As more solar connects to the transmission and distribution grid, solar developers should not lose sight of additional market compensation for the value they provide to the grid. Today in the industry, we have an energy price that shows the marginal cost of serving energy, but we don’t know the marginal cost of providing grid balancing services.
If the Federal Energy Regulatory Commission (FERC) believes distributed energy resources (DERs) — of which solar PV is a major component — are beneficial to the grid, FERC should open additional market compensation mechanisms for DERs. If FERC doesn’t do this, only transmission utilities may be able to provide those services. Since wholesale market changes are expensive, one incremental approach involves a zonal price for a service such as reactive supply and voltage control.
The problem
For power to be transferred from point A to point B, voltage, angle, and frequency should be balanced. Another way to think about this is active and reactive power. For efficient power transfer, we need both active and reactive power. Today, even in organized markets where energy, capacity, and ancillary services exist — these grid balancing services such as blackstart (bringing the grid back from a complete outage), reactive supply, and voltage control — are settled at the transmission node, not at the market node.
In other words, we have an energy price that indicates the marginal cost of serving energy that includes congestion and transmission loss components at each market node in the organized market. But reactive supply and voltage control is settled at the transmission utility level, not transparently at the market node where competition exists to provide the least cost.
FERC and ISOs are aware of the issue
PJM’s Reactive Reserves and Generator D-curves, in FERC docket AD14-7, are still open before the federal commission. CAISO had a straw proposal for reactive power and financial compensations 5 years ago and left it alone.
FERC staff wrote a report on the reactive power supply and compensation in 2005 and have issued a final order 842 on February 15, 2018, that mandates providing primary frequency response for large and small generator interconnections. This reliability mandate does not address the market compensation issue.
NERC, in its role as the reliability regulator reporting to FERC, had brought the industry experts together on reactive power planning in 2017. But NERC’s interest is more compliance and reliability driven, not market-driven.
Why is compensating balancing services relevant now?
Due to the increased penetration of distributed energy resources, we would need more grid balancing services in the future. Because when we connect more inverter-based resources (converting direct current from solar to alternating current), the power system still needs active and reactive power. For power delivery, voltage, angle, and frequency are balanced.
One industry estimates 300 gigawatts (GW) of potential DER penetration due to FERC Order 2222 on DER Aggregation. Order 2222 defines Distributed Energy Resource as “any resource located on the distribution system, any subsystem thereof or behind a customer meter.” Compensation for DERs providing grid balancing services is needed.
This need for DER compensation is reflected in the industry today where we have seen manufacturers and system integrators acquiring DER services platform provider. For example, the Generac acquisition of Enbala and Fluence acquisition of Advanced Microgrid Solutions (AMS). Both Enbala and AMS provide DER optimization platforms.
FERC Order 2222 is a good first step in aggregating DERs and providing market opportunities at current organized markets for energy, capacity, and ancillary services. But, FERC Order 2222 does not touch on what additional services and market compensation could be needed in the future when DERs are a significant component of the resource portfolio.
The solution
In the industry, we need to start thinking about market platforms for DERs, including distributed solar providing these services. Since a single market improvement cannot solve the problem in one day, we need incremental market enhancements in each ISOs under FERC jurisdiction. The cost of enhancing Midcontinent ISO (MISO) market systems is approximately $150 million. The total cost of MISO operations today is $296 million. Hence, we need to think of incremental projects towards market enhancements rather than big-bang projects.
One incremental approach involves moving to a zonal-based approach to tag a price for services such as reactive supply and voltage control. The grid operator can release future reactive supply and voltage control needs on the system in each reserve zone, much like a planning reserve margin requirement study, and run a capacity market auction. This zonal based approach comes close to moving the industry from transmission settlements to market settlements.
