Demand response resources are not being used to their full potential in the US but a number of rapidly changing market design and business model developments coupled with software intelligence might change that, according to Wood Mackenzie.
The characteristics of generation and demand response assets are fundamentally evolving, said Elta Kolo, research manager, grid edge at Wood Mackenzie in a webinar this week. Regulatory policies and technology development are pushing the boundaries of flexible demand and supply.
Renewable energy penetration in wholesale market territories varies from around 5% to nearly 30% in the US, but it is constantly on the rise – renewables represented more than 50% of new capacity additions over the past four years.
But what will change the dynamic significantly for flexibility both on the demand and supply side is the growth in storage capacity, which doubled last year and is forecast to reach 4.5GW by 2024, according to Wood Mackenzie research. Of this, 42% is behind the meter and the majority of that is residential.
Potentially the greatest opportunity but also the greatest unknown comes from the increasing fleet of electric vehicles, which grew 48% year-on-year to 1.2 million by the end of 2018.
There is also a large potential for residential sector flexibility, with 23 million connected domestic distributed energy resources in the US and an estimated 47GW of available flexible demand by the end of this year.
Most of the currently available 32GW of demand-side flexibility in wholesale markets is from manufacturing and heating and cooling load control, and concentrated in the PJM and MISO regions covering states in the Northeast, Midwest and the South of North America. Batteries constitute only a small slice of this resource but this should grow as the regulator the Federal Energy Regulatory Commission’s (FERC) Order 841 opens up some value streams for storage assets.
The PJM service territory has about 9GW of emergency demand response resources, which is between 3-10% of peak installed capacity. The system operator has not activated an emergency load management event since 2013 and even on cold days, a maximum of 50MW accessed the market and found opportunity in economic demand response markets. Looking at what is making money it is apparent that the system operator’s short-term balancing needs are increasing. Until 2015 the majority of payouts were in real-time and day-ahead markets but in the last three to four years there has been a gradual increase in the slice of the pie coming from PJM’s regulation and synchronised reserves, for fast-responding reduction in energy use.
The MISO region is seeing a decrease in supply availability and tighter reserve margins due to aging and retirement of plants. There is a growing reliance on intermittent resources from interconnected neighbours. Managing non-summer outages has proved challenging – the operator had not called an emergency event in ten years until September 2017, and since then it has called five, mostly out of the outage season. The need for flexible resources is increasing and the operator has been working hard to find resources available at short notice. Prior to its most recent annual auction it applied to FERC for tariff changes to tighten requirements in order to increase short -term availability.
“There are a lot of exciting things happening, a lot of changes and a lot of figuring out how to work with an ever-changing system,” Kolo said.
The pace of change is accelerating due to the increase in renewables and environmentally-driven regulations. National environment regulator the Environmental Protection Agency regulations pushed out 20% of available fuel-based behind-the-meter-generation for demand response three years ago, while this year California banned fuel-based back-up generators from providing demand response altogether. It also introduced mandatory rooftop solar panels for new builds starting next year.
Another important regulatory development to follow is the FERC proceeding on the aggregation of distributed energy resources which may not see a ruling for at least six months but is gaining a lot of traction politically, Kolo said. “It will be interesting to see how this and FERC Order 841 work together and don’t create additional barriers to entry,” she added.
As the resource mix changes, technology vendors are pushing boundaries. There are many examples of innovative ‘aggregator of aggregator’, virtual power plant and other programmes such as the Enel X eMotorWerks company with 30MW of flexibility from 10,000 Honda electric vehicles in California, an iES pilot aggregating flexibility from high rise buildings for ancillary services in New York and Sunrun and National Grid working together on 20MW from residential solar plus storage in New England. Markets have to adapt to allow for these resources to be co-optimised those both in front of and behind the meter and to interact with wholesale markets. Market design can be a major barrier, for example the problem of double charging battery storage when power is taken on and off the grid.
Software intelligence is key to aggregating and orchestrating these new assets for retailers. Acquiring and engaging customers is expensive and most of these retail programmes run at break-even for a few years in a row, but having a flexible portfolio ready to go when required is important. “This generation/supply/distribution co-optimisation at scale has not yet been proven but there’s no doubt it will be as we are seeing this dynamic change in our market. Maybe the rules are not there yet but the technology is – folks are thinking in innovative ways and we will continue to see aggregation models pop up,” Kolo said.
Wood Mackenzie will publish a report soon on flexibility, she said.