The U.S. utility industry has a blind spot, one that becomes increasingly evident as disruptive pressures grow each year, whether they are punctuated weather events that are happening with more frequency or increased customer demand for greater flexibility at the grid edge. Looking at the majority of electric distribution networks across the country, most do not have much – if any – visibility into the edge of the grid. That blind spot leads to missed opportunities to react quickly to customer-sited generation, deploy demand-side solutions in real time, and triage prior to, during and after storms and other events. Adding visibility and optionality to low-voltage networks will lead to an optimized grid that can absorb, react and adapt as these disruptions inevitably occur.
Utilities have been watching aggregate energy use plateau or, in some cases, decrease, while peak use has been increasing, either in more populous load pockets or across their service territories. This shift is driving a need for better demand management solutions deployed beyond the substation that have shorter run times and rely less on the command-and-control paradigm that most demand response (DR) programs have historically had. Plus, the trend of growing peak use may continue as more electric vehicles (EV) are added to our roadways. As an industry, utility infrastructure may not be ready for the demand. In California alone, there is a statewide goal of 250,000 EV chargers by 2025 and 5 million zero emissions vehicles (ZEVs) on the road by 2030. Today there are fewer than 7,000 statewide, according to the Alternative Fuels Data Center.
This issue is here today. More customers are seeing the advantages of electric transportation and the share of homes and businesses with some mix of distributed generation and storage continues to increase. Without greater visibility into changes at the business or premise level, we will both miss out on opportunities to manage customer demand and generation while creating unnecessary vulnerabilities to customer service and reliability.
Fortunately, there are solutions. By increasing investments in distributed intelligence with the interoperability of OpenADR, utilities can create a more flexible, reliable and interactive grid.
Distributed Intelligence
There are multiple examples of large commercial and industrial (C&I) sites deploying sophisticated energy and demand management solutions that help balance internal load and increase renewable energy use. But utilities will not be able to fully address future challenges without deploying intelligent distribution assets to the mass market. These assets — like advanced meters, streetlights, connected thermostats and load-control switches — typically have embedded computational ability either through componentry or a network that are able to monitor and react to changes at the grid edge, thus allowing them to balance demand and other distribution assets.
Distributed intelligence allows utilities to achieve locational awareness (that is, self-awareness of the devices on the grid), deploy resources where they are needed before an incident occurs, and engage customers more directly. But it takes a combination of locational awareness on the grid and peer-to-peer communications at the network edge to deliver tangible benefits.
Distributed intelligence offers several advantages:
- It provides sub-second data resolution for higher accuracy in power flow and system asset monitoring.
- Because analysis and response are automated and decentralized, less back-office infrastructure and data science expertise are required.
- Device self-awareness greatly improves immediate services for the utility; for example, minimizing the length and severity of outages, ensuring uninterrupted network connectivity and maximizing theft detection.
- Distributed intelligence allows a utility to select a custom set of solutions (from an existing portfolio of solutions) that are best suited to the challenges across their territory. For example, a utility with greater EV penetration and charging infrastructure needs solutions that monitor transformer health, while a utility with greater adoption of rooftop solar needs to monitor power flow and immediate weather changes across its distribution network.
Demand Resources and OpenADR
While distributed intelligence allows for greater engagement with end-use customers, who will understand the long-term advantages, most of the direct short-term value is delivered through operational benefits. Still, direct customer engagement is becoming increasingly critical for utilities, and complementary demand-side solutions require both scale and dispatchability.
Related: How customer-centric should utilities be?
Contingencies on the grid have always threatened the supply-demand balance and market conditions that drive rising electricity costs have always been with us. In both cases, demand response has achieved a long track record of delivering value.
Mass-Market DR
Most third-party demand response solutions are focused on large C&I users, and for good reason. They are easier to identify, engage and manage. Mass-market solutions — those delivered to residential and small commercial customers — are more challenging to address but equally critical.
Only a few companies are addressing mass-market demand response, either in competitive or vertical markets, and the differences between those programs and C&I can be daunting: customer demand curves are far from uniform, customer comfort is paramount, annual churn in some markets is very high, connected devices often depend on less-than-dependable residential Wi-Fi, and premise-by-premise marketing is often necessary. Because of these challenges, mass-market DR programs have, to date, been largely structured and managed specifically for each deployment.
OpenADR
What is arguably the most substantial advance in managing energy and harnessing the mass market is taking place now. The OpenADR Alliance introduced the OpenADR standard shortly after the California Energy Crisis of 2002, introducing a foundation and an architecture for interoperable information exchange with customers to facilitate automated demand response. That standard has evolved over the years, and OpenADR 2.0 shows promise as the emerging standard for communicating price and reliability signals.
The OpenADR 2.0 data model allows interaction with building and industrial control systems that are pre”programmed to take action based on a DR signal, enabling each demand response event to be fully automated — that is, requiring no manual intervention.
The standard also identifies event name and identification, event status, operating mode, various enumerations (a fixed set of values characterizing the event), reliability and emergency signals, renewable generation status, market participation data (such as bids) and test signals.
OpenADR 2.0 also standardizes the message format used for ADR so that dynamic price and reliability signals can be delivered in a uniform and interoperable fashion among utilities, ISOs and energy management and control systems.
From a practitioner’s perspective, the primary advantage of OpenADR is that it allows mass-market DR providers to avoid the need for a new application program interface (API) to be written for each deployment. That means, essentially, that the software component of each DR program does not need to be largely structured from the ground up each time – thus creating new opportunities to achieve scale, interoperability, and cost savings.
Integrating DI and OpenADR to Improve Scalability and Speed to Market
Combine distributed intelligence and OpenADR, and utilities have the two complementary and compelling solutions critical to grid modernization.
OpenADR provides a replicable, secure and scalable platform for energy management systems. Distributed intelligence monitors system health and includes other critical energy management endpoints, such as lighting control systems and distribution system interfaces.
Leveraging – and integrating – the OpenADR standard with new distributed intelligence technologies will enable utilities to optimize existing infrastructure, ultimately increasing reliability and resiliency, while lowering operational costs. Those benefits mean a more responsive, smart network and lower costs for end-user customers.
