The emergence of increasingly cost-effective distributed energy resources (DER), coupled with the pace of change in communication technologies, has led us to an inflection point in the electric utility industry. In response, and to help guide industry discussion, EPRI is conducting research to define the role of “the integrated grid” in a world with a growing presence of DER. EPRI and EEI collaborated to host a two-day workshop held July 10-11 in Washington D.C., where industry experts, representing a variety of perspectives, discussed topics covered in EPRI’s Integrated Grid Phase 1 paper: Realizing the Full Value of Central and Distributed Energy Resources. Three panels covering the customer, the distribution system, and the transmission-distribution interface served to focus presentations and subsequent discussion. What ensued was a lively debate and great deal of thoughtful reflection. Some questions remained unanswered, and others spurred more questions. In the end, participants identified the beginnings of common themes and points of agreement on priorities and next steps.
As I consider the meaning of the take-aways and the themes that I heard there, a few key questions come to mind, which I think should be the focus of continued industry dialogue.
1. As the industry adapts to the growing presence of DER, will the distribution system become simply a “smarter” version of itself, or will it be something more?
The Distribution System Operator (DSO) concept rolled out over the last year has sparked a great deal of conversation about the future role of the utility in organized markets where Transmission System Operators (TSOs) are unlikely to be able to efficiently manage distribution systems that look every bit as complex as today’s transmission systems. This is a fascinating debate that has the potential to help define the place for many traditional utilities in a future with a high penetration of DER. There are still many unanswered questions, such as how entities would interface and what types of data exchange would be required, the level of visibility (and control) TSOs and DSOs would need to real-time data from DERs on the distribution system, and whether DSOs would engage in economic optimization functions. Even so, this idea holds great promise and should be further developed.
2. There are fundamental “no regret” investments that can be made today. What are the core set of changes to our organizations and infrastructure that are valuable no matter which path this journey takes us?
Such investments can be identified and refined through scenario planning and industry collaboration. Good efforts have begun, but there is more work to do. Culture change in established institutions, investment in communication technology and the two-way enabling of the distribution grid, developing and adopting standards and industry guidelines for integrating DER are all likely no regret strategies. We also need to be looking to new load-resource balance scenarios for the future, thinking outside the ‘peak and RPS’ paradigms to consider new patterns, such as winter dusk, summer noon, and cloudy days. Learning from and adapting both the successes and mistakes of others should be the focus of industry research going forward.
3. In the future, network value may be defined by the number of connections, or uses of the grid, rather than energy throughput. As its nature and uses change, how do we judge the “value” of having a grid?
Under this paradigm, network value increases with the number of distribution grid interconnections and transactions, which may or may not include traditional utilities as a counter party. The distribution utility is likely the best suited to build and operate this network of the future, and should perhaps think of this as the foundation of their business model. Rather than focusing on the development of new products and services for customers, utilities should perhaps be considering how to create the transactional platform that enables the adoption of the ever changing demands and preferences of their customer base. However, the current regulatory paradigm and legacy pricing structures do not readily enable the transition to a viable business model that no longer depends on energy throughput as the basis for compensation.
4. How can we engage key stakeholders in the dialogue to try and address the policy considerations as a tool to help enable the necessary technological changes?
The most challenging hurdles to a successful industry transition to the integrated grid of the future will be more business model related than technologically driven. The need for change in longstanding views on policy considerations such as product pricing, utility cost recovery, and other regulatory boundaries need to be reconsidered. Some days this feels like a much larger hurdle than identifying the necessary technological break-throughs. There is a clear disconnect between this future and the current revenue model that rewards throughput and the legacy of ‘just and reasonable rates based on investment in plant’. As we think about how and whether we can change this paradigm, we need to remember that there are many non-technical aspects of this discussion that are being treated as constraints, such as legal precedent, regulation, and pricing. These can all be changed. What we need going forward is a broad collaboration across the diverse set of stakeholders that make up this industry.
Two things that can’t be emphasized enough as we move forward in this transition are 1) the importance of providing services and products customers want and 2) the importance of planning for an increasingly uncertain future. We need better tools and processes to accommodate customer preferences and, as an industry, we need to define a roadmap for how to get ahead of this change. This roadmap should include consideration of what will likely remain the same, what will inevitably need to change, and thoughts on the nature and time frame of such a transition.
What do you think the key challenges of the future will hold for the industry?