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Market Oversight | Reports & Analyses | Electric Power Market Summary 1

Electric Power Market Summary

SUMMER 2006

FEDERAL ENERGY REGULATORY COMMISSION @ FERC.GOV

NORTHWEST CALIFORNIA SOUTHWEST MIDWEST SPP

TEXAS PJM SOUTHEAST NEW YORK NEW ENGLAND

Peak electrical demands in summer 2006 were much higher in almost all regions of the United States than in summer 2005. 

Every regional transmission operator (RTO), and most other regions, 

set demand records. The bulk power grid and wholesale power 

markets performed well under the stress.

Ten percent more electricity was produced by natural gas-fired 

generators in summer 2006 than in summer 2005. Lower-priced gas, 

newly installed gas-fired generators, and more expensive fuel oil all 

contributed to this trend.
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ELECTRIC POWER MARKET SUMMARY

SUMMER 2006

Despite spells of record-breaking heat, U.S. consumption of electricity 

in summer 2006 grew only one percent from the previous summer. Milder 

weather in parts of June and August reduced consumption in most major 

power-consuming regions except in the West.

Unprecedented generation availability and robust demand response1

helped grid operators maintain reliability during peak periods, but in almost 

every area they still needed emergency actions such as warnings, public 

conservation, emergency transactions, and curtailment of interruptible 

loads. Even areas considered vulnerable—southern California, southwest 

Connecticut, Long Island, and Ontario— had no load shedding2 or serious 

market problems.

Compared to summer 2005, average wholesale prices for electricity 

declined in the Northeast and Midwest and rose in PJM (Mid Atlantic and 

portions of the Midwest) and California. Throughout summer 2006 prices 

were moderated by lower natural gas prices, greater supplies of nuclear and 

hydropower, and occasional moderate weather. During hot weather, prices 

rose to reflect the use of more-expensive generators and, during extreme 

peak loads, scarcity, though the price levels and scarcity mechanisms varied 

by region.

Peak Demands Much Higher in 2006

Peak electrical demands3 in summer 2006 were much higher in almost 

all regions of the United States and many demand records set in summer 

2005 were broken. The California Independent System Operator 

(CAISO), PJM and the Midwest ISO (MISO) saw substantial growth in 

peak demand. All RTOs, and most other regions, exceeded their historic 

peak demand. Growth of peak demand is significant because it stresses 

both the grid and the markets. In summer 2006, both functioned without 

significant disruptions.

1 Changes in electric usage by end-use customers in response to price changes or incentive 

payments. For a complete definition see Assessment of Demand Response and Advanced 

Metering ( FERC Staff Report, August 2006.)

2 “Load shedding” means disconnecting consumers from the grid, usually to prevent demand 

from exceeding supply, causing widespread grid collapse; “rolling blackout” is synonomous. 

“Blackouts” are failures of the grid to provide power for any reason. In this report the terms 

mean failure of the bulk power system, not the failure of local distribution systems or the 

disconnection of consumers, such as interruptible customers, whose contracts or terms of 

service allow for such disconnection.

3 Peak demand is a region’s highest hourly power demand during the summer. Average 

demand is the average of all hourly demands in a region during the summer. The terms “demand” and “load” are used interchangeably in this document to mean system power averaged 

over an hour.
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ELECTRIC POWER MARKET SUMMARY

SUMMER 2006

Monthly peak demand records also were widely broken, especially in 

May 2006. Pre-summer hot weather can be troublesome if generation 

supplies have not yet fully returned from spring maintenance: ERCOT had 

a two-hour rolling blackout in April 2006 and the New York Independent 

System Operator (NYISO) had an April heat problem in a prior year. 

But in May 2006 the heat occurred at the end of the month, when most 

generation was available. Nevertheless, NYISO experienced large real-time 

price excursions when unusual congestion combined with thunderstorm 

reliability procedures to slow its real-time software, leading to drastic 

schedule changes with neighboring PJM and Ontario. 

Large Increase in Natural Gas-Fired Generation

Gas-fired power generation rose 10 percent in summer 2006 over 

summer 2005 (see charts Net Generation by Energy Source and Change in 

Net Generation Output by Source.) The Western Electricity Coordinating 

Council (WECC) and Florida Reliability Coordinating Council (FRCC) 

regions, both strongly gas-dependent, had the largest increases in gas 

consumption for power generation, according to estimates by consultant 

Bentek Energy LLC. Several factors contributed to the increase. Natural 

gas was 10 to 20 percent cheaper, depending on location, in summer 2006 

compared to summer 2005. High peak demands required greater use of 

the least-efficient generators, including gas-fired combustion turbines. 
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ELECTRIC POWER MARKET SUMMARY

SUMMER 2006

Nationwide, about 20.2 gigawatts (GW) of new gas-fired generating 

capacity was added since summer 2005, out of a total addition of 22.6 

GW. 

Output also increased from hydropower, nuclear and renewable 

generators, while coal-fired output was almost unchanged. Power generation 

from oil fell sharply. Fuel oil prices were higher than natural gas prices in 

summer 2006, while in summer 2005 oil had been cheaper than gas.

Electrical Consumption Grew Modestly

In summer 2006, despite record-breaking heat waves and the secondwarmest4 summer on record, U.S. consumption of electricity grew only one 4 National Climatic Data Center, Report on Climate of 2006- August in Historical Perspective 

including Boreal Summer, September 14, 2006.
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ELECTRIC POWER MARKET SUMMARY

SUMMER 2006

percent from the previous summer. Milder weather in June and August 

reduced consumption in most of the major power-consuming regions 

outside the West.

Western cities needed more cooling in 2006 than in 2005, but many 

eastern cities needed less. This diversity in cooling requirements also limited 

U.S. electricity consumption growth. The following figures show average 

cooling requirements measured in cooling degree days5 for both summers.

 

Bulk Power System Performed Well Under Stress

The U.S. bulk power system performed well in the face of very high 

demand. There were no instances of involuntary load-shedding (blackouts.) 

In the West, the 11-day heat wave broke demand records not only during 

peak hours but during weekend days as well, raising concerns that operators 

would be unable to schedule needed maintenance for generators. But 

suppliers and system operators seemed well-prepared: generators on average 

were available a larger fraction of the time in California, for example, than 

5 A cooling degree day is a measure of demand for air conditioning. The positive difference between the daily mean temperature and 65°F is the number of cooling degree 

days for that date.
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ELECTRIC POWER MARKET SUMMARY

SUMMER 2006

in any previous summer, and the transmission system, critical in importdependent California, also performed well. 

Consumers contributed by responding strongly to public appeals 

for conservation, and hydropower supplies were more abundant than 

normal. Even so, CAISO reached a Stage 2 emergency (when operating 

reserves are below or are expected to fall below 5 percent), allowing it to 

call upon interruptible customers to curtail use. The combined effect of 

interruptible and curtailable loads, conservation, and other utility loadreduction programs was a 4.1 percent reduction, more than 2,000 MW, at 

the peak day and hour. Neither southern California (identified by FERC 

in May 2006 as an area of summer concern6) nor any other region in the 

West was subjected to involuntary load-shedding.

Eastern areas also weathered the heat well. Southwest Connecticut, also 

flagged for concern,7 benefited from ISO-New England’s demand-response 

programs—which were particularly effective in Southwest Connecticut—

and record-high availability of generators. Long Island was considered 

vulnerable8 due to a tight demand and supply balance and limited import 

capabilities; as elsewhere, good demand response and high availability of 

generation helped avoid problems. Long Island Power Authority (LIPA) 

also credits strict planning criteria and good transmission performance.9 

During summer 2005 Ontario experienced many transactional problems 

with imports and exports, raising concerns10 that it could adversely affect 

neighboring MISO and NYISO in 2006, but a new day-ahead scheduling 

process reduced such problems by 90 percent. Ontario’s Independent 

Electricity System Operator (IESO) said good generation availability 

(including from wind and hydropower), new capacity, and Toronto-area 

transmission upgrades also helped avoid operational and market problems 

during hot weather.

In general, generator outages were at unusually low levels during 

the summer. This improved availability was important to maintaining 

reliability during hot weather. Nuclear power plants operated at 96 percent 

of their total capability during June, July, and August, compared to 94.6 

percent during the same period in 2005, amounting to an additional 1,350 

MW on average. NYISO said only two generators were forced out of 

service during the heat waves, which suggests much better than average 

availability.11 California reported that during its peak week it had the 

lowest power plant outage rate ever. PJM and New England also reported 

good availability. The Midwest Independent System Operator (MISO) 

region was an exception. High temperatures in cooling water sources and 

limits on discharge temperatures kept some generators there below full 

output. 

Robust demand response was a common factor that significantly 

improved reliability in several regions. Demand response took several 

forms: voluntary conservation, paid capacity-based programs, and utility6 See Summer Energy Market Assessment (Item A-3), Commission meeting of May 18, 2006; 

http://www.ferc.fed.us/EventCalendar/Files/20060518103507-A-3-with-talking-ptsl.pdf.

7Ibid., note 3.

8Ibid., note 3.

9Distribution-level systems did not fare as well as transmission during heat events. LIPA 

experienced a few distribution line overloads. In nearby Queens, Consolidated Edison had 

extensive local outages when a number of distribution lines were damaged by overloading. 

Southern California Edison replaced hundreds of distribution transformers.

10 Ibid., note 3.

11NYISO planned for a forced outage rate of 5.43 percent, equal to about 2,100 MW on average.
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ELECTRIC POWER MARKET SUMMARY

SUMMER 2006

administered load control and interruptible load. Notably, demand 

response in NYISO’s western zones on Aug. 2 assisted PJM on its peak day 

by improving NYISO transmission voltages enough to allow all scheduled 

exports to flow to PJM.

Market Prices Reflected Supply and Demand

Electricity markets generally performed as expected in response to 

combinations of higher peak demands, moderate average demand, lower 

natural gas prices and better generating availability. The following table 

shows that prices rose in RTOs with the greatest increase in peak summer 

demand. For example, PJM’s record peak demand increased 8 percent and 

its average summer 2006 price was 14 percent higher than summer 2005. 

California’s peak rose 10 percent and its average price rose 5 percent. 

Where record peaks grew more modestly, prices fell. MISO, ISO-NE, 

and NYISO peaks grew less than 6 percent, and the New York City load 

pocket (Zone J) had approximately one gigawatt of new, efficient gas-fired 

generation in summer 2006. Prices fell in all three regions.

Scarcity Pricing Present in Several Areas During High Loads

Prices rose to very high levels during heat waves in both RTOadministered spot markets and in bilateral markets. 

In NYISO, scarcity pricing is activated when demand-response 

measures are needed to maintain operating reserves or meet emergency 

conditions. NYISO’s two demand-response programs were used locally or 

systemwide on July 18, July 19, Aug. 1, Aug. 2, and Aug. 3. Under these 

conditions, the clearing price is the higher of the locational price or the 

scarcity (demand-response) resource offer. Scarcity prices set price floors 

on these days. Hourly settlement prices for some zones ranged from $420/

MWh to $1,500/MWh for one to five hours on each of these days.12

ISO-NE activated scarcity pricing on Aug. 1 and Aug. 2 as 30-minute 

reserves were depleted during peak hours. On Aug. 1, scarcity prices were 

activated for less than two hours in all zones but Maine, and on Aug. 2 

scarcity pricing was active about four hours in all zones. During these 

periods the ISO administratively set the systemwide energy price to $1000/

MWh. 

In MISO the conditions for activating scarcity pricing did not occur. 

During peak loads on July 31 through Aug. 2, MISO took Energy 

Emergency Alert (EEA) actions that trigged the loss of interruptible load 

and implemented utility level demand-response programs. The resulting 

lower loads helped maintain adequate reserve levels and lowered prices. In 

review, the MISO Independent Market Monitor raised questions about 

12 High locational prices also resulted from co-optimization of energy and reserves, a 

market design element that reflects reserve values in energy prices.

 
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ELECTRIC POWER MARKET SUMMARY

SUMMER 2006

the interaction of EEA actions and pricing.13 If scarcity pricing (called 

shortage-condition pricing in MISO) is invoked, operating reserves used 

for energy are offered at $1,000/MWh and are eligible to set the price.

Scarcity pricing was not triggered in PJM in summer 2006. To trigger 

it, the RTO must dispatch emergency generation, reduce voltage or take 

other emergency actions. PJM issued warnings of such actions (such as a 

voltage reduction) but never implemented them. PJM’s scarcity pricing 

provisions call for the locational marginal price for the entire region to be 

set by the highest offer price. 

 In bilateral markets, scarcity was reflected in both bilateral trading 

and in the relationship between power and fuel prices. For example, 

bilateral prices reached, and in some cases exceeded, the western soft cap14

of $400/MWh, as shown in the following table.

An indicator of scarcity is the ratio between the price for natural gas and 

the price for electricity. Known as an implied heat rate, it is the efficiency 

with which a generator must convert gas to electricity to break even, given 

their prices. If market prices for electricity and gas are such that even the 

least-efficient generator could make money—that is, the implied heat rate 

is very high—it indicates that there may be a scarcity premium in the price 

of electricity.

The actual heat rate for a simple cycle gas-fired generator is typically 

about 10,000 Btu/kWh, and the least-efficient plants need 20,000 Btu/

kWh. The chart shows that implied heat rates in the west between July 

24 and July 26, 2006 were well above those levels, strongly suggesting a 

scarcity premium in electricity prices. 

13 The Independent Market Monitor noted a lack of explicit rules coordinating shortage pricing and emergency operating procedures and recommended MISO develop ways to prevent 

suppressing “legitimately high prices” with emergency procedures during shortage conditions. Patton, David; Independent Market Monitor Review: 2006 Peak Load Event; September 20, 2006 http://www.midwestmarket.org/publish/Document/3c9065_10e9e96031d_-

7e6b0a48324a

14 By order dated Feb. 16, 2006, the Commission modified the price cap on spot market sales 

in the WECC outside of the CAISO to a $400/MWh “soft” cap, 114 FERC 61,135, paragraph 1. A 

soft cap allows market participants to submit bids above the bid cap with adequate justification, in this case for sales that are 24 hours or less and are entered into the day of or day prior 

to delivery in WECC or in CAISO.