Assessing the costs and benefits of distributed energy to the grid of the future

EPRI is perfecting a method to evaluate the impact of DERs on all stakeholders

The question about distributed energy resources (DERs) is no longer whether the system can handle them, but what their costs and benefits to the system are, according to the Electric Power Research Institute (EPRI).

EPRI, created in the 1960s to help safeguard the U.S. grid, is now engaged in a three-year process to identify reliable and affordable ways for utilities and grid operators to take advantage of the new ways electricity is produced, delivered, and used.

DERs “are connected into the system but not integrated,” explained EPRI Washington Relations Director Barbara Tyran at GTM’s Grid Edge 2015 conference.

EPRI is taking on that integration with a three-phase research investigation into the costs and benefits of DERs to the system.

The first phase of EPRI’s work on integration culminated in a February 2014 report, entitled "The Integrated Grid: Realizing the Full Value of Central and Distributed Energy Resources." Tyran called it a “concept” paper.

It argued the resilience of the system could be compromised by DER variability if grid operators fail to incorporate new planning, procedures, and smart capabilities.

The purpose of the integrated grid is to enable utility customers to have the same range of technology choices from their electricity providers as they have in other areas of their lives, Tyran explained. 

Now, another report, "The Integrated Grid; A Benefit-Cost Framework," focuses on how “society in general will benefit from all the individual customer choices,” she said.

“At EPRI we have 750 engineers and scientists who say it is an engineering problem that can be solved, but we need to get on it and invest in it and we need to do the necessary R&D.”

The DER conundrum

EPRI's paper begins by defining DERs as electricity supply that is interconnected to the grid “at or below IEEE medium voltage (69 kV)” and either (1) generates electricity with a primary fuel source, (2) stores energy to supply electricity to the grid, or (3) involves load changes by end-use customers in response to price or other inducements.

With increasing DER penetration, customers are creating an unprecedented two-way power flow. They are generating and selling electricity into the system while the flow of base load electricity from central stations continues. “But the system was not designed for two way power flow,” Tyran explained.

EPRI engineers are working to design a system with embedded communication intelligence. Sensors in the power delivery infrastructure would optimize the value both of DERs and of traditional base load generation.

“That will give the system operator the situational awareness to understand how to best manage that system for the benefit of everyone, including society,” Tyran said.


The need for a new way to value DERs

It is not necessarily clear to all stakeholders that the benefits for such system upgrades are worth the costs, but EPRI’s benefit-cost framework “defines the tools, protocols, and methods necessary to conduct consistent, repeatable, and transparent studies to anticipate and accommodate DER,” the paper explains.

The intention is to streamline “understanding of the net benefits of DER and how to maximize them” and to reduce the cost and time invested in competing studies “being conducted in isolation using different approaches and reporting results differently.” Because the EPRI study is “rooted in the fundamentals of power system engineering and economics," its authors say its is applicable to "all regions, systems, markets, technologies, and research questions."

Dispatch is no longer about baseload generation and a forecastable load, Tyran said in explaining the paper. In a world with proliferating devices powered by electricity, demand will be “much less forecastable,” she said.

Supply is also changing. Many states, for instance, have renewables mandates that require first dispatch of variable renewables, Tyran noted. “It is a problem that can be solved but it is one that needs to be addressed.”

With consumers becoming energy producers, all the components of the power system become involved, Tyran said. The addition of the interactive and dynamic technologies imposes new burdens on transmission and distribution infrastructure, she said. Some fear fluctuations in load and supply could challenge present standards of reliability.

DERs can, for example, “adversely affect circuit voltage, which requires mitigation costs,” the paper details. Smart inverters can mitigate such affects and eliminate the need for infrastructure upgrades. A consistent valuation methodology is needed to determine whether to account for that benefit at the local or system level.

Fossil and nuclear base load generation, which in the past operated at full capacity to maximize the value of the assets, will now be tasked with ramping in response to renewables’ availability

“It is like asking an Indy race car driver to operate as a taxi in Manhattan," Tyran said. 

EPRI engineers say it can be done but to bear the extra wear and tear, she explained, the assets will require more “robust materials.”

“EPRI is studying nuclear plants to determine how best to operate them so that they can provide some types of flexibility,” the paper reports. “Coal plants have already been retrofitted in some areas to provide lower minimum output and higher ramp rates.” Hydro can be retrofitted either “by improving speed of response or, more significantly, by adding pump-back capability” and new ways of scheduling are being studied.

A more flexible conventional fleet, according to EPRI’s paper, could:

  • address variability by more efficiently managing turndown and start times
  • improve resource and flexibility adequacy by reducing the likelihood of insufficient capacity and the loss of load
  • reduce challenges to frequency and voltage stability simply by having more generation online

Obtaining these benefits will necessitate capital investment and operating costs.

Capital investment will go to new generation or existing plant retrofits. A challenge for the methodology will be accounting for the capital investment necessitated by DER expansion and separating it from the part due to normal load growth or plant retirements. 

“What needs to be captured is the cost of the additional flexibility needed to manage DER integration relative to the capacity that may have been developed for other reasons," the paper explains.

Dealing with operating costs is more straightforward. Getting more flexibility services from conventional plants will increase parts replacement and labor maintenance costs, costs for increased labor and training of operators, and increased policy compliance costs, the paper reports.

“An increased outage rate may also be a consequence, resulting in reduced revenue to the plants and higher system supply costs because more expensive generation is used,” it warns.


The benefit-cost framework

“With the benefit-cost framework, we are doing scenarios and modeling to look at all these relationships,” Tyran explained. “How do we increase the penetrations of DERs on the system without congesting the system or compromising its integrity or creating some sort of outage?”

The methodology provides “an end-to-end analysis that starts with identifying individual feeder impacts and works outward to trace the consequence of those impacts through the bulk power system,” the paper explains. With it, planners and system operators can “anticipate and understand how to maximize the net benefits from DER interconnections.”

The benefits of DERs can reach beyond the local delivery system to the bulk power system “where fuel costs may be saved, asset investments deferred or avoided, and emissions reduced,” the paper reports. The EPRI benefit-cost framework “traces these benefit and cost streams from their point of emanation to their monetary manifestation.”

The framework “allows utilities to individually tailor a study to their circumstances and assess the most relevant alternatives,” it explains. It “does not stipulate which alternatives should be pursued or how the costs incurred from those that are pursued should be recovered — that is left to the responsible stakeholders.”

EPRI's cost-benefit analysis.

The final phase

The final phase of EPRI’s grid integration work will take its engineers and scientists out of their labs and away from simulations and modeling.

Over the next few years, “we are going to take this to host utilities and set up pilot projects. Not every system, not every line, but strategically, where we can get the greatest learning,” Tyran said

EPRI expects to identify the gaps in research and development that need to be filled and are especially interested in the granular information they can get about individual feeders, Tyran said. 

“Each feeder is unique like a snowflake and we need to understand the attributes and how to penetrate with DER in the best possible way.”

Like the papers on the work in the first two phases, the results from the pilot projects will be made public. “The energy sector should be engaged,” Tyran said. “There are decisions ahead."

Filed Under: Generation Transmission & Distribution Solar & Renewables Distributed Energy Efficiency & Demand Response Technology
Top image credit: Flickr; Energy.gov