Electricity grid operators knew hours before the 4 p.m., August 14, 2003 Northeast power failure that things were going badly. One called his wife, predicting accurately that he would have to work late, and another complained it was “not a good day in the neighborhood.”
The largest blackout in North America left 50 million people without power and largely without communications, but some engineers knew that the blackout could have been prevented. Part two of a two-part series on the Northeast Blackout of 2003.
Credit: Shane Lear, courtesy of NOAA
As the official report makes clear, troubles were building up during the day with the computers, the communications, and the coordination, the C3 of civilian power pools. The August 2003 blackout was the culmination of control systems out of service, inflexible generator schedules, and a grid operator unable to require flexibility from market-based generators.
With three aged power plants shut down the day before, the conditions were ripe for trouble. When the first overloaded line sagging from excess heat touched a tree limb and short-circuited at 2 p.m. south of Cleveland, Ohio, the computer, communications, and coordination capabilities were insufficient to save the day and prevent the blackout two hours later.
Lessons learned
The 2003 blackout had many lessons, but for the industry and regulators, the big one was: Make the grid reliability rules mandatory and enforceable! But in addition to top-down reliability controls, regulators are also accommodating innovations and flexibility that were needed back on that day in August 2003. These kinds of reforms also provide for lower costs, and easier adoption of renewable energy, as well as greater reliability.
The system-wide blackouts that have hit large areas in the past (see prior blog) demonstrate that we are using region-wide systems but often without adequate regional-scale coordination. Recent Federal Energy Regulatory Commission (FERC) orders address parochial boundaries that limit flexibility, and improve transfers and cooperation across boundaries. The FERC reforms to increase flexibility and improve reliability have also been designed to improve the integration of renewable energy and make better use of efficiency and demand response. A more diversified supply with more distributed generation inherently helps reduce vulnerability.
Grid operators help
Credit: ISO/RTO Council
The greatest innovation in the management of the power grid in the past 10-15 years is the regional Independent System Operator, or ISO. The ISO is coordinator of grid planning and operations for the area served by its member companies. Generators and utilities interact through the ISO to coordinate and transact their business. When mature, an ISO also consolidates the otherwise fragmented practices over a wider area, creating immediate savings in shared reserves, and aggregate and smooth variability of wind energy.
ISOs were not as mature in 2003 as they are today. Still in the West, other than in California, ISOs do not exist and reforms have been very, very slow. One promising development is a voluntary “energy imbalance market” or EIM. The advantages of either a comprehensive ISO or a more narrowly conceived automated imbalance market as the EIM may offer, is the much needed innovation of close coordination of grid wires and generators. With modern communications and controls, these approaches can recognize unused flexibility and make the power system more reliable, more economical, and better suited for absorbing renewable energy. As climate change makes conditions for power generation more challenging, and fossil-fired plants are affected by hotter weather and droughts, more flexibility and unanticipated energy trades will be needed to avoid blackouts.
Flexibility and innovation from FERC
Just in the past year, a change has been ordered that will increase reliability and flexibility. FERC has ordered a change to an old practice between utilities, both big ISOs and small utilities, that still requires schedules for energy transfers be set and unchanged in one-hour blocks. This reduces the flexibility that may be available from the neighboring utility or the generator supplying power. It also offers no flexibility in addressing the steadily changing demand for power during the morning and evening rush hours on the grid, known as “ramps.” FERC, in Order 764 designed to reduce the costs for integrating renewable energy, required that transmission schedules be changeable at 15-minute intervals.
Economists at FERC and in the nascent energy storage industry also recognized that generators have little incentive to change their output when instructed to provide that flexibility. The reliance on large, inflexible steam generators (typically coal and nuclear) has made the grid less adaptable. To recognize superior performance for balancing supply and demand, FERC has adopted a new “Pay for Performance” compensation approach for this service. This has drawn additional and faster response capabilities from existing generators, customer-owned equipment, and even new storage assets (flywheels and batteries).
While much of the attention and controversy about inter-regional cooperation in the electric utility sector is focused on long-term planning for new transmission, or the reliability of imported power, great improvements in the operation of the existing system are available. Controls and rules can be adapted to recognize the benefits of coordination, greater information sharing, and reduced costs. Sometimes it takes lightning, or a blackout, to wake up and re-evaluate the way we have been doing things. The 2003 Northeast Blackout had that effect, though we are only halfway through the changes we know we need.