The Federal Energy Regulatory Commission (FERC) would find ISO-NE’s multiple market models troubling in the Order 2222 compliance filing. Even though the New England ISO has seven market participation models for aggregating DERs fairly, FERC should issue a deficiency letter because none of those models work due to the high cost of metering implementation.
One good thing out of the ISO-NE’s proposal is that it has found a way to allow for multi-nodal aggregation. FERC should ask other multi-state ISOs like SPP, MISO, and PJM why the New England multi-nodal aggregation would not work for them.
New England states clean energy commitments, and high energy costs are a slam-dunk for DERs
As the Advanced Energy Economy (AEE) presentation frames the DER picture at ISO-NE, there are already 7-8 GW of DERs in New England, and more to come due to state clean energy commitments such as:
• CT: 580 MW customer-sited storage by 2030; 150,000 EVs by 2025 / 500,000 EVs by 2030.
• MA: 300,000 EVs by 2025; 1,000 MWh of storage by 2025.
• ME: 400 MW storage by 2030; 41,000 EVs by 2025 / 219,000 EVs by 2030.
• RI: 43,000 EVs by 2025
• VT: 50,000 EVs by 2025.
According to FERC’s 2021 common metrics report recommended by the General Accountability Office (GAO) in 2008, New England ISO has the “highest total wholesale power costs, with capacity costs representing a significant component” due to its reliance on natural gas. Hence New England states are critical in lowering consumer costs. And New England ISO’s CEO is aware of the high costs during the winter season.
However, the five existing and two new market models don’t move the needle for DERs.
In aggregate, ISO-NE had good intentions going into the stakeholder process with new market models on top of the existing models. But coming out of the process, it missed the main objectives of leveling the playing field for distributed resources because none of the seven models work for most common use cases for DERs, such as standalone storage, solar+storage, EVs, hot water heaters, and smart HVAC.
ISONE expanded its existing 5 models for DER aggregation:
1. Generator Asset Model
The ISO expanded the existing Generator Asset Model to allow aggregation to comply with Order 2222. Small gas turbines can participate in this category. This category would not do much for DERs.
2. Continuous Storage Facility (CSF) and 3. Binary Storage Facility (BSF) models
The existing storage models CSF and BSF do not allow for aggregation. Hence the ISO has proposed a modification that allows aggregated DERs to participate as CSF and BSF if they are electric storage facilities. Fast-acting storage is CSF, and pumped hydro storage with charging and discharging cycles in hours instead of minutes and seconds falls under the BSF model at ISONE.
4. Alternative Technology Regulation Resource (ATRR) model
ISO-NE’s current ATRR model has a 1 MW size condition and a locational requirement that “prevents a resource from being selected to provide regulation if their sensitivity to a binding transmission constraint is above a threshold.” To be compliant with Order 2222, ISONE has reduced the size to 100 kW and modified the locational requirement such that all constituent DERs must be within the same Demand Response Resource Aggregation Zone. This last point minimizes the likelihood of congestion management issues for DERs participating as ATRR.
5. Demand Response Resource (DRR) model
ISONE has not proposed any changes to this existing DRR model because it is already compliant with Order 2222 as a standalone demand response model.
ISONE added 2 new models – DRDERA and SODERA
ISONE says that the new Demand Response Distributed Energy Resource Aggregation (DRDERA) model allows for demand response DER to aggregate with other types of DERs.
But one of the problems with the DRDERA model is that the ISO made energy market participation a pre-requisite for resources to spinning reserves. As AEE notes, no other ISO requires the load to be already dispatched for energy to provide spinning reserves. The other problem is more nuanced and concerns how demand reduction is calculated.
The second new model ISONE added for 2222 compliance was the Settlement Only Distributed Energy Resource Aggregation (SODERA) model that allows DERs to inject, withdraw, and participate in the forward capacity market and day-ahead and real-time energy markets. But SODERA resources cannot provide regulation or spinning reserves.
So, DRDERA allows for spinning reserve market opportunities, but the DER provider must participate in the energy market. The SODERA allows for capacity and energy markets but does not allow DERs to provide ancillary services like spin and regulation. Keeping track of which market participation model to use would be a nightmare for DER providers in New England.
Metering requirements are a big barrier for DERs hence AEE proposed Third Party Meter Reader (TPMR)
Spelling out metering and telemetry requirements for DERs in FERC Order 2222 is important because imposing generation resource requirements on distributed resources decreases the economic opportunity cost by increasing the market participation costs.
At ISO-NE, sub-metering (metering at individual DER asset level) is effectively prohibited because utilities do not support that, and ISO-NE is not allowing for 3rd party metering. Accordingly, all Distributed Energy Resource Aggregation (DERA) models require participation at the retail delivery. Separate resources at a site must have separate retail billing meters, which adds to the cost. Instead of reducing the cost of integrating distributed resources, ISO-NE’s proposal increases the cost.
AEE proposed amendment didn’t gather enough votes because utilities hold a majority of the votes at these RTO committee meetings. AEE’s amendment allows Aggregators or their authorized agents to meter the injection, withdrawal, and load reduction of all DERs within each DER Aggregation and report meter quantities.
The ISO benefits from this new Third Party Meter Reader (TPMR) because it approves qualified entities to provide meter services to DER Aggregations. This arrangement works at New York ISO (NYISO).
Allowing multi-nodal aggregations is a good thing!
Not everything is bad with ISONE’s proposal. Unlike PJM, ISO-NE allows for multi-nodal aggregation of DERs. The ISONE’s approach does not need distribution factors. As the ISO explains, having a DRR Aggregation Zone as a single pricing node in the NE market model forces the aggregated DERs to be offered, dispatched, and settled at that single node. But this comes at a cost. DERs greater than 5 MW must participate as a single asset, and only aggregations less than 5 MW can aggregate across multiple nodes.
It remains to be seen if FERC allows this multi-nodal approach because it is only multi-nodal for less than 5 MW resources. To New England’s credit, it has proposed an approach compared to MISO and SPP.
Like CAISO and NYISO, FERC should issue a deficiency letter to ISO-NE and ask the New England grid operator to explain why it has chosen to disregard AEE and AEMA stakeholder comments and amendments.
The ISO-NE has proposed a tiered implementation date for its capacity market (2nd qtr 2027) and energy plus ancillary services market (4th qtr 2026). Comments are due in the docket ER22-983 by April 1st 2022.