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Why FERC may struggle with SPP’s Order 2222 proposal

If FERC reads the PJM compliance proposal first, followed by MISO's, and then reads SPP's at the end - FERC could find SPP's proposal barely meets the threshold for compliance on several fronts.

FERC would have a tough time deciding what to do with SPP’s proposal because SPP’s posture from the beginning was that Order 2222 is not something the distribution utilities and SPP states want. SPP followed what it did with FERC Order 841, where SPP filed a compliance plan and later picked up improvements after receiving the FERC’s decision.

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SPP surely desires FERC’s decision sooner than MISO and PJM with its proposal.

Bare minimum

If FERC reads the PJM compliance proposal first, followed by MISO’s, and then reads SPP’s at the end – FERC could find SPP’s proposal barely meets the threshold for compliance on several fronts. SPP did not have workshops with its state regulatory agencies as an initial matter. SPP had workshops with distribution utilities alone but missed the chance to explain why it chose that approach in its filing.

SPP did not propose a market participation model for distributed energy resources like MISO did with its Distributed Energy Aggregated Resource (DEAR) model. SPP believes its revised definitions for Resource and Market Participant are sufficient to meet the objectives of Order 2222. When well-established, multi-state ISOs like MISO and PJM have proposed a new market participation model, but SPP did not, it raises a red flag.

What is in the proposal?

1. SPP proposed a revised definition for a “Resource” contingent upon its market registration. SPP argues that this Resource could be an Aggregated DER if it registers with SPP.

2. SPP proposed adding Distributed Energy Resource Aggregator (DERA) as a Market Participant (MP) in its Integrated Marketplace. SPP’s logic is that an aggregator will be able to participate in all of the SPP markets as an MP.

3. SPP has outlined how a DERA would register a DER Aggregation in the Energy and Operating Reserve markets. In this section of SPP’s proposal, the word “attest” pops up 6 times in a single paragraph. SPP insists the DERA attest that:

a. each DER is eligible for registration,
b. Relevant Electric Retail Regulatory Authorities (RERRA) have signed off on participation,
c. the Distribution Utility “affirmed that the DER included in the DER Aggregation is not participating in a retail program for the same service that the DER would provide to the wholesale market under the DER Aggregation,
d. whether a DER Aggregation that includes demand response from a large utility is prohibited from participating in a DER Aggregation in the wholesale market by the RERRA (because of the state opt-out issue)
e. Distribution Utility affirmed that the capacity of the DERs included in the DER Aggregation will not be used simultaneously (1) to reduce the LSE’s obligation or any other LSE’s obligation (2) that the same capacity is also offered in the Energy and Operating Reserve Markets (i.e., double-counting).
f. the participation of DERs in the DER Aggregation complies with the tariffs of the relevant distribution utilities and RERRA.” The bottom line is that SPP insists on these 6 attestations before an aggregator can register DERs to participate in SPP markets.

4. To comply with the Order, SPP has kept the minimum size for DERs at 100 kW and has not proposed any maximum size requirement, unlike PJM.

5. SPP has proposed a single node aggregation arguing that if it allows multiple nodal aggregations, it would be tough for SPP to understand which Resource is responding and from where to transmission congestion on its 450 permanently defined flowgates and approximately 770 additional temporary flowgates defined daily. Without multi-nodal aggregation, SPP said distribution factors are not needed.

6. SPP proposed that aggregators provide all the information requested in the 6 attestations.

7. SPP’s metering and telemetry requirements are onerous for small DERs because it insists on Inter-Control Center Communications Protocol (ICCP) connection. Additionally, SPP proposed that MP designate a Meter Agent and that agent be responsible for providing settlement quality data. SPP proposed “that DERAs that include demand response must telemeter and submit, separately and in addition to the total aggregation response, metering reflecting the demand response performance.” That last part is not unique to SPP. Most ISOs proposed this requirement to comply with another FERC order 745 that deals with demand response compensation.

8. SPP’s proposal relies heavily on coordinating with the distribution utility because it has proposed to provide setpoint instructions and other information to the Distribution Utility, which none of the other ISOs proposed.

9. SPP proposed that modifications would not trigger a need to re-register or re-qualify the entire list of DERs in the aggregation to comply with the requirement around modifications to the DER Aggregations.

Contrast SPP with MISO and PJM proposals – no management testimony!

MISO’s proposal included testimonies of an executive vice president, senior vice president, and director. With a 2030 implementation date, MISO went on the offensive first with Richard Doying’s testimony on why a multi-configuration resources (MCR) market upgrade was needed. Second, Todd Ramey’s testimony included an explanation of the sequencing of market improvements – Market Systems Enhancement came first, followed by the MCR upgrade and then the Order 2222.

And finally, Laura Rauch narrated the entire stakeholder process at MISO including RERRA workshops and testified that MISO was compliant with Order 2222 on multiple fronts. None of that testimony is available from SPP’s compliance proposal.

PJM’s testimony included a senior manager’s reasoning for single node aggregation and why multi-nodal aggregation is not possible with PJM’s unique system topology, congestion patterns, and operating practices. A glaring contrast with MISO and PJM, SPP’s proposal did not include any staff testimony on why they went with single node aggregation.

Another contrast with MISO and PJM is that SPP staff asked for stakeholder redlines, not comments on SPP’s market tariff. Unlike MISO and PJM, SPP staff did not make presentations at each task force meeting, collect stakeholder feedback, or revise their compliance proposal in a presentation format before writing the tariff. With its Revision Request (RR 468) process, SPP directly asks stakeholders to tackle the tariff language.

SPP DER task force emphasized stakeholder voting

SPP did one thing that none of the other ISOs did: document votes approving its compliance proposal at each committee. But SPP failed to tell FERC about these multiple votes. There is no narrative or testimony about voting at Order 2222 Task Force, Operating Reliability Working Group, Market Working Group, Regional Tariff Working Group, and Markets and Operations Policy Committee (MOPC).

SPP failed to mention EDF Renewables, Enel Green Power North America, and Savion LLC opposed RR468 at the January 2022 MOPC meeting. Advanced Power Alliance, EDP Renewables, Google Energy, ITC Great Plains, and Southwest Transmission LLC voted absent.


FERC must take a different tack with SPP compared to MISO and PJM. Comments are due by June 9 in docket #ER22-1697, since FERC approved Advanced Energy Management Alliance’s (AEMA) request for an extension.

SPP requested FERC to decide on its proposal before the end of 2022, citing concerns with implementation costs. SPP is specifically concerned with the costs of implementing 2222 on its distribution utilities and load-serving entities.

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