(John Kemp is a Reuters market analyst. The views expressed are his own)
By John Kemp
LONDON Jan 10 In a silent revolution, the U.S. power distribution system is undergoing the biggest shake-up since Samuel Insull built the modern electricity industry a century ago.
In the old model, supply passively followed demand, and large amounts of expensive generation and transmission capacity were kept idle much of the year to be available to meet demand at peak times. In its place now, the grid is changing gradually to a more market-based system, in which both supply and demand are expected to adjust to make the most efficient use of generation and transmission assets.
By the end of 2011, 38 million "smart meters" had been installed across the United States, up from just 1 million in 2005, according to a survey by the Federal Energy Regulatory Commission (FERC).
Nationwide nearly 23 percent of electric customers now have a smart meter, a figure that rises to more than half in Idaho, Georgia, Arizona, Nevada, Alabama and Delaware and to as much as 70 percent in California.
But in New York, just 0.3 percent of customers have smart meters and only 0.2 percent in New Jersey. The two states had fewer than 50,000 smart meters combined in 2011, according to FERC ("Demand Response and Advanced Metering" Dec 2012).
At a minimum, smart meters record usage at hourly intervals, and provide usage data to both customers and energy companies at least once daily. But more sophisticated versions monitor consumption in real time and have two-way communications capable of recording and transmitting information between the meter and the grid.
Smart meters are intended to support a shift from flat-rate electricity tariffs to time-of-use pricing or even critical peak pricing. Both systems charge customers more, sometimes much more, for electricity at times when the grid is stretched to the limit.
Dynamic pricing helps avoid the need to build extra power plants and transmission lines to deal with just those few hours and days each year when capacity is scarce and encourages customers to shift consumption to less congested periods with cheaper rates.
Twenty-nine states either have adopted time-based pricing systems, have requirements pending or are studying them, according to FERC and the Energy Information Administration (EIA).
In Arizona, one third of the residential customers of the Arizona Public Service (Maricopa and surrounding counties) and Salt River Project (metropolitan Phoenix) service areas have voluntarily chosen to participate in a time-of-use tariff programme.
California, Maryland, Arkansas, Oklahoma, Illinois, Idaho and Connecticut are all introducing significant dynamic pricing programmes.
By June 2012, the Department of Energy had spent $2.8 billion to support the rollout of advanced meters, part of the $4.5 billion Smart Grid Investment Grant programme under the American Recovery and Reinvestment Act.
Smart metering is just one element of the attempt to create more demand-response capacity in the system.
FERC defines demand response as changes in electricity use from normal consumption patterns in response to changes in the price, or to incentive payments designed to induce lower use at times of high wholesale market prices or when system reliability is jeopardised.
Demand-response programmes include:
* Interruptible supply contracts, in which the utility can order customers to cut consumption at peak times in return for rebates
* Direct load control, in which the utility can remotely switch off customers' heating or cooling appliances or change their settings
* Critical peak pricing, when the utility can declare very high prices 24 hours in advance for short periods of peak demand, leaving the customer to manage consumption.
FERC estimates demand response from all sources could trim 72,000 megawatts (MW) from consumption, about 9.2 percent of peak power demand, up from just 59,000 MW in 2009.
Commercial and industrial customers, who have sharper incentives than residential consumers to manage bills, still account for most demand-response capacity.
Demand-response capacity is also spread very unevenly across the country. PJM Interconnection and the Midwest Independent System Operator are able to call upon far more demand response than other regions.
In 2011, the FERC survey identified actual demand reductions of more than 20,000 MW at peak times across the country.
In 2012, PJM invoked demand response repeatedly - mostly for economic rather than grid security reasons - during June and July when air conditioning loads were highest during a heat wave. On July 18, PJM called up over 2,500 MW of demand reduction, the largest single deployment of demand response last summer.
Further north, the New York Independent System Operator called on demand-response resources repeatedly during June and July to cope with soaring temperatures. On June 20, it reduced hourly peak loads by up to 30 MW in New York City.
California did not deploy formal demand-response programmes last summer. But the California Independent System Operator (CAISO) did issue several "Flex Alerts" in August asking consumers voluntarily to conserve electricity and shift use to non-peak times. CAISO estimates a Flex Alert issued on Aug. 10 reduced peak load by as much as 1,000 MW.
The grid is getting smarter in other ways too. The North American Synchrophasor Initiative (NASPI) is installing units across the entire grid that measure voltage and other aspects of power quality as much as 30 times per second and make the results available to grid controllers instantly via satellite links (link.reuters.com/cym25t).
Supported by the Department of Energy, NASPI is designed to enable grid controllers to react quickly to problems before they cause cascading failures across the network, such as the 2003 blackout which knocked out 265 power plants and left 50 million customers across the U.S. Northeast and parts of Canada without electricity for up to four days.
The U.S. grid is slowly being transformed by demand response, renewed interest in investing in transmission assets and plans to start building a network of long-distance, high-voltage lines to bring renewable wind and solar power from the centre of the country to major demand centres near the coasts..
Insull's vision of encouraging ever more power consumption to maximise economies of scale is giving way to something much more complex. Capacity is being managed far more efficiently. The old rather rickety grid is being strengthened and should be able to improve reliability even as it adds more renewables. (editing by Jane Baird)