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MISO and SPP are sticking with FERC Order 2222 plans. What’s next?

The DER industry must be critical of both proposals in the areas of net energy metering and interconnection, as well as the lack of a market participation model for Aggregated DERs at SPP.

Midwest grid operators Midcontinent Independent System Operator (MISO) and Southwest Power Pool (SPP) are sticking with their plans to implement distributed energy resource participation in wholesale markets, according to responses filed at the Federal Energy Regulatory Commission (FERC).

The DER industry must be critical of both proposals in the areas of net energy metering and interconnection, as well as the lack of a market participation model for Aggregated DERs at SPP. Taking a leaf out of SPP’s 2025 proposed implementation date, FERC should insist on MISO implementing a DER Light model by 2026.

DER providers and stakeholders have until Nov 1 and 2 to respond to MISO and SPP responses at FERC.

Join us on Feb. 6, 2023 in San Diego for the inaugural GridTECH Connect Forum, the only event that brings together utility leaders and distributed energy resource developers to overcome the challenges associated with interconnection. Learn more about the new, regional event from Clarion Energy today.

Broad statements that net energy metering is ruled out

SPP made a big deal about lagging jurisdictional authority over its 550 distribution utilities in its response to FERC but ruled out the participation of net energy metering programs in SPP markets without providing evidence.

FERC will likely reject this argument because SPP’s double counting language in their proposal (Section 12.1) states: “The same service is a service that could potentially obligate the DER to provide the same MWh in both the wholesale and retail markets. If the DERA offers services from the DERs into the Energy and Operating Reserve Markets also participating in their retail provider’s programs but offering a different service, this is not considered double counting.”

So, SPP cannot rule out NEM program participation unless it has gathered evidence from its 550 utilities that those NEM programs would provide the same MWh in retail and wholesale markets.

MISO also makes a similar statement in its response. None of these ISOs (MISO, SPP) engaged their stakeholders on NEM solar use cases. With only broad statements to offer, FERC should reject this proposal.

Both ISOs borrow concepts from Generator Interconnection Queue for DER interconnection

MISO and SPP borrow concepts heavily from generator interconnection even though FERC explicitly stated in Order 2222 that distribution-connected DERs do not have to follow FERC jurisdictional interconnection procedures because distribution facilities fall under state jurisdiction.

For example, SPP’s response cites Attachment B of Appendix 3 of SPP’s Generator Interconnection Procedures (GIP) to assert that SPP’s data requirements for small generators less than 20 MWs align with distribution utilities DER requirements. This SPP requirement is problematic to aggregators because, while SPP insists that it cares only about receiving DER aggregated data from an aggregator, SPP insists on receiving individual meter numbers and customer account numbers at each DER site.

MISO is also sneaking in generator interconnection concepts and procedures on distribution-connected DERs under the pretense that “affected systems” studies are not FERC tariff-related. Rather, they fall outside the tariff under MISO Business Practices Manuals. FERC should reject this argument because FERC is making these affected systems studies part of generator interconnection tariffs in the Notice of Proposed Rulemaking on generator interconnection reforms tied with transmission planning reform. Moreover, affected systems are defined in MISO’s current FERC-approved generator interconnection tariff. MISO cannot claim compliance with FERC Order 2222 and require DER interconnections to follow affected systems study procedures simultaneously.

SPP’s gamble with existing resource types

SPP Coordination Center (Courtesy: SPP)

Unlike MISO, SPP did not add a new market participation model for aggregated DERs. SPP reasoned that since DERs consist of multiple existing technologies such as demand response and renewable energy – they would fit into any of the existing 11 Resource Types. For example, at SPP, similar to MISO, there are two demand response resource types – Block Demand Response Resource (BDR at SPP, DRR Type I at MISO) and Dispatchable Demand Response Resource (DDR at SPP, DRR Type II at MISO). SPP said, “DER aggregations will be eligible to register as DDR as long as the aggregation is comprised entirely of controllable load or behind-the-meter generation that is used to reduce load.” These DDRs must be dispatchable within 5 minutes, requiring a telemetry connection with the SPP control room.

FERC might reject SPP’s reasoning here and force SPP back to the drawing board because a BDR at SPP is not allowed to provide frequency regulation and ramp services and only participates in energy, spinning, and supplemental (non-spinning) markets. NEM solar and residential batteries might qualify to participate as Generating Unit (GEN) or Plant (PLT) resource types which are allowed to provide all of the possible ancillary services.

There is no maximum MW size restriction for DER aggregations at SPP, similar to MISO. But SPP snuck in a response capacity limitation of 1 hour based on a justification that the NERC MOD standard requires a synchronous generator to demonstrate real power and lagging reactive power for an hour. SPP’s Order 2222 proposal rests on similar justifications of treating DERs like generators without reducing barriers for non-synchronous DER technologies that are inverter-based, like solar and storage.

SPP requires multiple affirmations and attestations yet lacks authority

Another aspect of SPP’s proposal that FERC could reject is multiple affirmations and attestations. To participate in SPP markets, an aggregator must first gather positive affirmation from a retail provider who could be an EDC or an LSE at SPP. Then the aggregator contacts the retail electricity authority to gain their affirmation that the retail program can participate in wholesale markets. Before registering the DER aggregation, an aggregator must gather affirmations from a minimum of 3 and a maximum of 550 entities. Lastly, the aggregator must attest that they received positive affirmations and include the contact information of individuals they contacted at each of these entities.

Lastly, MISO’s proposal is somewhat deferential to its EDCs but not as much as SPPs. There are at least four instances of “SPP lacks the jurisdictional authority” over its EDCs in SPP’s reply to the FERC data request. SPP says it lacks the authority 1) to force EDCs to communicate to the aggregator about retail program eligibility to participate in the wholesale market, 2) for EDCs to provide meter data on behalf of an aggregator to SPP, 3) to require distribution utilities to set up an ICCP connection with SPP, and 4) to set up a uniform standard for safety & reliability criteria that its 550 distribution utilities must perform on DER aggregations. None of these are insurmountable for SPP, but unlike MISO, FERC should note that SPP did not initiate workshops with retail authorities to discuss these jurisdictional barriers. Rather, SPP burdens aggregators to help SPP navigate these barriers.

Implementation dates – SPP in 2025, MISO in 2030

MISO stuck to its 2030 implementation date, asserting that after its Market Systems Enhancement project, it is updating its Demand Response Tool (DRT) and Unified Enrollment System for registering DERs. But MISO did not communicate to FERC if it has explored any minor modifications to these market registration tools. For example, minor changes to the DRT could handle enrollment, measurement, and verification for homogenous and heterogenous aggregations like demand response aggregations. Like its Electric Storage Resource decision in May 2021, FERC should force MISO to implement a “DER light” version at least 3 years before 2030. That DER Light version could entail aggregating DERs leveraging existing market models like SPP’s proposal without the full Cadillac version.

When FERC asked SPP for software milestones to justify its 3rd quarter 2025 implementation date, SPP responded with broad estimates such as it takes 9 months for EMS design, 6-12 months for ICCP changes, and 9 months each for operator displays and market registration testing before the go-live date. FERC should approve SPP’s proposal without major modifications and order SPP to implement its 2222 model by September 30, 2025. Otherwise, if FERC insists on major changes to SPP’s proposal (e.g., requiring multi-nodal aggregation), the distribution utilities and SPP could have an excuse to delay implementation beyond the proposed 2025 date.

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