(Repeats column, no change to text)
By John Kemp
LONDON, April 30 (Reuters) - Demand response programmes, where customers are given a financial incentive to reduce power consumption at times of peak demand, are playing an increasingly important role in the U.S. power market.
In 2013 and 2014, grid operators called on record amounts of demand response to cope with first the summer heat wave and then the polar vortex.
Without the ability to reduce electricity demand voluntarily, utilities in many parts of the United States would have been forced to initiate rolling blackouts.
In one instance, regional transmission operator PJM secured nearly 6,000 megawatts (MW) of demand reductions on a single afternoon - equivalent to the entire output of five nuclear power stations.
More than 8 million electricity consumers in the United States are now enrolled in some sort of programme to cut their consumption during periods when the grid is stretched.
Policymakers and regulators have been strong supporters because demand response can increase electric reliability, lower customer bills and avoid the need to build lots of costly new power plants and transmission lines.
But it remains controversial with some power producers and grid operators, who fear it is undercutting the incentive to invest in new generating and transmission capacity and could hurt reliability in the long-term.
Demand response programmes are operated at retail level by utilities and at the wholesale one by regional transmission organisations and independent system operators.
The Federal Energy Regulatory Commission (FERC) estimates total demand response capacity doubled between 2005 and 2011 from 30,000 MW to 66,000 MW. The potential demand reduction from all sources was equivalent to 8.5 percent of peak load on the U.S. power network in 2011 - roughly equivalent to the peak consumption of California.
Of the total, 37,000 MW of demand response capability was in programmes run by utilities for residential customers and small businesses, while 29,000 MW was contributed by larger consumers participating in the wholesale market, according to FERC (“Assessment of Demand Response and Advanced Metering” 2012).
By 2011, about 8.5 million of 131 million retail customers in the United States (6.5 percent) were enrolled in demand response programmes run by their utility.
Perhaps surprisingly, at the retail level, most customers chose to participate in a programme that gave the utility direct control over their electricity use rather than accepting a programme in which prices varied but they were left to decide whether to turn appliances off for themselves.
Around 6 million customers were enrolled in some form of direct demand control programme that allowed the utility to remotely interrupt the power supply to one or more electrical devices such as pool pumps or air conditioners for short periods lasting from a few minutes up to six hours.
Direct control programmes contributed more than 9,000 MW of potential demand reductions.
Some larger users agreed to reduce their power consumption in response to instructions from the grid. Interruptible supply contracts contributed another 15,000 MW.
Far fewer customers were enrolled in programmes where they faced steep price changes but retained control over whether or not to reduce their consumption.
Just 2.2 million retail customers were enrolled in programmes charging peak/off-peak prices that varied by time of day, contributing around 7,000 MW of potential demand reductions.
Only 20,000 participated in critical peak pricing programmes, where the utility has the right to declare a power emergency with 12 or 24 hours notice and can charge very high prices for electricity consumed during the critical peak.
Similarly, only 20,000 were enrolled in real-time pricing, where prices vary hourly based on the wholesale cost of electricity.
Critical peak pricing and real-time pricing programmes contributed just 2,000 MW of potential load reduction in total, according to a report prepared by the Government Accountability Office (GAO) published on Monday (“Demand response activities have increased” April 2014).
During the 2013 summer heat wave, grid operators for New England (ISO-NE), New York (NYISO), the mid-Atlantic states (PJM) and California (CAISO) repeatedly called on demand response to keep the lights on and avoid rolling blackouts.
NYISO activated demand response across the entire state on July 18 and 19 as power consumption hit a new record, according to GAO. NYISO credits demand response for avoiding blackouts, especially in the lower Hudson Valley and New York City.
Two months later, on September 11, PJM called on and received 5,949 MW of demand response, the largest it has ever received, after hot weather and equipment failures created emergency conditions across four states. Once again, demand response allowed PJM to keep the lights on and avoid forced power cuts.
In January and February 2014, PJM, CAISO and the Electric Reliability Council of Texas (ERCOT) were all forced to activate demand response again as the polar vortex plunged the country into a record cold spell and led to widespread equipment failures.
Activating demand response is often cheaper than calling on emergency generation from peaking power plants: most peakers operate just a few hours each year so need to charge very high prices to recover their capital and operating costs.
By flattening out the peaks in power demand, demand response can also avoid or delay the need to invest in lots of additional and expensive generation and transmission capacity that will only be used a small fraction of the time.
The costs associated with spikes in demand have a significant economic impact as GAO explained in its report: “10 percent or more of the costs of generating electricity are incurred to meet levels of demand that occur less than 1 percent of the time.”
According to the Midcontinent Independent System Operator (MISO), demand response has saved customers across the central part of the country more than $100 million a year.
Because of their potential to make more efficient use of generation and transmission capacity, demand response has long been popular with policymakers and regulators.
Congress has instructed regulators to report on time of use tariffs and other demand response mechanisms in several pieces of legislation (including the 1978 Public Utility Regulatory Policies Act, the 2005 Energy Policy Act and the 2007 Energy Independence and Security Act).
The 2009 American Recovery and Reinvestment Act provided billions of dollars in co-funding to help utilities install smart meters, which are essential to implementing many demand response programmes.
Almost 50 million smart meters (out of a total of 151 million) have now been rolled out nationwide.
In March 2011, FERC issued Order 745, which requires that suppliers of demand response be paid the same for cutting consumption as generators are paid for providing extra power output. In effect, FERC requires treats demand response as a form of extra generation.
Parity is controversial. According to GAO, parity supporters claim “equal compensation is appropriate because demand response activities provide a benefit to the market by replacing the need to have power plants provide additional capacity.”
Demand response can also provide localised benefits by relieving congestion in places such as New York City.
For critics, including many independent power producers and some officials in regional transmission organisations, equal compensation is not justified because demand response and generation have fundamentally different characteristics.
Generators must make long term commitments while most participants in demand response programmes are only locked in for a month or at most a year before they can withdraw their commitments.
Generators and some grid operators warn that equal compensation and the increasing reliance on demand response are undercutting long-term reliability because they weaken price incentives to install more capacity to meet future needs.
They claim the long-term availability of demand response is more unpredictable than building new generating plants and warn of “response fatigue” if customers are called on to cut consumption too often.
Despite the warnings, demand response seems set to play an increasingly important role in the power market. FERC has already accepted plans from NYISO and ISO-NE for compensating response providers under Order 745. Plans from CAISO and MISO have also been broadly accepted. Only the Southwest Power Pool (SPP) has been told to come back with revised proposals.
So to keep the lights on in future, it looks like customers will have to accept more flexibility in their power consumption. (Editing by Jason Neely)