Location, Location, Location - and Time - and Performance: Valuing Distributed Energy Resources for Distribution Systems
By Shay Bahramirad & Daniel Kushner
Consumers, policymakers, and utilities are increasingly aware of the benefits that Distributed Energy Resources (DERs) can offer– reliability, economics, sustainability, and resiliency. Fulfilling the promise of this technological innovation, however, is only possible if DER owners receive fair compensation for the services they provide. In 2016, the Illinois State Legislature passed the Future Energy Jobs Act (FEJA) to set a path towards the establishment of DER valuation process to further compensate future DERs for the services they provide to the distribution grid. The primary way that DERs can provide value to the distribution grid is by deferring traditional grid upgrades. If DERs can provide sufficient real power, reactive power, or reserves at the right place and time, a planned upgrade may be deferred. This can reduce the costs of grid design and operations, which are translated into value for customers.
Realizing these benefits at lower costs than conventional solutions requires precision in estimating and designing DER compensation mechanisms. Simple umbrella incentives unrelated to specific avoided costs become another DER subsidy without providing a fair, situational compensation as it relates to the true impact it makes to the grid. If a DER is not in the right location or able to provide the required product (real power, reactive power, or reserves) at exactly when the overload or voltage issues would otherwise occur, then the traditional grid capacity upgrade would still be necessary.
Quantifying the monetary value of this grid upgrade deferral is similarly essential; undercompensating the DER owner would not provide the incentives to sustain the deployment of this technology, while overcompensating could overly inflate the cost of the system. Additionally, there is a need to measure the grid benefits provided by DER in a way that is efficient, maximizing the flexibility of the system to make it possible to continue deferring large investments to accommodate for load growth. It is also important to avoid or minimize cross-subsidies and be fair to customers that are not deploying DER. On state and federal levels other benefits of DER such as potential reductions in emissions and reduced wholesale power costs are typically dealt with through production incentives and reduced market clearing prices or investment credits, such as the distributed generation incentives included in FEJA.
ComEd, the electric utility serving more than 4 million customers in Chicago and Northern Illinois, has partnered with industry leaders to develop a methodology to address this challenge. This methodology is technology-agnostic and focuses on the services that DER can provide (real power, reactive power, or reserves at a given place and a given time), rather than the type of DER. In other words, if a specific power generation is needed at a particular segment of a distribution feeder, this methodology would provide the same compensation whether that real power was generated by a solar-storage unit, a diesel generator, or energy efficiency. To determine the value, there are two main steps:
- The first step is to do an annual analysis (i.e., an 8760-hour study) of a feeder with projected future loads and DER. Traditionally, electric utilities plan for the peak, ensuring that there is sufficient capacity to meet that load. Calculating the temporal value of DER to a particular station or feeder, however, requires an hourly analysis.
- Next, a locational analysis of the constraint and potential location for the DER is needed. Certainly, if a DER is not on the feeder where a planned upgrade would be needed, its value to the grid is non-existent. Similarly, if no upgrade is needed a utility would not build excess capacity.
Locational Marginal Value (LMV) is the desired unit for real or reactive power generation of a DER at each node in the distribution grid. The LMV is the value of an increment in a DER dispatch in avoiding traditional capacity upgrade costs. In order to calculate the LMV, the costs of traditional upgrades are allocated to the grid locations where the thermal overloads and/or voltage violations (under and over voltage) are projected to occur. This projection will be on an hourly basis and according to the amount of limit violations. This results in a Marginal Cost of Capacity (MCC) at each nodal location, which can be used as a penalty in the function that values DER in a distribution locational marginal pricing concept that derives the LMV as the shadow (marginal) cost of the grid constraints.
MCC allows developing DER valuation based on location and time against shadow capacity investment costs when compared to traditional investments. This would then support the locational marginal valuation of a given DER. The LMV of any DER asset is defined as the sum of the marginal value of real power, reactive power, and reserve provided by that asset at any point in time. The hourly LMV values can in turn be used to determine the value of specific DER technologies such as solar PV, demand response, energy efficiency, CHP, electric vehicles, and battery energy storage on the basis of avoided annualized investment over a pre-determined timeframe. These values could then be posted in a fashion similar to how solar PV Hosting Capacity are posted today.
Though it has been previously suggested that approximations of issues like the power factor improvement provided by a DER could be used, a high-fidelity AC analysis is required in order to evaluate the effects of DER. The reason is that voltage and thermal issues can vary significantly even on a given feeder, and only if the calculation is conducted for the node where the DER is installed it can be possible to compensate the DER owners fairly for their service to the grid.
Today, when capturing the impact of aggregated DERs at the regional level, the DER locational value is overlooked. At the distribution level, understanding the impact of DERs is critical to providing reliable, good quality power to the customers. Therefore, instead of a top-down approach that deals with aggregated DER, a bottoms-up approach is necessary. In principle, increasing the planning granularity from the feeder to the segment all the way to the nodal level can help valuing DER efficiently and effectively. In valuing DER through their contribution to relieving locational and temporal issues, system wide voltage and thermal issues can be resolved. This methodology has already been tested on more than a dozen of distribution feeders with projected upgrades on ComEd’s system to show its effectiveness.
This work represents a key step in building the grid of the future in which many types of DER can support a grid that produces the higher level of service that the society, with ever increasing demands of high quality power, requires. The proposed methodology in DER valuation is being developed by having fairness, efficiency and accuracy in mind so it can support a distribution grid with higher penetrations of lower carbon DER that can further reduce the carbon footprint of the grid.
Dr. Shay Bahramirad serves as a strategic business leader in Commonwealth Edison, the electric utility serving Northern Illinois including Chicago, working on the 21st century power grid transformation and the new energy economy. She holds executive responsibility for ComEd’s vision of the grid of the future, ComEd system reliability, engineering, and planning, as well as developing frameworks for emerging technology roadmaps and investment strategies. Bahramirad is an IEEE Senior Member, an Editorial Board Member of Electricity Journal, an Adjunct Professor at the Illinois Institute of Technology, and the IEEE/PES Vice President of New Initiatives and Outreach, overseeing the organization’s engagement with policy makers globally, and developing strategies for next generation of standards and frameworks, including Smart Cities.
Daniel Kushner is a Senior Business Analyst in the Smart Grid and Technology group at Commonwealth Edison. He has worked on topics ranging from microgrids to electric vehicles, and published work on topics ranging from the smart grid to smart cities. He completed his Bachelor’s degree in history at Johns Hopkins University, and his doctorate in political science at Brown University.