Electric power systems are experiencing a time of unprecedented transformation, due in part to decades of underfunding and a heavy dependence on electricity. Existing centralized systems are not able to give the desired output or performance, nor are they efficient enough environmentally or economically. But in the last decade, smaller, decentralized resources have replaced these centralized power systems. This has led to our transmission and distribution system to grow increasingly distributed, but the intelligence and automation capabilities remain under-utilized. So far, the transition to smarter grid technologies has not been sufficient to meet the increased needs of electric vehicles, batteries, transactive energy markets, and new regulations.
This brings us to the future of energy. In the coming years, energy consumers and prosumers will participate in an integrated platform model that facilitates two-way value transactions between distributed energy resources (DERs) to ensure a more reliable, affordable and sustainable energy system.
This article outlines the challenges faced by today’s infrastructure and what technologies and processes are needed to mitigate those challenges and allow the grid to continue to provide reliable energy in an increasingly decentralized energy network.
What are the common challenges faced by managing the aging power systems of today?
The grid of today is characterized by bulk and distribution technologies and policies designed to manage one-way energy flow from bulk generators to distribution customers. At the bulk level, resources are dynamically priced and valued, but those grid operators are blind to most DER capabilities. At the distribution level, resources are generally sited and operated based on annual contracts that do not fully consider the dynamic capabilities of DERs, but do allow for the bulk system to fully serve retail customers.
Even today, however, customers are increasingly self-supplying, and networks are entering the end of life for certain distribution and transmission assets. The increased self-supply is generally from intermittent resources that have certain control capabilities and create opportunities for enhanced demand management. Changing customer supply is due to the rise of electric vehicles and policy goals to decarbonize the grid.
As those policy goals and technologies continue to develop, grid assets will continue to age. The combination of those forces places the onus on grid operators, planners, and regulators to coordinate and determine a path forward that continues to serve customers reliably while meeting consumer demands and policy goals.
Coordinating those pulls and pushes will be software systems that can manage the complexity that is inherent to energy systems, which is only increasing as more assets join and modify the system’s supply and demand.
What technologies and processes are necessary to provide a reliable, efficient and resilient energy infrastructure?
In an increasingly decentralized energy network, here are some of the technologies and processes utility companies can implement to prepare for change:
1. Grid-edge resources with coordinating controls and new business models
- More DERs are being deployed behind-the-meter at various stages of distribution: at the customer’s premises, at community level, at the utility level or aggregated at the fleet level. As a result, a complex array of ownership and operating models is becoming common.
- The rise of this spectrum of DER activity calls for the layering of an advanced grid that can show the physical network of flowing electrons, the transaction value for utilities, interact with DER participants as prosumers, and so on. To coordinate objectives and constraints, this platform should encompass a complete range of business models – including ownership, operating and revenue from Market-Based Earnings (MBE).
2. A sophisticated transactive energy management software
- With the proliferation of DERs, mechanisms allow for communication between the DER and the rest of the energy system to become increasingly necessary in order for distribution planners to make use of the DER’s capabilities and plan for their impacts.
- Moving past command and control of resources, coordination of those resources through use of economic signals brings us to a potential state in which transactions between the DER and network operators reduce system costs and mitigate system constraints. This approach to energy coordination is generally referred to as transactive energy.
- Policy changes are key to enabling shifts toward new DER-to-Network business models and move the grid past net energy metering or uncoordinated demand response. Changes such as FERC 2222, which allows the DER to participate in bulk markets, as well as Ofgem’s evaluation of flexibility, pave the way for the DER to be compensated and utilized based on its value across bulk and distribution systems.
- Making optimal physical and economic use of these resources may be done through better alignment of those communication systems and policies. As policy allows for DERs to participate in more markets, fully realizing those resources’ capabilities requires technological systems to be implemented that coordinate network operation and market participation.
3. A locational marginal value approach to transactive energy
- The traditional Bulk Electric System (BES) has established norms and laid a strong foundation for transactive energy mechanisms. The bulk system operators perform security constrained optimal power flow analyses on the transmission networks to compute generator dispatch schedules and Locational Marginal Prices (LMP). These prices reflect the quantified value of energy and ancillary services to the BES, considering factors such as the cost of generation and capacity constraints.
- Compensating and operating DERs calls for a similar approach to optimize dispatch and determine compensation based on locational and marginal valuation of net benefits to the bulk and distribution systems.
- Dispatch and LMP pricing methods can be extended from the BES to the distribution system, in order to capture distribution level constraints and benefits from DERs. These pricing mechanisms go beyond fixed price or time of day compensation for the DER, and incorporate DER system impacts including losses and congestion relief. Given sufficient data, the distribution LMP provides constantly updated time and location-specific quantification of DER value.
- Final use of these prices and dispatch advancements is to be determined. Certain users may want 5-minute prices and fully configurable bids and offers. Others may want annual contracts and for a third-party to manage bids and offers. The range of business models these advancements enable will allow new market participants to enter and specialize in optimizing their parts of the energy system value chain, ranging from customer management, to price risk, to network constraints.
