With Richard Glick, chairman of the Federal Energy Regulatory Commission, potentially on his way out, the possibility exists that the remaining FERC commissioners will be tied along party lines on critical issues.
That possibility could impact major FERC decisions. But deciding on aggregated distributed energy resources in FERC Order 2222 should not be a “tied” decision.
Assuming Commissioner Danly is a “no” vote since he has consistently dissented, Commissioner Christie could vote with his Democratic colleagues as he is a major proponent of state’s rights. Aggregating DERs to participate in wholesale markets provides the state’s with additional tools to avoid blackouts.
With the upcoming winter and higher natural gas prices forecasted in the New England area, FERC must take action on ISO-NE’s Order 2222 proposal before it’s too late. PJM did an excellent job with the compliance proposal it submitted last February, but for the net energy metering issue.
MISO and SPP’s proposals were submitted in April, and if FERC doesn’t act soon the grid operators and their DER stakeholders could lose momentum. Changes at the FERC commissioner level should not stop work to reduce barriers to aggregating distributed resources.
Enabling demand response
The FERC staff report “Winter Energy Market and Reliability Assessment 2022-23,” released in October, notes that higher natural gas prices and wholesale electricity prices are possible in the New England region. FERC held a New England Winter Gas-Electric Forum in September and requested the industry to comment in docket #AD22-9. Several organizations pointed out deficiencies in ISO-NE’s Order 2222 proposal in their post-forum comments.
FERC commissioners should note in particular Advanced Energy Economy’s comments about unlocking demand response and demand-side flexibility to address potential winter emergencies in the New England region.PJM region.
Commissioner Christie should note that ISO-NE’s CEO asserts that increasing retail demand response is within the New England state’s responsibility. But FERC is responsible for ensuring aggregated retail programs can participate in wholesale markets if they are technically capable. ISO-NE’s metering requirements are a barrier for DERs to participate, and FERC must take action to reduce these requirements before it is too late.
Advanced Energy Management Alliance (AEMA) also noted in its post-forum comments that ISO-NE “has repeatedly created rules that unduly discriminate against demand response and other distributed energy resources.” Surprisingly, the New England Transmission Owners commented in favor of demand response and DERs.
ISO-NE’s implementation date for aggregated DERs to participate in the energy and ancillary services market is in the 4th quarter of 2026. The capacity market implementation starts later, in the 2nd quarter of 2027.
PJM’s problematic stance
PJM’s filing has possibly the least controversy compared to its ISO peers in Order 2222, except when it comes to the net energy metering (NEM) issue.
PJM states can enable more distributed solar through Order 2222 by allowing NEM assets to aggregate with non-NEM assets. NEM solar should be allowed to participate in wholesale markets with the state regulatory authority’s approval. But PJM’s responses to FERC were “not narrowly designed to avoid double counting,” as AEE and the Solar Energy Industries Association (SEIA) noted in their comments.MISO SPP RTO map.
PJM requires NEM resources to comply with the “must offer” requirement in the day-ahead energy market. Additionally, PJM is lumping NEM assets with non-NEM assets located at a single site, with these restrictions setting up a barrier for DERs to participate in PJM markets.
PJM’s implementation date for aggregated DERs to participate in the energy and ancillary services market is February 2026. The capacity market implementation starts much sooner, in July 2023. Another reason why FERC should act now.
MISO states favor earlier implementation
By proposing a 2030 implementation date, MISO has grabbed the headline and made FERC’s job harder, especially since it has prioritized a market upgrade that favors natural gas offers over DER offers. MISO reasons that natural gas capacity provides more benefits than aggregated DERs. Never mind that MISO did not calculate the benefits of aggregated DERs.
FERC’s job–and, more specifically, Commissioner Christie’s decision to vote along with Commissioner Clements and Phillips–is simpler if they factor in the objections to MISO’s 2030 date from Organization of MISO States (OMS), which is made up of state commissions from Missouri, Michigan, Illinois, and Indiana.
FERC should note the point made by the Indiana Utility Regulatory Commission (IURC) that most MISO states share “seams” with PJM and SPP, and that both PJM and SPP have an earlier implementation date than MISO. Hence, most MISO states would already be preparing to support FERC Order 2222 implementation in 2025-26.FERC headquarters. Credit: Ryan McKnight / Flickr
Additionally, both Michigan and Illinois have experience with aggregating DERs. If the state “opt-out” issue for demand response is a controversial topic for FERC commissioners to tackle at this stage, a near-term solution would be for FERC to order MISO to open up its existing Demand Response Resource Type I for aggregating DERs such as distributed solar and storage. Since MISO opened up the Electric Storage Resource market model in June for distributed storage, market participants could aggregate behind-the-meter solar with storage if MISO upgrades the existing DRR Type I.
As AEMA noted in its November comments to MISO’s response to FERC’s data request, opening up the existing market models for DERs is a much better near-term option. Lastly, the 2022 OMS MISO survey shows a significant reduction in resources committed to serving MISO North and Central load in 2027. (Slide 11 here) Commissioner Christie should note that the OMS MISO survey states that Load Modifying Resources, which include Demand Response and Behind The Meter Generation (BTMG), are important in meeting local capacity needs within MISO’s local resource zones (LRZs). Hence FERC should order MISO to implement 2222 in 2026-27.
Conditional approval for SPP
SPP is the only ISO that has not proposed a new market participation model to comply with FERC Order 2222 requirements. Instead, SPP proposed that DER aggregators must use any of the existing 11 valid resource types. But, unlike MISO, SPP proposed a third quarter 2025 implementation if FERC issued an order by late 2022. FERC should order SPP to implement by 2025, as proposed, because even though SPP’s compliance proposal is not perfect (for example, too many affirmations and attestation requirements on aggregators), it offers a path forward for DER providers to work within SPP’s current market construct.
However, FERC’s approval must be conditional, as noted in the AEMA November comments. SPP has a one-hour response capacity requirement for DERs included in an aggregation. SPP says this one-hour requirement allows it to comply with NERC standards.
FERC’s approval should be based on the condition that SPP clarifies that this one-hour requirement applies to an aggregation, not individual DERs. For example, a 50 kW solar and a 50 kW storage should be able to participate in an aggregation provided they can provide one hour of response capacity to SPP operators. Having that one-hour requirement on individual DERs is a barrier to aggregating DERs and defeats the purpose of Order 2222.