In real-estate, it’s location, location, location. In today’s evolving digital power grid, location certainly matters – but so does time.

The cost to deliver power to specific locations throughout the day varies with time. Regulators, however, have been reluctant to allow this marginal cost differential to be incorporated into rates that residential and commercial/industrial customers pay. Instead, rates have been structured according to an average of costs across the operating day.

There have been two primary arguments made by utilities and regulators against such a time-and-location approach. First, it is difficult for customers to understand. Second, it would be costly for utilities to meter. But thanks to the availability of digital technologies like smart meters and other Internet-enabled devices; intelligent software enabling multiple operating modes for distributed energy resources, such as energy storage; and more sophisticated distribution platforms, time-and-locational based pricing is now possible.

We know, because Enel X customers have leveraged these tools to take advantage of retail supply rates that are locational AND time based, creating greater efficiency, resiliency, and savings.

Making it in New York

In New York, for example, utilities have used locational-based marginal pricing for wholesale electricity supply that varies by zone and time of day. This model was developed almost two decades ago, when the state deregulated the vertical utilities into distribution-only entities and established the Independent System Operator (NYISO). The next step was to take this model to the next level, recognizing that the market was shifting, technology had advanced, renewables were proliferating, and resiliency was paramount.

The state looked at ways to develop a more responsive and efficient grid and began rethinking how third-party developers could take part in a new operating model. Building out new renewables and other Distributed Energy Resources (DERs) at the edge of the grid could help maintain power during extended outages, but those activities would also solve another challenge – meeting peak demand on critical power days.

In 2015, in response to the reality of climate change and the impact of Hurricane Sandy, the New York Public Service Commission and state administrators decided to move forward with a new policy approach called Reforming the Energy Vision (REV). The basis of REV is to work toward transforming existing distribution providers into “platform providers,” thus developing a formalized way for energy use and production to intermix in the distribution system. As part of this, they laid the foundation for developing the market for DERs.

Ultimately, the state wants to create a way for those who are willing to voluntarily participate to react to price signals based on supply and demand. When the local distribution grid needs power to support excess demand, the price will be high for users that can’t reduce load or export surplus generation. When there’s an oversupply, the price will be low – and could even be negative, with excess looking for load to supply. The platform will be the marketplace, where two-way power flow becomes “transactive.”

But can it be done? (Hint: it’s already happening)

There are skeptics who doubt that such a transactive rate structure will materialize, but it’s been done at the wholesale level for years under NYISO. At the start, there were many critics of the market concept, with some predicting that the grid would collapse. The reality is, the grid must stay in balance – so the laws of supply and demand help set pricing throughout the day. The grid is elastic and responds to price, and this dynamic has led to variable pricing for Demand Energy’s commercial customers in New York City.

In the broader distribution market, supply and demand will drive value for utilities and their customers – and time is a key factor. Different parts of the city peak at different times. In Con Edison’s distribution network, for example, there are four different peak periods. Heavy commercial business networks peak from 11:00 am to 3:00 pm. In areas with a blend of businesses and commercial retail space, the local grid peaks from 2:00 to 6:00 pm. Where there is a mix of businesses with some residential, the peak is from 4:00 to 8:00 pm. Finally, in predominantly residential areas, that peak from 7:00 to 11:00 pm, there are a lot of open rooftops with good exposure for solar PV. There the need for peaking power is in the evening when the sun is fading.

So where is all this headed?

As we move forward, it becomes clear how time and location are both key to creating a path forward to develop a resilient, renewables-based energy grid. Demand can be supported by supply in a value-based market, with third parties participating under the control of the platform provider (i.e. Distribution Service Operator).

Our view is that to “animate” the market, we need to develop a more granular-type rate by dissecting the (existing) daily as-used demand charge into hourly prices, with a substantial differential for peak versus non-peak hours. This would be a voluntary rate that would give customers the ability to manage load during the four peak hours on a given network. By using price as the signal for customers to manage or adjust load (or generation), we will start to move towards a transactive energy market – and a Grid 2.0 business model.

We would say it’s about time!