Advanced Metering Tops 50% for First Time

DR Participation Drops in ISO-NE, PJM

Dec 12, 2019

Advanced meters represent more than half of the meters in service, but demand response growth has been choppy due to slow adoption of time-of-use rates.

By Rich Heidorn Jr.

Advanced meters now represent more than half of the electric meters in service, but the growth of demand response has been choppy due to slow adoption of time-of-use rates, FERC reported Wednesday.

The U.S. had 78.9 million advanced meters operational in 2017, 51.9% of the total of 152.1 million meters and an increase of five percentage points from 2016, FERC reported in its 14th annual report on DR and advanced meters. The annual report was mandated by Congress in the Energy Policy Act of 2005.

Between 2007 and 2017, the number of advanced meters in operation jumped almost twelve-fold and now dominate in five NERC regions: Texas RE (90%); SPP RE (63%); the Western Electricity Coordinating Council (61%); the former Florida Reliability Coordinating Council (58%) and ReliabilityFirst (55%).

Advanced Metering — Advanced meter growth (2007–2017) | *FERC, Energy Information Administration, Institute for Electric Efficiency*

In the last year, FERC reported, utilities in Arkansas, Hawaii, Indiana, Minnesota and New Jersey have proposed or received approval for deploying advanced meters, seeking to improve customer engagement, reduce outage duration and create a foundation for other grid modernization efforts.

Commission staff noted regional differences in advanced meter penetration, with residential customers at higher penetration levels than commercial or industrial customers in most regions. In FRCC, Hawaii, the Midwest Reliability Organization and the Northeast Power Coordinating Council regions, however, advanced meter penetration is highest in the industrial sector.

Overall, advanced meter penetration rates for residential and commercial customer classes were at or above 50% for the first time in 2017, while penetration for industrials grew to 44.5%.

Time-of-Use Rates

But while advanced metering has become more ubiquitous, policymakers have been slow to embrace the technology’s capabilities. The report identifies the “relatively slow implementation of time-based rate programs” as a main cause of lackluster customer participation in demand response.

Nationwide, enrollment in time-of-use (TOU) rate programs has increased by 42% since 2013, with retail customer enrollment increasing by about 7% in 2016/17. But only 8.5 million customers nationwide have TOU rates, 75% of them in ReliabilityFirst and WECC.

Regulators in New York and North Carolina have ordered their utilities to expand time-based rates to reduce peak demand and leverage their metering investments. Regulatory commissions in Maryland, Michigan, Minnesota, and the District of Columbia have adopted or are exploring time-based rates for electric vehicles to incentivize charging during off-peak hours.

Demand Response

Demand response statistics showed some advances and some retreats.

Potential peak demand savings from residential programs — the total demand savings that could occur at the system peak hour if all demand response was called — dropped by 12% to 31,508 MW from 2016 and 2017, with the biggest reductions in SPP RE (due to lower reported savings by Oklahoma Gas and Electric) and WECC (with large decreases reported by Salt River Project and Southern California Edison). The report said the drop in WECC “likely reflects a shift toward greater demand response participation in CAISO’s wholesale market.”

Demand response participation in the wholesale markets increased by about 8% from 2017 to 2018, to a total of 29,674 MW, with the biggest increases in CAISO and MISO but decreases in ISO-NE and PJM, which have tightened requirements for capacity resources. The registration of DR in wholesale capacity, energy and ancillary services markets grew to 6% of peak demand in 2018.

ISO-NE reported a 48% drop in DR participation from 2017 to 2018, which the report noted “coincides with the implementation of ISO-NE’s Pay-for-Performance program, which places more stringent requirements on [capacity] resources,” including DR.

PJM reported a net decrease of 226 MW (2.4%) in DR enrollment from 2017 to 2018, which the commission said “may be due to the continued phasing out of legacy demand response products” as the RTO completed its transition to an annual Capacity Performance product with tougher penalties for non-performance.

ERCOT, MISO, CAISO and PJM each deployed emergency demand response in 2019:

ERCOT reduced load by about 3,100 MW on Aug. 13 and 1,800 MW on Aug. 15 by deploying emergency response service (ERS) after high demand, reduced wind production and generation outages left the region short of its 2,300-MW reserve threshold. (See ERCOT Survives Another Day in the Ro a ster.)
MISO activated load modifying resources (LMRs) on Jan. 30, during an energy emergency alert Level 2 emergency in its Central and North regions. The RTO’s market monitor predicts DR will be deployed more frequently as the region’s capacity surplus decreases. (See MISO Maintains Relia b ility Through Arctic Midwest Temps.)
CAISO issued a statewide “flex alert,” calling for voluntary conservation on June 11, and some utilities declared critical peak pricing days — boosting prices temporarily — for retail customers several times during the summer.
PJM called on interruptible customers in the American Electric Power, Baltimore Gas & Electric, Dominion and Potomac Electric Power Co. zones to reduce load on the afternoon of Oct. 2, when the RTO’s demand exceeded 126,000 MW, its second-highest October demand on record.