies entering the state and a large increase in the

amount of in-state generation that was sold out-of-state, possibly as a result of the Cal-ISO's buyers

cap.

Increased Outages

Another factor that contributed to the supply shortage was the amount of generating capacity

that was unavailable because of unplanned outages. In May 2000, outages within the California ISO

were only slightly higher than May 1999, but the problem of outages grew worse throughout the

summer (see Figure 2-12). By August 2000, 3,391 MW of capacity were unavailable because of

unplanned outages compared with 604 in August 1999. California’s steam natural gas plants make up

36 percent of the total capacity and are now quite old: 82 percent of these plants are more than 30

years old.10 As these units are dispatched more frequently due to the shortage of available generating

capacity, they are more susceptible to breakdown. 

Future Resource Additions
11www.energy.ca.gov/sitingcases/projects_since_1979.html

12EOB/CPUC report to the Governor on California's Electricity Options and Challenges at 36.

13Id. at 38.

5-7

The problem with California's oil and natural gas generating plants will not be alleviated quickly

through the addition of new generating resources within the state. According to the California Energy

Commission (CEC), five projects totaling 3,643 MW are expected to be online in 2001-02.11 An

additional 14 projects totaling 8,015 MW are under review by the CEC; however, these projects do

not have an anticipated in-service date. Capacity additions throughout the WSCC also lag in the near

term. Only 1,521 MW of capacity is planned to be on-line during 2000. The capacity situation within

WSCC should improve shortly thereafter when around 23,000 MW of capacity should come on-line

between 2001-2003 (see Table 2-3).

Since California started its electric restructuring program, the amount of new generating

capacity in California has lagged while load has increased. Only 672 MW of net capacity has been

added in California between 1996 through 1999. In the meantime peak load has increased by 5,522

MW over the same period.12 Load growth rapidly outpaced generation additions, reducing important

reserve levels within California.

A major factor in the lack of new generation within California is the complexity of siting

generation within the state. As noted by the EOB/CPUC in their report to the governor, “state siting

procedures in California are complex and create investor risk because of California's commitment to

environmental protection and public participation in the permitting process.”13 The California

Environmental Quality Act (CEQA) and the federal Clean Air Act are two of the principal laws that

determine where power plants are constructed in California. The CEQA requires evaluation and

mitigation of potential power plants before the state allows construction and failure to conduct

environmental review can result in CEQA litigation by citizens or local government agencies that can

delay, change or eliminate a generating project. In addition, Local Air Districts enforce state, federal

and local air quality laws for power plants. The changing California regulatory environment throughout

much of the 1990s also created regulatory uncertainty for investors who chose to wait until clear rules

were established before applying to build new power plants.

The California legislature's attempt to expedite this process through enactment of AB 970 does

little to relieve these difficulties. That legislation gives priority to projects that would have the greatest

efficiencies and the least impacts. Thus, while AB 970 centralizes in the CEC determinations that

would normally be made by numerous state and local agencies, it does not appear to materially change

the substantive provisions governing siting decisions in California.

B. Market Rules
14The Market Surveillance Committee and the ISO's Division of Market Analysis have

reached similar conclusions. See, e.g., An Analysis of the June 2000 Price Spikes in the California

ISO's Energy and Ancillary Services Markets, by Frank A. Wolak, et al., September 6, 2000, pp.

6-11, and Report on California Energy Market Issues and Performance: May-June 2000,

5-8

The market conditions discussed in the previous section contributed to high prices, but their

effects were magnified by the existing market design and some flawed regulatory policies. This section

discusses the rules and regulatory policies that appeared to have a significant contributing role in the

high prices, as well as some that did not appear to be a factor but that have been commonly assumed to

be factors.

Among the factors that appear to have contributed to the recent high electricity prices in

western markets, and California in particular, are rules and policies of the PX and the Cal-ISO, and

statutory requirements and regulations administered by state and local regulatory bodies. For example,

until very recently, SDG&E, SoCal Edison and PG&E were required by CPUC regulations to

purchase and sell all of their electricity through the PX. While the three IOUs now have some

additional authority to purchase outside the PX, their purchases are subject to an after-the-fact

prudence review. These state policies greatly limited the options available to the three IOUs and have

created an impediment to their use of forward contracts. Also, state retail rate policies currently

prevent consumers from seeing and responding to market prices, and they provide weak incentives for

the IOUs to minimize the wholesale cost of electricity once their stranded costs are paid off. In

addition, certain ISO and PX rules appear to have contributed to underscheduling of load and

generation in forward markets, causing operational problems for the ISO and forcing it to procure

energy out-of-market at high prices. These are discussed below.

1. Lack of Forward Contracting

The three IOUs in California were required to purchase their power through the PX with little

or no ability to purchase through forward contracts. Requiring the three IOUs to purchase and sell

through the PX exposed them to the volatility of the spot market without the ability to mitigate the

summer price volatility.

Forward financial contracts for energy potentially can provide IOUs and other load serving

entities with a highly effective hedge against high costs in energy spot markets, while providing both

buyers and sellers with a greater level of price certainty. Moreover, for generators that are otherwise

able to exercise market power in energy spot markets, such contracts can help to mitigate the market

power of the generators that hold them. Thus, forward financial contracts offer the potential to reduce

both the cost impact of price spikes on consumers’ bills, and the incidence and magnitude of the price

spikes that occur.14
California ISO Department of Market Analysis, August 10, 2000, p. 6.

5-9

Properly structured forward contracts can benefit consumers by providing load serving entities

with the ability to lock in a fixed price for a fixed quantity of energy well in advance of the actual

consumption of that energy. This means that a load serving entity need only face spot prices to the

extent that its actual energy purchases differ from its forward market purchases. Indeed, if a load

serving entity's actual purchases match its forward market purchases, it can achieve both a perfect

hedge against high spot prices and the benefit of complete price certainty in the face of spot price

volatility. Of course, holding forward contracts does not guarantee that consumers will incur lower total

energy costs. These costs ultimately will depend on the relative level of prices in the forward and spot

energy markets.

Forward financial contracts also help to mitigate generation market power in energy spot

markets. For example, consider a generator with market power that holds a contract for differences

with a load serving entity. Such a contract requires the generator to compensate the buyer for the

difference between the energy spot price and the contract's strike price when the strike price is lower

than the spot price, and requires the buyer to compensate the generator when the strike price is higher. 

Holding this type of contract reduces the incentive of the generator to raise spot prices because any

increase in spot prices will cause its payments to the buyer to increase (or its receipts from the buyer to

decrease). Thus, to the extent that the majority of its supply portfolio is committed under contracts for

differences, the generator's incentive to exercise market power in the spot market will be reduced or

even eliminated. Similar results can be shown to hold for generators that hold other forms of financial

contracts as well as forward physical contracts. It must be emphasized, however, that forward

contracts serve only to mitigate market power in spot markets; the market power that a generator may

have in forward markets will be unaffected by the forward contracts that it holds. Nevertheless, market

power tends to be found less in forward markets than it is in spot markets, because forward markets

provide energy purchasers with more lead time and therefore more options. Indeed, with sufficient lead

time, the options available to purchasers in the forward market can include the construction of new

generating units.

Until recently, CPUC regulations placed strict limits on the options available to IOUs to enter

into forward contracts. Specifically, prior to August, the CPUC limited the forward contracts available

to PG&E, SoCal Edison and SDG&E to block forward contracts purchased through the PX that

provided for delivery of energy up to 12 months hence. Also, the regulations strictly limited the quantity

of energy that each IOU could obtain through forward contracting. However, since August, actions by

the CPUC and the state legislature have provided the IOUs with an expanded array of PX energy

products and with the authority to enter into long-term bilateral contracts with entities outside the PX. 

Restrictions on forward contract trading levels remain in place as well as after-the-fact prudence

reviews which dampen a purchaser's incentive to buy forward.
15See also, An Analysis of the June 2000 Price Spikes in the California ISO's Energy and

Ancillary Services Markets, by Frank A. Wolak, et al., September 6, 2000, pp. 10-13, and Report

on California Energy Market Issues and Performance: May-June 2000, California ISO

Department of Market Analysis, August 10, 2000, p. 6.

5-10

During and prior to the summer of 2000, the IOUs did not fully utilize even the limited authority

they had to enter into forward contracts. There are perhaps several reasons for this. First, the

standard products available through the PX block forward market may not have met the specific needs

of the IOUs. For example, these products are defined only for a limited set of fixed hourly periods

(peak, super-peak and shoulder-peak) within a given calendar month. Second, because the standard

contracts did not provide a full range of hedging features, they may not have offered the level of

insurance against price spikes that the IOUs sought. Third, the prices for the block forward contracts

may have appeared high relative to the IOUs' forecasts of spot prices for the summer of 2000. Indeed,

by the time the IOUs received authority to increase their forward market trading levels, forward market

prices had already increased, probably in response to the early spot market price spikes. Finally, the

IOUs may have feared that the CPUC would declare their forward market purchases to be imprudent

if spot prices turned out to be lower. In addition, because SDG&E was allowed to easily pass through

to retail customers its energy and ancillary services costs, it may not have had a strong incentive to

aggressively pursue cost reductions through forward contracting.

The restrictions on the ability of the IOUs to enter into forward contracts have denied the IOUs

the opportunity to adequately insure themselves against high energy spot prices. Also, because forward

contracts can help to mitigate generation market power in energy spot markets, price spikes during the

summer of 2000 have probably been larger and more frequent than they otherwise would have been if

the level of forward contracting had been higher.

2. Demand Responsiveness

In well functioning competitive markets, both suppliers and consumers are able to see and

respond to market prices. Indeed, this is what allows competitive markets to achieve the efficient

outcomes for which they are well noted. However, in electricity markets, such as those of California,

consumers often must make their consumption decisions without knowledge of the true market price of

electricity. In addition, some utility purchasers of electricity, such as SDG&E, may not always have

strong incentives to minimize the wholesale cost of the electricity that they purchase for their retail

customers. This lack of demand responsiveness can, at times, lead to excessively high prices.15 It can

also have important implications for the Commission's regulation of wholesale power markets.

To be effective, prices must accurately reflect the cost of supplying electricity at a given time

and place, and they must be communicated to consumers in a timely manner. In California, for

example, retail customers generally are not provided with accurate and timely price signals. This is due
5-11

in part to the retail rate freeze that was applied to the IOUs as part of the statewide restructuring. The

retail rates of PG&E, SoCal Edison and SDG&E were frozen at the time of restructuring to ensure that

retail customers would not pay rates that exceeded the rates paid before deregulation. The rate freeze

was designed to operate in conjunction with the recovery of the utilities' stranded costs. Specifically,

AB 1890 provided for recovery of stranded costs through a Competition Transition Charge (CTC). 

The CTC surcharge cannot, in conjunction with PX market prices, exceed the rate freeze levels. This

means that, to the extent that PX prices are high, CTC recovery is slower. Consequently, if customers

reduce their demands, their rates do not fall; the utilities simply recover their stranded costs at a faster

rate. Both the CTC and the rate freeze are limited in duration to the earlier of March 31, 2002, or until

stranded costs are fully recovered for each IOU. 

SDG&E completed its recovery of stranded costs in 1999 and the CPUC lifted its rate freeze

in July 1999. With the end of the rate freeze, SDG&E was allowed to pass on its wholesale costs of

power directly to its customers. Consequently, SDG&E customers felt the full impact of the wholesale

price increases that were experienced in the summer of 2000, when their electricity bills more than

doubled. However, because these customers did not see the rate impacts until they received their bills,

they had no practical way to respond in the short term to the high prices. Also, without time-of-use

metering, they were unable to reduce their bills by moving consumption to off-peak periods. 

Furthermore, SDG&E itself may have had little incentive to minimize its purchased power costs given

that it could simply pass through the costs to ratepayers, subject only to the possibility of a prudence

review by the CPUC.

By contrast, PG&E and SoCal Edison have not completed their stranded cost recovery and

therefore remain subject to the retail rate freeze. Consequently, these utilities' customers were fully

insulated from the price increases of the summer of 2000, and clearly had no incentive to modify their

consumption patterns in response to the increased costs. However, because PG&E and SoCal Edison

were unable to pass through the increased wholesale costs to their customers, they likely had a much

stronger incentive than SDG&E to minimize these costs, because any cost savings realized can be

applied as an offset to their CTC costs. However, neither of these companies had much ability to

minimize their costs because they were largely required to buy in the spot market.

It should be noted that available evidence suggests that customers that had direct access to

wholesale markets this summer did indeed change their consumption patterns in response to the price

increases. Based on discussions during this investigation, there is evidence to suggest that some load

reduced purchases during peak periods and increased purchases off peak.

The fundamental problem created by unresponsive demand is that, during periods of tight

supply, prices can rise far above competitive levels. The reason is as follows. In a competitive market,

if demand is low relative to the available generating capacity (such as during off-peak periods), the

market clearing price will approximate the marginal running cost of the most costly generator operating. 

This is true even when demand is unresponsive to price, as long as the market includes many owners of

generation competing to serve the limited demand, and none of these generators has locational market
16The PX price “cap” is actually a practical limit imposed by the market software

requirements, not a regulatory restriction on bidding or pricing.

17San Diego Gas & Electric Company, et. al., 92 FERC ¶ 61,172 (2000).

5-12

power. However, these same generation owners will discover that they have considerable market

power when demand is both unresponsive to price and at such a high level as to require the ISO to

place virtually all available generating capacity in operation or on reserve in order to meet demand

reliably. 

This is not to say that competitive prices should never rise above the marginal running cost of

generation. When supply is scarce relative to demand, competitive prices will rise to a level that reflects

the value that the marginal consumer places on additional consumption. This additional increment

above marginal running cost is referred to as the “scarcity rent.” However, market prices in electricity

markets like those in California cannot be expected to settle at this level if retail consumers do not have

the ability to see these prices and to make known to the market, through their purchasing decisions, the

value that they place on marginal consumption. Indeed, in the absence of demand responsiveness,

prices in California and in markets elsewhere frequently rise well above this competitive level at times

when demand is high and capacity is scarce.

The only alternative facing a system operator in the absence of demand response may be to

ration demand through administrative load reductions. This is exactly what happened in California last

summer, when a total of 38 emergency alerts were called. These administrative procedures succeeded

in reducing demand without curtailment of firm load, which suggests that load does indeed have the

ability to reduce its consumption. But it does appear difficult to convert these reductions from an

administrative basis to a market one. Under the reliability rules, interruptible load cannot be required to

reduce its consumption except under emergency conditions. Thus, as long as firm load is maintained,

load may have only limited incentives for price-based reduction of consumption. It appears difficult to

develop a large amount of demand response, but the reasons appear to be institutional more than

physical.

3. Underscheduling

At present, the PX has a $2,500/MWh price cap16 and the Cal-ISO has caps of $250/MWh

for energy and ancillary services and $100/MWh for replacement reserves. The PX's higher energy

price cap has not limited energy prices in the PX. Instead, as noted in the San Diego order, the ISO's

cap has effectively limited the price of generation sales in the PX day-ahead and hour-ahead energy

markets.17 Buyers never offer to pay more in the PX market than the ISO's maximum purchase price,

since they may still buy at the ISO's cap in the real-time market if their bids are not accepted in the PX. 
18 PX September report at 44.

19See, AES Redondo Beach, L.L.C., et al., 87 FERC ¶ 61,208, (May 26, 1999)

5-13

Specifically, the net cost to load to buy in the ISO's real time energy market cannot currently exceed

$350/MWh (i.e., $250 for energy and $100 for replacement reserves). Thus, loads will not offer to

pay more than $350/MWh for energy in the PX's forward market, and the PX energy price will not

exceed that level. These restrictions on price helped create incentives for both buyers and sellers to

underschedule load and supply in the day-ahead market.

The amount of underscheduling has tended to increase substantially during high demand

periods. A major reason appears to be that the amount of supply offered into the PX markets during

high demand periods is often substantially less than forecasted demand. Data presented in Section 2

indicate that the day-ahead schedules in the PX consistently fell below forecast loads whenever loads

were above 35,000 MW, and that the load level where this occurred decreased in July and August. 

Information in Section 3 shows that the proportion of supply below $100 in the PX was reduced

through the summer as the price cap was reduced. The total amount of supply offered in the PX does

not appear to change much over the summer. The California PX states that little additional supply has

been offered into the PX Day-Ahead market at any price above $100/MWh, especially when the

ISO's load forecast exceeds 35,000 MWh. For example, on July 31, 2000, in hour 16, total supply

offered into the PX day-ahead market at any price was less than 35,000 MWh, while the ISO's load

forecast was over 45,000 MWh.18

As a result, load and generation underschedule in the PX's forward markets and then appear in

the ISO's real-time market. Extensive underscheduling creates operational and reliability problems for

the Cal-ISO, and has required it to procure energy out-of-market at high prices. 

 In an attempt to address the operational problems and reduce the incentives for

underscheduling, the ISO modified its practices for procuring replacement reserves in May 1999. 

Specifically, the ISO now procures a day in advance enough replacement reserves to match its estimate

of underscheduled load—that is, the difference between its own forecast of real time load and the

amount of energy scheduled in the forward markets. The ISO says that procuring additional

replacement reserves increases the likelihood that sufficient generation will be available to reliably meet

the load that shows up in real time. As an incentive to discourage underscheduling, the ISO charges the

costs of the replacement reserves to unscheduled load that shows up in real time and to scheduled

generation that fails to produce in real time.19

However, the modified replacement reserves policy has not reduced the amount of

underscheduling. Indeed, underscheduling has increased, especially during high demand periods. For
20Report on California Energy Market Issues and Performance: May-June 2000,

California ISO Department of Market Analysis, August 10, 2000, p. 26.

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example, in June as much as 21 percent of real time load was not scheduled in advance.20 A major

reason for this phenomenon is that the policy creates conflicting incentives. On the one hand, the policy

does discourage buyers from underscheduling, by charging the costs of replacement reserves to

unscheduled load. However, the policy also encourages generators not to offer energy in the forward

market (especially during periods of high demand), but instead to sell their capacity as replacement

reserves. That is because by doing so, the generator can receive a payment for replacement reserves in

addition to a payment for selling energy in real time. (During periods of high demand, generators

selected to provide replacement reserves are likely to be called on in real time to produce energy. The

policy encourages generators to bid less into the PX as load increases, by increasing the probability that

all replacement reserves will be used for energy and hence the expected opportunity cost of not

deferring supply until the hour-ahead or real time markets.)

As noted by the MSC, because the ISO requires all forward schedules to be balanced, load

and generation are equally underscheduled. Underscheduling arises largely because loads and

generators disagree about the appropriate forward price of energy. In effect, underscheduling occurs

because loads are trying to protect themselves from higher prices in the forward market, while

generators are trying to protect themselves from lower prices in the forward market.

Clearly, substantial underscheduling creates operational and reliability problems for the ISO as

the grid operator. The effect of underscheduling on energy prices, however, is less clear. On the one

hand, the ISO has incurred costs to procure replacement reserves and to make out-of-market

purchases at high prices in response to underscheduling. On the other hand, attempts by load to reduce

underscheduling by procuring more energy in the forward markets would likely put upward pressure on

forward market prices. In sum, underscheduling had no clear impact on this summer’s prices.

4. Exports/Imports

Exports increased through the summer along with reductions in the price cap, but there are

many possible reasons why this might have occurred, including prior commitments by generators,

increased opportunities in the Southwest where weather remained extremely hot, reductions in the

overall WSCC level of hydro generation, and off peak pumping requirements for hydro. These exports

have the effect of reducing the supply of in-state generation and limiting the amount of such generation

bid into the PX. In the summer of 2000, these increases in exports were not compensated by increases

in imports, and the net imports into California were reduced. 

Several concerns have been raised about the reduction in net imports. The first concern is one

of reliability, because the reduction in scheduled imports contributed significantly to the problem of
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underscheduling. The ISO needed to purchase additional imports for real time, either through

replacement reserves or out-of-market purchases at the last minute, contributing to the high incidence of

emergency alerts and concerns of maintaining the reliability of the system.

The second concern is that generators exporting power were gaming the system in order to

increase prices. By selling to entities outside California, who may be the same entities who supply

imported power in real time, the increased exports decrease supply in day ahead and hourly energy

markets and increase prices. Supply then becomes available in replacement reserve markets at the

ISO, or as out-of-market purchases in emergencies. Out of market purchases were not large (less than

1 percent of energy costs), but replacement reserve purchases were very high on certain days in the

summer (see Section 3). In one sense, this is not gaming, since there are no administrative rules on the

amount of capacity that must be provided to meet load as there are in the eastern ISOs. Loads are

required to bid into the PX, but there is no capacity penalty imposed if corresponding supply does not

bid into the PX. The concern seems to be that megawatts are exported to the very same entities who

then sell the megawatts back in real time at high prices. Several generators reported contracting a

significant proportion of their supply forward outside of California, and the buyers of that power may

have exported it back to California at some later date. One marketer, who is reported to have

contracted for power from California generators at attractive prices before the summer, exported

power back as replacement reserves at high prices during emergency conditions in California.

These exporting practices are permitted under the rules and are not necessarily a market power

problem. It may simply be the normal working of a market where sellers are maximizing profits in a

competitive market, where sellers or buyers see an opportunity at one time, take an option, and

exercise it at a later date. It becomes a problem if it is associated with a pattern of withholding

resources from the market in order to drive up prices. For example, if a large seller outside California

were able to influence the price of power in the West by acquiring power from California, withholding

power from the market at a critical time, and selling the power back to California. As such, it is part of

the overall issue of market power and scarcity in the West, discussed in the next section.

5. Auction Rules

Currently, the Cal-ISO and the PX use a single-price rule for establishing real time energy

prices. That is, the market-clearing price (which is based on the highest accepted bid) is paid to all

accepted sellers, including those who bid less than the price. To prevent future price spikes, some have

proposed an alternative pricing rule—paying each accepted seller its bid, rather than the marketclearing price. Buyers would then pay a price reflecting the average of the accepted sellers' bids. 

Proponents of the pay-as-bid rule argue that consumers would pay less in total during high demand

periods, on the grounds that consumers would pay less than the highest accepted bid to suppliers who

bid less. However, generators are not likely to bid under a pay-as-bid rule in the same way as under

the single-price rule. Sellers bidding below the market-clearing price will receive that price under the

single-price rule, but they will receive only their bid under the pay-as-bid rule. So generators will
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generally submit higher bids under a pay-as-bid rule. In sum, it is not clear whether a pay-as-bid rule

would have the effect of lowering consumers' bills.

C. Market Power

The previous sections have discussed the factors that contributed to an electricity shortage this

summer and the effects of problems with market rules. This section discusses the issue of market

power in the context of scarcity and considers whether the apparent shortage arose because of

withholding and hence whether the high prices in the West were the result of the exercise of market

power. Market power is the ability of a seller to influence market outcomes, especially the market

price for a sustained period. Sellers exercising market power use this ability to raise the market price

above competitive levels, either by physically withholding some of their capacity from the market, or by

offering their capacity at prices above competitive levels. During periods of supply scarcity, the market

price naturally rises and even firms with relatively small market shares may possess significant market

power. However, as the supply becomes more scarce, it becomes more difficult to isolate the effects

of scarcity and market power on the market price. 

Market power, like scarcity, is a matter of degree. It is important to recognize that, in practice,

the issue of market power is not a simple, all-or-none question, but turns on the magnitude of the

market power impact on price and its consequences. In times of scarcity, this impact is potentially very

large, but it may be very difficult to separate from scarcity effects that can also be large and the duration

of the impact of market power may be relatively short-lived. 

Significant market power abuses that violate market rules need to be dealt with directly, but

market power in a newly developing market may be magnified by flaws in market rules. The best

approach in these cases may be to change the rules in order to mitigate the impact of market power

exercise. Mitigation in the form of rule changes may be appropriate even in the absence of findings of

market power exercise by specific sellers or buyers, if there are clear incentives for its exercise, and

there are potentially large impacts that cannot be adequately separated from the effects of scarcity.

 

As discussed below, there is evidence suggesting that sellers had the potential to exercise

market power during this past summer. However, the evidence available and analyzed during this

investigation, to evaluate whether there were actual exercises of market power, is inconclusive. A

considerable amount of data on individual bidding patterns and individual plant performance was

obtained and reviewed in the course of this investigation, but was not sufficient to make determinations

regarding exercises of market power by individual sellers. Further study of high-priced bidding by

individual firms or periods when individual generators were not running would be needed to substantiate

any charges of market power abuse.

1. Measuring the Effects of Market Power on Price
21The monthly market power index is the percentage increase in monthly wholesale energy

revenues relative to monthly revenues under the perfectly competitive benchmark. MSC Report on

June 2000 Price Spikes, September 6, 2000, p. 17. 

5-17

During periods of high demand and tight capacity, prices would ordinarily rise as a result of

basic competitive market forces and real scarcity. However, conditions of tight capacity can often

create market power, especially when demand is insensitive to price. When demand is inelastic and

approaches capacity, a seller with a relatively small amount of capacity can often begin to influence the

market price. It can sell most (if not all) of its output even if it asks for a price higher than what other

sellers are asking. The seller may lose some sales by asking a higher price, but these lost sales revenues

are more than made up by the higher prices on the output it produces. Thus, while the combination of

high demand and tight capacity would ordinarily cause prices to rise due to competitive market forces,

they may also create market power that causes prices to rise even higher. From a public policy

perspective, the desirable outcome is a competitive price increase, not the higher price increase caused

by the exercise of market power.

When market power is exercised, the market clearing price exceeds the price that would have

been set under competitive conditions. It is important to note that a generator's true marginal cost is the

generator's opportunity cost of selling into a particular market. That is, the next highest value of the

resource. If the running cost of a unit is $40 per MWh, but that unit is physically able to sell into a

market in which the price would be $80 per MWh if that generator participated in that market, then the

opportunity cost of selling into another market is $80 per MWh. As long as the generator bids its true

opportunity cost into a market, it will never receive less than the true value of its output.

In order to estimate the degree to which market power is being exercised, the supply curve for

a particular hour would have to be reconstructed replacing the bids received with the marginal cost of

each bidding generator. The effect of market power on the price would be the difference between the

actual market clearing price and what the market clearing price would have been if all the generators

had bid their true marginal cost. The Market Surveillance Committee (MSC) of the California ISO has

performed such an analysis. The MSC estimated a significant degree of market power being exercised

in California markets for the period October 1, 1999, to June 30, 2000. They estimated that prices for

non-must-take energy over the entire period were 36.3 percent higher than they would have been

under competitive conditions. For the last month of the sample, June 2000, they estimated that prices

were 64.6 percent higher than they would have been under competitive conditions. The highest

previous monthly market power index was in June 1998, when prices were estimated to be 39.9

percent higher than they would have been under competitive conditions.21 These findings certainly

suggest that market power was exercised in June by the standard of short run marginal costs. Average

prices in August were higher than June. However, as discussed in Section 3, costs were also much

higher, so it is unclear whether, or to what extent, market power appears to be a continuing concern. 

The MSC has not yet completed an analysis for July and August.
22For example, a measure of market power in a monopoly, the price-cost margin or Lerner

Index ((Price - Marginal Cost)/Price) is equal to -1/elasticity of demand. 

23In fact, during a period of true scarcity, when demand exceeds supply even the unit setting

the market-clearing price will receive a profit, or scarcity rent, since the price will naturally increase in

order to equate supply and demand.

24Especially in a market with little demand elasticity.

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2. Demand Conditions

The degree to which the market price will exceed the marginal cost of production depends not

only on the supply-side factors discussed above, but also on the demand responsiveness. For any

given concentration level, the less responsive (elastic) the demand the more the market price can be

raised above marginal cost.22 Thus the less elastic the demand, the greater the cost to consumers of an

exercise of market power. In California, as in other states, demand changes from hour to hour, but not

typically in response to hourly prices. Nevertheless, it is clear that demand can respond to conditions,

as the difference between peak forecasts and actual loads (see Section 3) suggests. During emergency

periods, interruptible customers have their demand reduced and voluntary reductions do occur in

measurable amounts, in response to ISO interruptions of loads and public appeals for conservation. 

The difficulty is that the demand response is driven by administrative directive, not by market prices.

3. Market Power and Scarcity

In both the PX and ISO, all generators supplying energy receive the market-clearing price,

which is the highest accepted bid to supply energy. During periods of scarce supply, the marketclearing price will greatly exceed the marginal running costs of most of the generators supplying

energy.23 Those generators with low running costs will receive a significant profit from the output of

their units. The high price then serves as a signal to potential entrants that there are profits to be made. 

High prices during periods of supply scarcity are a normal feature of a properly-functioning market.24 

It is difficult to separate scarcity from market power. As stated above, during periods when

electricity becomes more scarce, the price naturally increases. However, during those same periods the

ability and incentive to exercise market power increases. The ability to exercise market power (raise

price) increases because the market is clearing in the steep (inelastic) portion of the supply curve, thus a

slight reduction in output will significantly increase the market-clearing price. The incentive to exercise

market power increases because the payoff becomes much higher. Any generator whose bid is

accepted will receive the higher market-clearing price for all the energy it provides for that hour. 
25Department of Market Analysis, California ISO. Report on California Energy Market

Issues and Performance: May - June, 2000, p. 51.

26The total cost includes both capacity and energy payments, since many of the units that

provide energy also provide reserve capacity.

27Department of Market Analysis, California ISO. Report on California Energy Market

Issues and Performance: May - June, 2000, p. 51.

28 Eric Hildebrandt, Market Analysis Report, California ISO Department of Market Analysis,

September 2000.

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For an example of true scarcity, the California ISO DMA reports that during June 2000, there

were 27 hours when the available supply within the ISO was less than the system demand.25 For those

hours, the average cost of procuring real-time energy was $709/MWh.26 During a period of true

scarcity, any firm that can sell energy into the ISO real-time market has market power. 

In addition, during June 2000 there were 106 hours when the available supply was between

100 percent and 110 percent of the system demand. For those hours the average cost of procuring

real-time energy was $324 per MWh.27 Even considering the increase in marginal cost of operating

gas-fired generators in Southern California, a price of $324 per MWh exceeds estimates of the

marginal cost of the last unit supplying energy. In June, the highest marginal operating cost was about

$160/MWh.28 As noted in Section 3 of this report, it was not until August and September that the

combination of high natural gas and NOx credit prices pushed the running cost of gas turbine units near

that level.

4. Methods of Exercising Market Power

A generator could exercise market power through either economic or physical withholding. In

the case of economic withholding, a generator would submit bids in excess of its opportunity cost in

order to raise the market clearing price. In the case of physical withholding, the generator would not

supply all of its available energy in order to increase the market-clearing price. In that case, by

withholding lower cost output, higher cost units whose bids would not otherwise have been accepted

would set the market clearing price. All suppliers whose bids were accepted would then receive the

inflated market-clearing price. As long as the gain from the higher price exceeded the lost profits from

the foregone output, withholding output would be a profitable strategy. 

However, as noted earlier, determining physical withholding from real unit outages that occur

during periods of high demand is difficult. This determination is made particularly difficult in the western

environment by the presence of hydropower, must take contracts, and severe environmental

compliance limitations. In each of these categories, it is difficult to determine the relevant capacity,
5-20

since the amount of energy the facility can produce is limited by various factors, not by the physical

capacity of the unit. From conversations with the ISO staff, we have learned that hydro facilities and

must take contracts are treated on an “as bid” basis, so that the amount of energy bid is taken as the

indicator of the power available from the unit in any given hour. These facilities will often appear

underutilized and much of the capacity will appear available when measured against the total physical

capability of the unit. 

Because of the difficulty in assessing a firm's true opportunity cost of selling into a market,

economic withholding is even more difficult to assess than physical withholding. Generators are

maximizing the profits from a portfolio of generation units. There are many markets into which they can

sell. They face environmental, reliability, technical and regulatory constraints. For example, generation

units have different start-up costs and ramp rates. Since the bids the units submit to the PX and ISO

(through their scheduling coordinator) are composed of capacity and energy but not other costs such as

startup, they cannot bid their full set of cost components, so they may “average” some of the costs

associated with ramping their units up or down into their bids. It is not clear what constitutes a

reasonable averaging and what does not. 

A generator that is producing less than its capability during a period when the price is greater

than its opportunity cost would appear to be engaging in physical withholding. It is not always clear,

however, what separates withholding output in order to raise price from withholding output due to

environmental, reliability, technical or regulatory constraints. For example, for a unit that is slow to

ramp down, the optimal running plan may be to begin to reduce output (withhold) earlier in the day than

for a unit that can be quickly ramped down. For another example, a unit may only be able to run for a

fixed number of hours during the summer due to environmental constraints. What appears to be

withholding (not running the unit when the market price exceeds the marginal running cost) may be

simply the result of the generator trying to maximize the value of the unit's output for those hours it can

run.

5. Evidence from Summer of 2000

One method of withholding output would be to call an unplanned plant outage. An increase in

unplanned outages shortly before or during price spikes would be an indicator of physical withholding. 

As noted in Section 2.3, the amount of capacity unavailable due to unplanned outages was 2,787 MW

greater in August 2000 than it had been in August 1999. Given the significant cost increase of the

marginal units and their associated bid price increase, the absence of 2,787 MW significantly increased

the market-clearing price. Higher prices are to be expected during a period with significant capacity

unavailable due to outages; they are the result of an inward shift of the supply curve at the time of the

outage. As shown in Table 2-14, however, the strongest correlation was between outages (unplanned

and planned) and the next day's price rather than the price in the day of the outages. The outages

would then be lower on the day of the high prices, than they were on the previous day. High prices in

the periods after a significant amount of capacity becomes unavailable would indicate a market reaction
29 Specific examples of this practice have been noted in the England and Wales pool by

several observers. For example, see David Newbury, Power Markets and Markets for Power, and

Frank Wolak and Robert Patrick, England and Wales Electricity Market, February 1997.

30California Power Exchange Corporation Compliance Unit. Price Movements in California

Electricity Markets, Analysis of Price Activity: May-July 2000. September 29, 2000, pp. 59-61.

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beyond the direct effect on the supply. While the reaction could be a competitive attempt to reduce

outages in anticipation of tight conditions, it is also consistent with an attempt to exercise market power

by driving up prices for the next day and then making the unit available in time to receive those high

prices.29

If attention is focused on the thermal units that have the greatest ability to respond to price, data

from the control areas in the WSCC seem to show that only 5 to 7 percent of the non-hydro generation

resources went unused at peak times. This suggests that the magnitude of any physical withholding of

available capacity was not large for these units. 

Firms could also exercise market power through the bids they submit to the ISO and PX. As

described in Section 3, the bid curves offered in the PX change their shape through the summer as the

price cap lowers. The proportion of bids under $100 decreased during the summer, so that firms were

changing their bidding behavior and increased the price at which they would offer any given amount of

supply. However, the change in behavior was exhibited by all categories of participants, so it is as likely

to be a response to increased costs as it is to be intentional behavior by any individual firms or groups

of firms to raise the lowest price offered to compensate for reduction in the price cap.

As noted by the above, the price responsiveness (elasticity) of supply significantly influences the

effectiveness of either type of withholding. If the market supply is highly responsive to changes in price,

then any attempt at economic or physical withholding will not be effective, since there will be significant

supply at the margin to respond without causing a significant increase in price. An indicator of an

effective economic or physical withholding strategy would be if those units that consistently set the

market-clearing price were able to decrease the supply elasticity through their bidding behavior. The

PX Compliance Unit estimated that the average supply elasticity of the units clearing the market for

those hours in May through July 2000 when the market-clearing price exceeded $100 per MWh was

actually 24 times greater than the overall supply elasticity.30 As a result, the entry of supply at high

prices may have increased the elasticity of supply in these ranges, making the exercise of market power

more difficult over these load ranges that it otherwise would have been. Staff was able to observe this

phenomenon in the individual participant bidding curves. Some bidders bid consistently at high levels,

submitting bids that varied even though the average price bid was high. Other bidders submitted bid

curves that included a large amount of supply at low prices and only a very small amount at high prices,

making the bid curve very steep for a small proportion of their submitted supply. Bidders in the former

category will tend to make high-priced supply more elastic. However, they also have the effect of
5-22

shifting total supply upward, so they will also tend to raise the price at lower load levels compared to

bidders who submit only a small proportion of supply at high prices.

6. Market Power in Context

It is important to evaluate the impact of market power in the context of two conditions

discussed in the earlier sections: scarcity and market rules. In the short term, when supply becomes

very tight and demand is unable to respond, the price discipline of a normal competitive market is

greatly diminished. The effects of scarcity and market power in these circumstances are very similar:

high prices, a seller's market with few or no restraints on sellers, and few or no options for buyers. In

an ideal world with no market power, these prices would signal scarcity and the market would correct

itself. But the past summer in the West was not an ideal world. Buyers had essentially no short-term

options and few longer-term, forward ones. Without better forward markets, even true scarcity signals

would not get effectively conveyed until close to real time, leaving little room for the development of a

more stable overall market. 

Market power can compound the effect of scarcity, because it will distort normal market

signals. Sellers have the incentive to raise prices to inelastic buyers when supplies are anticipated to be

tight, and the result can be prices above competitive levels that appear sooner than they would in a

workably competitive market where prices are set by short-term marginal opportunity costs. 

Frequently, these prices may be the work of a competitive market. However, at least some of the June

price spikes appear to be attributable to market power, and high bids observed in PX and replacement

reserve markets during this investigation provide further indications that above marginal cost bids can be

sustainable. 

Market rules can provide some substitute discipline if normal market processes break down, at

the risk of distorting genuine market signals. But markets designed with overly complex rules and

decision procedures can make matters worse, if they give sellers misplaced incentives and the means to

act on them. For example, rules that provide incentives to shift supplies from the day-ahead spot

market to even shorter-term hourly or real time markets can adversely affect the ability of the ISO to

manage the market reliably in real time. Although the price impact of such shifts is uncertain, the effect

is to move supply to a market where demand is even less responsive than in the day-ahead market,

restricting buyer options and potentially increases any market power the seller may possess. Without

prospects of greater demand response in close to real time, these types of problems may be very

difficult to manage through purely market incentives, and non-market rules may be needed.

If higher than competitive prices are sustained for a long enough period of time, price restraints,

capacity requirements, rules requiring greater forward contracting, or some other market intervention

may be needed. However, policy makers need to factor in increases in input costs, unavoidable

limitations on siting generation and transmission costs and other true costs or limitations in crafting

workable market rules that assist market development rather than impeding it.
5-23

D. Conclusion

As noted at the beginning of this section, competitive forces, flawed market rules and, to some

extent, market power contributed to the unusually high prices the past summer. These results seem to

suggest that some change in market rules is required. Additionally, some further steps during a

“transition” period to 2002, when new capacity will be available, may also be necessary. Options to

address these conclusions are provided in the following section.