You've seen the phrase, but what is a Minimum Generation Emergency? Here's the lowdown.

Of the many critical scenarios that ISO New England’s control room operators work through to keep the lights on, the situations that get the most attention involve tight electricity supplies on hot summer days or cold winter nights— those times when demand tends to peak in New England. And it’s well-known that when there’s not enough power to meet demand, lower voltages can occur, which can lead to ‘brown-outs.’ At the worst, system operators could have to resort to rolling blackouts. That’s a step that ISO New England has never had to employ; our system operators have always been able to solve those tight supply situations.

But at the other end of the spectrum lies another set of less well-known challenges that arise when demand is exceeded by generation and imports from neighboring bulk power grids. If that were allowed to happen, the result could include excessively high system voltages and frequencies and unscheduled flows of power into neighboring regions.

ISO New England’s control room operators have always been able manage through those situations, as well.

Min Gen Warning

It’s not unusual for generation to threaten to exceed demand, especially during the “shoulder” months of spring and fall, when New England weather is mild and there is little to no heating or cooling demand on the system. Spring also brings thaw and an increase in the output from run-of-the-river hydroelectric generators. During these seasons, system loads as low as
9,000 megawatts (MW)—the base load of the system—are not unexpected.

Meanwhile, New England’s baseload nuclear units, which essentially run all the time due to the long length of time required to power up and power down, supply about 4,500 MW or 50 percent of the base load. Combine that with conventional generation and intermittent resources, such as wind and run-of-the-river hydro generators, and some of the possible causes of over-generation become apparent.

When the control room forecasters’ reliability assessment indicates that generation could exceed the region’s demand for electricity, a “Minimum Generation Emergency Warning” (Min Gen Warning) will be issued on the ISO notices page. A Min Gen Warning lets power plants and neighboring regions know that the ISO is seeking voluntary reductions in generation and imports.

Min Gen Emergency

In real time, if the Min Gen Warning does not result in enough units being decommitted voluntarily, or imports from neighboring regions being reduced voluntarily, system operators are allowed to take certain steps to dial back generation and energy imports until demand starts to pick up again.

Of course, it’s not as easy as just telling all the generators to slow down or turn off. Power plants have an “economic minimum” (EcoMin): the minimum amount of electric energy that a generating resource must produce to cover the costs of running. They also have “emergency minimums.” Just as power plants have upper limits on how much electricity they can generate, they also have physical limits on how little they can produce. Below that emergency minimum limit, there is a risk the generator equipment can be damaged or the generator can trip offline. If at all possible, system operators also try to avoid turning generators off because the power from those plants may be needed again within a few hours as electricity use picks up. Some generators, such as coal or nuclear plants, can take 12 to 24 hours or even longer to start up.

A Minimum Generation Emergency (Min Gen Emergency) is declared when the ISO anticipates asking generators to operate at or below their EcoMin in order to resolve the situation.

According to our system operating procedures, a Min Gen Emergency should be declared when the difference between projected demand and electricity supply (that is, net imports clearing in the Day-Ahead Energy Market plus the EcoMin of all online power plants) is 100 megawatts or less. (If the difference is 100 megawatts or less, that means the gap between projected demand and supply is getting too narrow.) For example, at 3 a.m. on Sunday, October 4, 2009, ISO control room operators saw that the system could have 150 MW more generation than needed by 4 a.m., so they shifted from a Min Gen Warning to an actual Min Gen Emergency. (Or, put another way, demand would be 150 MW lower than generation.)

Once a Min Gen Emergency has been declared, the ISO administratively sets the real-time locational marginal prices to $0 per megawatt-hour and the unit dispatch software (UDS) may dispatch generators down to their offered emergency minimum level of generation—the least amount of power the equipment can produce. Control room operators can also cut back on imports to a greater degree, can reject any request to increase output from a generator that has scheduled itself to run, and can cancel the scheduled start-up of power plants.

With imports curtailed, power plant output reduced to emergency minimums, and demand starting to rise again as New England awakened, the Min Gen Emergency was cancelled after five hours, at 8 a.m. on October 4.

These variations in demand fuel the volatility of wholesale electricity prices in the real-time energy market. In the middle of the day on October 3, 2009, when supplies were tight because of several unexpected outages on the system, average wholesale prices neared $100 for a megawatt-hour (MWh) of electricity. Twelve hours later, when demand dipped so low, locational marginal prices were set to $0 per megawatt-hour. That was the price for the entire five-hour duration of the Minimum Generation Emergency.

The term “minimum generation emergency” can be confusing—it sounds like there’s not enough generation to meet demand. Before industry restructuring, the term used was "light load conditions." In that era, utilities tended to have a relatively small set of baseload generation plants that could not be dispatched down or off. Their other resources could be turned off during normal conditions. As a result, excess generation conditions only occurred during periods when demand was light.

When interim markets started (in 1999, in New England), market participants were able to self-schedule generation and import and export transactions to the point that excess generation could result, regardless of the level of demand on the system. Because "light load conditions" weren't necessarily the cause, the more descriptive "excess generation conditions" was used in ISO New England’s rules.

ISO New England's transition to Standard Market Design in 2003 was modeled on the market design in PJM Interconnection, and much of PJM's software, rules, and terminology—including "minimum generation emergency"—was incorporated. Although these situations are not emergencies, the term does reflect a situation under which the ISO anticipates asking generators to operate at or below their EcoMin in order to work through or end the situation.