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Policy Review

Demand Response: Effective tool for grid planning and reliability [free access]

April 1, 2009

Demand response (DR) has long held the promise of cost effective management of load growth and transmission congestion, thereby leading to improved grid reliability and better short-term capacity availability. It is almost always cheaper to reduce the peak capacity requirement through DR than to build a new peaking power plant. Further, the time needed for deploying a DR resource is significantly less than that required for creating new generation and transmission infrastructure. Economic DR programmes also serve to moderate prices during shortage conditions.

The 2008 Assessment of Demand Response and Advanced Metering report by the Federal Energy Regulatory Commission (FERC), released in December 2008, estimates that the potential resource contribution of the various DR programmes across different states of the US in the year was almost 41,000 MW. This was approximately 6 per cent of the projected peak load in 2008.

The report also states that direct load control programmes accounted for the largest portion of the national peak load reduction potential. At 11,045 MW, these programmes accounted for 30 per cent of the national peak load reduction potential, followed by interruptible/curtailable rates that accounted for 8,032 MW or 22 per cent, and emergency demand response programmes at 4,817 MW or 13 per cent.

The report concludes that DR programmes have expanded as a result of legislative and voluntary programmes and also in response to rising energy costs. It is expected that these programmes will continue to expand in the future. The survey also records several instances where DR programmes have not just helped meet peak demands but have played a critical role during emergencies, ensuring the competitiveness of wholesale markets and the reliability of grid operations.

For instance, in Texas, DR was deployed in response to sudden changes in generation output on two occasions. On December 12, 2007, the Electric Reliability Council of Texas (ERCOT) deployed its Load Acting as Resource (LaaR) programme when 1,022 MW of generation tripped. Within 10 minutes of notice, LaaR providers responded with a 1,051 MW curtailment to stabilise the grid. Then, on February 26, 2008, ERCOT experienced a frequency drop in its system as a combined result of decline in wind generation, increased heating demand and lower generation from non-wind generators. ERCOT reported that 1,108 MW of LaaR load responded within 10 minutes, stopping the frequency decline and restoring the ERCOT grid to stable operation.


However, despite the benefits, DR programmes face several barriers, chief among which is the potential loss of revenue to the utilities if the consumption decrease during peak periods is not compensated by an increase during off-peak hours. The FERC notes that several states have taken steps to remove this barrier, either by providing a reasonable opportunity for utilities to recover the costs of deploying DR programmes or by offering incentives for implementing high performance DR programmes. Then there are other states that have put policies in place that allow utility profits to be "decoupled" from the retail sales volume.


On the federal level, the FERC has recognised the important role that DR plays in ensuring the competitiveness of wholesale markets and the reliability of grid operations. Through its recent orders, the commission has eliminated barriers to the deployment of DR. On October 17, 2008, it issued the Wholesale Competition Final Rule 719 that requires all regional transmission operators (RTOs) and independent system operators (ISOs) to modify their market rules to allow DR resources in their markets for certain ancillary services, eliminate charges to a buyer during a system emergency for taking less electricity in the real-time market than purchased in the day-ahead market, and permit aggregators of retail customers to bid demand responses directly into the organised energy market on behalf of the customers.


FERC's order number 890, which reformed open-access transmission tariffs, requires the RTOs and ISOs under its jurisdiction to establish a transparent transmission planning processes incorporating DR resources if they were "capable of providing the functions assessed in a transmission planning process, and can be relied upon on a long-term basis."


The other major barrier to large scale DR deployment is the lack of tariff incentives to customers to respond to DR measures. Most customers in the US continue to pay a fixed retail tariff that does not reflect the real-time variations in cost of delivering electricity services. Though price-responsive demand is considered to be one of the most effective forms of DR, activities to implement time-based rates are still limited in the US. Currently, only about 8 per cent of all US electricity customers participate in some form of a DR programme.


The main reasons for the low number of DR participants are inadequate penetration of advanced meters and delays in the utilisation of these meters to support time-based rates. While advanced metering infrastructure providing information on electricity usage on a real-time or near real-time basis exists, the cost of deploying the technology remains an obstacle. Further, though other enabling technologies such as home area networks and smart thermostats are required to fully develop DR for residential customers, the recovery of the costs of these technologies through customer tariffs remains a controversial issue.


The FERC report concludes that in order to address these and other barriers, the commission will continue its current coordination with the National Association of Regulatory Utility Commissioners on aligning retail DR programmes and time-based rates with wholesale market designs, and support other organisations to develop practical means to forecast, measure, verify and track the impact of DR initiatives.


The findings of this report, along with consultations with various market entities and stakeholders, with help the FERC to an assessment of the national DR potential for 5- and 10-year periods by June 2009, as is required under the Energy Independence and Security Act, 2007. By the end of this year, the US Department of Energy and the FERC are further required under the act to identify the need for technical assistance, education, regulatory provisions and model contracts for customers, states, utilities and DR providers. Based on the findings, they have to submit an execution plan to the Congress by the end of next year.


The need of the hour is for the FERC to play a leadership role to ensure that the whole is larger than the sum of the individual DR programmes, advanced metering initiatives, smart grids, renewable energy and energy efficiency being deployed at the federal and state levels.