By Peter Maloney
APPA Author
Posted on July 10, 2018

Regional power grids fared well through a recent heat wave just as California and the Southwest were bracing for the expectation of brutal hot weather.

The hot weather set at least one record, but in most wholesale markets, peak demand was far below historical levels.

ISO New England hit an hourly peak of 24,180 MW on July 5, not even close to the ISO’s record peak of 28,130 MW hit on Aug. 2, 2006 during a heat wave. The July peak was not even high enough to qualify for the ISO’s list of top 10 peaks.

The ISO issued no alerts and had sufficient capacity to meet demand throughout the heat wave. ISO New England, in fact, began preparing for the hot weather even before summer began, spokesperson Marcia Blomberg said. Each spring, the ISO and its utility partners perform maintenance on transmission and generation resources in preparation for the high loads that hot weather brings.

Heading into the summer months, ISO New England closely monitors weather forecasts, fuel source availability, and other factors that may affect the grid to get a sense of what conditions system operators will be facing.

The difference between a normal summer temperature of 90°F and heat wave conditions of 94°F can result in more than 2,000 additional MW of demand, the ISO says.

Cold winter weather also causes spikes in demand, but ISO New England experiences its highest peaks during the summer, and summer peaks can put more of a strain on its grid because they extend for longer periods with a ramp beginning during midday and stretches into the evening. Winter peaks usually last two to three-hours early in the evening.


The PJM Interconnection, which serves all or part of 13 mid-Atlantic states and the District of Columbia, also is a summer peaking system. PJM hit a peak of about 146,000 MW on July 3, but like New England it was far below PJM’s historical peak of 165,492 MW hit on Aug. 2, 2006. Last summer, PJM’s peak demand hit 145,331 MW on July 19.

The recent July peak was “certainly the most demand we’ve seen so far this calendar year,” Paul McGlynn, PJM’s senior director of operations said, but it was lower than the ISO had estimated going into the heat wave. On July 2, PJM estimated its peak would hit about 151,000 MW.

PJM issued a hot weather alert in advance of the expected high temperatures, requesting that transmission and generation resource operators defer any scheduled maintenance or testing of their facilities.

“Overall, system performance was good. Generation and transmission performed well throughout the event,” McGlynn said.

PJM day-ahead and real-time prices were above $100 in most zones during the afternoon of July 2, with the highest price hitting $207 for the day-ahead market in the Duke Energy Ohio and Kentucky zone. Prices on July 3 were generally between $80 and $90 during the hottest parts of the day.

PJM’s total capacity is about 180,000 MW, which McGlynn said is “well beyond” the ISO’s planning reserve margin of about 16%. PJM’s actual reserve margin is about 28%.

New York

In neighboring New York, the hot weather brought about peak demand of 31,468 MW on July 2, missing the ISO’s historic peak of 33,956 MW set in July 2013.

In preparation for the heat wave, NYISO activated its demand response programs for Zone J (New York City) on July 2 in order to reduce electricity consumption levels. The peak load forecast at the height of the heat wave was projected to be 32,810 MW.

NYISO zonal day-ahead prices peaked at $255 per MWh in the Western zone for a single hour of July 2, and close to that level on July 3. Several other zones, including New York City and Long Island, exceeded $100 in a number of intervals during the afternoons of July 2 and 3. Real time prices were generally below $100.


The Electric Reliability Council of Texas, however, did set a record, hitting a new July peak of 69,647 MW on July 3. “We had sufficient generation to meet the demand,” spokeswoman Leslie Sopko said. “Based on normal operating conditions, we anticipate there will be sufficient generation to meet peak demand this summer,” she said.

ERCOT day-ahead prices on July 2 and 3 were between $100 and $170 for the two hours between 3 and 5 p.m., while real time prices were much lower, generally about $20, other than the Western zone, where real-time prices ranged between $80 and $100 in most hours.

To help prepare for the summer months, ERCOT and the Public Utility Commission of Texas have met with market players to encourage enhanced preparations for summer operations.

ERCOT added some restrictions on planned transmission outages during the summer months and met with gas pipeline companies to reduce the potential for generation unavailability due to pipeline outages. “Our grid operators and ERCOT market participants are focused on performance this summer,” Sopko said.

Texas regulators recently urged natural gas pipeline owners to defer pipeline integrity work until after the summer to make sure power plants have access to fuel when they need it during a period when a demand record is expected to be set.

“When integrity testing of gas transmission pipelines can be scheduled to take place outside peak electric generation months, without safety risk, we encourage you to take this approach to protect citizens from losing their air conditioning, fans, and lights during the hot Texas summer,” Railroad Commission Chairman Christi Craddick and Public Utility Commission Chairman DeAnn Walker said in a June 25 notice to pipeline and power plant operators.

ERCOT went into the summer expecting record breaking peak usage. In a resource adequacy report released in April, the grid operator forecast a summer peak of 72,756 MW based on normal weather conditions. That forecast is more than 1,600 MW higher than the all-time peak demand record set in August 2016.

Since March, ERCOT’s total generation resource capacity has increased by more than 500 MW because of generating units returning from mothball status and from extended outage status and from planned gas-fired resources becoming available earlier than initially expected. ERCOT’s planning reserve margin for summer 2018 has increased to about 11% and through 2022 it is in a range from 10.9% to 12.3%.


Meanwhile, California was bracing for its first summer heat wave over the weekend with temperatures expected to break the 100°F mark in Southern California.

San Diego Gas & Electric on July 6 activated its Reduce Your Use rewards program that allows customers to earn credits on their bills for energy saved.

Forecasts call for temperatures to reach as high as 117°F in the desert and over 100°F on some communities. SDG&E said it had secured adequate electric supplies and crews are standing by to ensure the grid can deliver safe, reliable energy.

SDG&E in a series of posts on its website, noted that some of its customers faced power outages due to fires.

The Los Angeles Department of Water and Power urged customers to save energy where possible.

In a July 8 post, LADWP said that Saturday’s (July 7) peak electricity use exceeded 5,700 ME, making it the 2nd highest weekend day in Los Angeles history. Friday’s peak electricity use reached 6,256 MW, setting a new record for a July day.

LADWP noted on July 8 that it was working to restore power to customers faced with outages in the midst of the heat wave.

“LADWP power system crews made significant progress overnight and now have restored power to nearly 51,000 customers since the heat storm began Friday,” LADWP said. “Additional overnight crews and cooler temperatures in the late evening and early morning hours helped crews who have been working 16-hour shifts make progress.”

LADWP on the morning of July 9 said its power system field crews had made significant progress overnight. As of 9:00 a.m. July 9, LADWP had restored power to 76,000 customers since the heat storm that began Friday, with LADWP reporting 7,800 customers without power.

Over the past three months, LADWP’s average energy use has peaked at 4,350 MW, compared with an average daily peak of 3,555 MW year-round. LADWP hit a record peak demand of 6,502 MW on Aug. 31, 2017.

On Friday, temperatures near Palm Spring soared to 111°F and Southern California Edison reported that some homes were without power.

In a July 5 news release, Southern California Edison said it had extra crews at the ready and additional personnel monitoring the impact on the electrical grid, in case high temperatures result in additional power outages. The investor-owned utility said that during extreme high heat, it looks at planned outages on a case-by-case basis and factors such as public safety and reliability needs are considered. In some cases, these maintenance outages are postponed to a later date.

As of Friday, the California ISO had not released a flex alert, which requests consumers to voluntarily conserve electricity. However, in a tweet, the grid operator said that it was declaring restricted maintenance operations in Southern California for July 7, with the expected heat wave and high loads.

Meanwhile, in May, the ISO released a summer assessment that forecast tight electricity supplies this summer. CAISO is expecting about the same level of peak demand that occurred last summer, but 2018 hydroelectric production will be down 1,300 MW by late summer compared with 2017’s above normal production. In addition, natural gas-fired generation is expected to drop by 800 MW because of planned retirements.

CAISO expects electricity supplies to be adequate during the day when solar production is high, but conditions will become “challenging” in the evening when the solar energy drops off and consumers begin to cool their homes.

CAISO says there is a 50% probability it will need to declare a Stage 2 Emergency for at least for one hour this summer. The ISO has not declared a stage 2 event since 2007.

CAISO projects 51,947 MW of generation will be available to serve demand this summer and forecasts peak summer demand of 46,625 MW under normal conditions. If temperatures are warmer than normal, “power supply margins will begin to tighten up significantly,” the ISO said. CAISO’s peak load in 2017 was 50,116 MW on Sept. 1.