As the energy industry shifts toward cleaner and more sustainable models, it becomes increasingly critical for utilities to be able to manage and control the customer side of the power grid. One proven way to do that, Demand Response (DR) programs, have been common for many years. These programs typically incentivize participants to shift their energy usage away from peak consumption times, in order to reduce dependence on costly and inefficient peaking power plants and to overcome weaknesses in transmission and distribution systems. In most cases, DR programs use either direct energy reduction/increase requests or variable price messages to attract customers to participate.

Distributed Energy Resources (DER), however, now vastly increase the complexity of demand-side control by introducing more generation assets at the expense of grid reliability and power quality. Industry communications and connectivity standards, like OpenADR, which have long helped utilities manage DR resources, can now also play a similar role with the growing pool of diverse DERs. The latter not only includes renewable energy but also energy storage, electric vehicles (EV), and EV charging – as well as traditional DR targets.

But how much control do utility operators need to effectively manage all the resources in their power grid? This question still seems open ended at this point in time, though there are some use cases and models available that can help establish some ground rules.

In our view, DERs can be categorized in two groups based on size and ownership. However, there is a gray area between the two that will have to be addressed in the future as well.

1. Large, utility-controlled systems

It makes sense that distributed power generators, battery storage, and resources of any kind with capacities larger than a certain (as yet undefined) threshold need to be controlled by the utility operator. Just like a fossil fuel or nuclear power plant, the generation capability of these large-scale DERs is and will be vital for the grid stability – and we can assume that there are not too many of these resources around. Therefore, tying them into the control network of the utility appears to be the right thing to do. Cyberattacks can also be kept in check with this limited number of endpoints.

1. Small, customer-owned systems

On the other side of the scale, we find the (truly) distributed resources, such as privately owned residential solar, EVs, home batteries, and the like. These DERs, taken together in functional or geographical groups, will also represent a large percentage of future generation and will somehow have to be managed by the grid operator. However, there are several challenges. Such resources are not owned by the utility but by the customer, so full access to the controls may not be readily granted by owners. Further, we are now talking about thousands, if not millions, of small-scale systems. Addressing and controlling every one of them will be challenging from a data connectivity, analysis, and cybersecurity perspective.

On the horizon

Moving forward, utilities and grid operators will generally have to decide which resources fall into which of the above categories. There are also some regulatory efforts currently being explored on how to manage smart inverters (for example). One such regulation is California Rule 21 CSIP (Common Smart Inverter Profile - http://www.cpuc.ca.gov/general.aspx?id=4154). Rule 21 requires that smart inverters open up their control interface, either using the framework’s default interface based on the IEEE 2030.5 control standard, or using other established standards upon mutual agreement between utilities and resource owners. One of these alternatives can be OpenADR.

As a comparison, IEEE 2030.5 provides direct device control functions to set parameters like Volt/VAR curves and many other values in each inverter. OpenADR, on the other hand, enables grid operators to use a standard to communicate higher-level requirements, objectives, and incentives (not unlike DR programs) to aggregators, control systems, consumers, and – if really needed - to inverters directly, to empower them to modify their associated DERs and contribute to the grid’s stability. Rather than directly controlling DER resources, OpenADR informs the customer and motivates them to act, based on pre-programmed or dynamic sequences of operations. Many of the Rule 21 CSIP requirements can already be covered by OpenADR 2.0b in this fashion, and the OpenADR Alliance is developing additional extensions where needed. 

Another much discussed (but not yet too commonly implemented) aspect of DER control is Transactive Energy (TE) messaging. There are many definitions for TE, but the basic premise remains the same in most of them: DRs and DERs can trade their energy generation or usage with utilities, or, in an even more distributed future, among themselves. Utilities can offer spot prices for energy just like other product retailers and see if specific customer segments will buy or sell energy into the market.

A recent, almost-completed California project successfully demonstrated its technical implementation and the willingness of customers to react to price offers (albeit in a system-to-system communication scenario based on preset price levels and actions). More information can be found at https://rates.energy/. Several other similar projects are in the works, many of them using OpenADR.

So what’s next? The OpenADR Alliance is closely following emerging use cases and business models for Distributed Energy Resources and Transactive Energy. While the base specification OpenADR 2.0b (also known as IEC 62746-10-1: 2018) will remain unchanged, the Alliance is working on extensions for additional DER management, grouping, and TE messaging.