In its new benefit-cost framework for an integrated grid, the Electric Power Research Institute (EPRI) is laying out a transparent, consistent and repeatable process through which utilities and others can use the methodology to evaluate the benefits of distributed energy storage, for instance, throughout the entire power system, and equally calculate the cost, according to EPRI president and CEO Michael Howard.
EPRI said in a Feb. 16 statement that its new report, “The integrated grid: A benefit-cost framework,” provides a framework for assessing the benefits and costs of technologies that will enable the grid to accommodate more distributed energy resources (DER) and bolster its reliability and resiliency.
Discussing the framework during the NARUC 2015 Winter Committee Meetings in Washington, D.C., on Feb. 16, TransmissionHub reported Howard said that one of the things that EPRI recognized early on is that with an integrated grid, one needs an integrated view of the benefits and cost.
“What we’re suggesting … is that what you really need to do is take a systems view because the benefit that you have — for example, distributed energy storage — is not just the benefit at the edge of the distribution system, but, if it is properly integrated, can provide a tremendous amount of benefit throughout the entire power system,” he said.
Howard also said, “[W]e’re suggesting that when you do a benefit-cost analysis, that you use our framework and that you look at not just through a straw, but you look at the entire power system and understand the impacts that it has to the customer, distribution system, transmission system [and] bulk generation throughout the whole system, and then, based on that, you calculate the overall benefit and cost.”
At last year’s NARUC meetings, Howard noted that EPRI had begun work on a three-phase initiative involving central and DER.
EPRI noted in its report that DERs are typically connected to the radial arms of the grid, but they have repercussions that resound throughout the electric system. Kilowatts generated on a distribution line can affect the performance of that circuit, the operation of the interconnected transmission system, and how the central generation fleet is dispatched, EPRI said, adding that those effects include benefits and costs.
EPRI said its benefit-cost methodology defines the tools, protocols and methods necessary to conduct consistent, repeatable and transparent studies to anticipate and accommodate DER. The framework is rooted in the fundamentals of power system engineering and economics.
The framework is composed of four core analytic elements that correspond to the steps undertaken to conduct a fully integrated system study, EPRI added, noting that it begins by specifying the core assumptions: market conditions, DER adoption and scenario definitions.
A study of DER integration starts by identifying and quantifying the distribution system impacts attributed to interconnected DER, which is done by conducting hosting capacity studies that determine the level of DER interconnection that can be locally accommodated without affecting the quality of supply for the existing infrastructure.
Subsequently, energy, capacity and reliability analyses are undertaken to identify designs and approaches that take advantage of the DER benefits while avoiding adverse impacts.
EPRI added that the bulk power system’s focus starts with resource adequacy, making sure that sufficient resources are available to meet electricity demand, and then, transmission expansion studies determine whether the power generated can be delivered to the distribution system without a drop in service reliability.
Three additional analyses – transmission performance, system flexibility and operations practices and simulation – ensure that all system benefits and impacts are considered.
Distribution and bulk power system analyses are done sequentially and, in some instances, iteratively, EPRI added, noting that the distribution studies describe how power flows change at the substation, where the two elements of the electric system come together. The first pass through an integrated analysis of DER accommodation calculates the distribution impacts and passes them for analysis to identify benefits and impacts at the bulk power system level.
The analyses at that level, EPRI added, may suggest that the best way to maximize DER benefits involves making changes to the distribution system.
The benefit-cost step is where the accumulated impacts are processed and measures of net benefits are built. It anticipates that a study requires a reference case — which may omit DER or include DER connected only at the time of the study — to establish a basis for comparing DER interconnection cases. Alternatively, EPRI added, the study may stipulate a level — or levels — of DER adoption and determine the impacts that result. Either approach launches a study that exposes the implications of different levels of DER adoption on distribution circuits, as well as different approaches for the related system design modifications.
Many of the impacts identified in the distribution and bulk power system analyses are costs or costs saved — the former incurred to mitigate adverse impacts, and the latter those that would have otherwise been incurred but are avoided, EPRI added. Other impacts define changes in the system that are tangible and should be identified and quantified but that are not readily monetized as they are not transacted in the electricity — or any — market. Emissions associated with electricity generation, changes in delivery reliability and changes in the economy are examples of externalities for which there are no market transactions to definitively set a value for their level.
EPRI also said that from a societal perspective, as many benefits and costs as possible should be monetized so that the net benefits derived are all-inclusive to reflect the interests of the utility and its customers, as well as those of all economic sectors and all citizens.
Discussing next steps, EPRI said that knowing the key drivers to the DER adoption decision — and forecasting how electricity demand changes as a result — are the first steps toward forecasting how much and what kinds of DER are likely to be interconnected.
Noting that the complexities brought about by DER integration require the development of new planning tools and operating methods, EPRI said that improved modeling capability is essential for devising operational strategies that realize the benefits that are possible.
EPRI also noted that storage and demand response can mitigate some of the adverse impacts of DER, but how they affect distribution system operation must be better-characterized and incorporated into dynamic system models. While standards can play a significant role in DER accommodation in the distribution system, finding the necessary consensus on what they entail requires substantial impact and implications modeling support.
In addition, EPRI said that the temporal nature and nuances of the bulk power system require dynamic load modeling and forecasting capabilities along with probabilistic capacity adequacy analyses to account for the inherently intermittent nature of supply of some DER, and the same holds for assessing impacts on the transmission system. Distribution planning models need to be integrated with those of the bulk power system for planning to be truly integrated, according to EPRI.
EPRI proposed that pilots be launched to test technologies such as:
· Utility-scale photovoltaic, with and without energy storage. Pilots are needed to confirm the level and timing of the output of the PV system and to ensure that interconnection and grid coordination systems operate as designed — and that the design itself achieves effective integration.
· Distributed storage — customer-side systems — operated in conjunction with intermittent DER. Field tests are needed to confirm that storage coordination strategies that appear to be beneficial to the customer and the grid are in fact beneficial when operated on the premises of consumers and businesses to serve their interests.
· Microgrids serve local customers’ needs for greater electric service reliability and resiliency, and can also serve as a system support asset, but the benefits are speculative until confirmed in practical applications in which systems are fully interconnected with and operated in coordination with the grid.
· Electric vehicle (EV) charging infrastructure can be built to serve the needs of EVs but operated to achieve grid benefits as well. The operation of at-scale facilities will resolve how the system is affected.
· Customer-side technologies, such as PV — with and without storage — and devices used by customers to control when and how much electricity they use.
Howard noted that one of the things that EPRI has determined over many years of work “is that you really don’t know the full benefit and the full cost until you test” the technology at scale.
Many utilities have expressed a strong interest in being part of the pilot projects, he said.
Of utility-scale solar, for instance, Howard noted that it will be tested at multiple locations because how utility-scale solar works, how it gets connected and integrated into the distribution system in one place is different from another location. Those important issues need to be, not just simulated in a lab, but also fully tested, he said, adding, “We need your help and we need you to get engaged with us on these projects.”
Noting that collaboration is key, EPRI said in its report that it intends to engage with utilities around the world, NARUC and the U.S. Department of Energy, among others, to apply and hone the benefit-cost framework.