Policy & Regulation

Southwest Power Pool’s multi-nodal analysis is not on par with PJM’s

Southwest Power Pool’s multi-nodal analysis is not on par with PJM’s
SPP Coordination Center (Courtesy: SPP)

Time is running out for Southwest Power Pool (SPP) to put together a comprehensive FERC Order 2222 proposal before the December 26 filing date. 

SPP started strong by admitting that multi-nodal aggregation is possible and assembling a technical analysis to support its 100 MW SPP-wide aggregation restriction. Still, its proposal differs in multiple ways from PJM’s.

Comparison with PJM is warranted because SPP staff indicated they talked to PJM about PJM’s 167 MW aggregation restriction after the Federal Energy Regulatory Commission (FERC) approved PJM’s proposal in March. Unless SPP conducts additional analysis similar to PJM’s, including looking at five-year historical data as opposed to one-year, and price separation data as opposed to transmission constraint data, SPP is running the risk of non-compliance with FERC’s locational requirements in Order 2222.

Similarities with PJM’s requirements

FERC approved PJM’s multi-nodal proposal earlier this year. This FERC approval has led SPP staff to embrace PJM’s multi-nodal aggregation restrictions without fully realizing the amount of work PJM staff has done. There is also a higher bar for SPP staff to meet because FERC found PJM partially complied with locational requirements. Even then, PJM did a lot of analysis. In SPP’s situation, FERC found that SPP did not comply with locational requirements. Hence, one would expect a lot more analysis from SPP staff to meet the burden of complying with FERC’s Order 2222 locational requirements.

Before discussing the differences between SPP’s current approach and PJM’s filed approach, some similarities exist. The primary similarity is the restriction for multi-nodal aggregations at PJM and SPP. But the reasoning differs a bit. PJM restricts multi-nodal aggregations to 167 MW, which is 0.1% of the estimated peak demand (152,736 MW) in 2026, times the forecasted pool requirement (1.0918). SPP first proposed a 56 MW limit (0.1% of its peak demand, 56,184 MW in 2023), but now increased to 100 MW (0.2%), but for SPP East footprint and 20 MW for SPP West footprint.

PJM has an “anchor” component DER concept that SPP appears to borrow in its proposal without defining it. So, both have a multi-nodal restriction in situations where individual DERs (component DER) are so small that they cannot add up to 0.1 MW to make the aggregation work. In that situation, PJM allows one anchor component DER or a group of component DERs to be part of the multi-nodal aggregation so that, overall, the aggregation can meet the minimum size requirement of 0.1 MW. SPP has a similar restriction.         

PJM did three analyses and looked at five years of historical data

PJM staff conducted three analyses with different levels of granularity. In the first analysis, PJM staff conducted a nodal-to-zonal LMP analysis to compare the LMP prices at each pricing node to the zonal aggregate LMP in which those pricing nodes were located. SPP conducted a historical congestion analysis, which would be like PJM’s first analysis but not as extensive because SPP did not look at the past five years of historical LMP data as PJM did. PJM analyzed 11,000 pricing nodes and 446 million hours of real-time LMP pricing data. SPP only looked at one last year of congestion data and one year of shift factor analysis.

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In the second analysis, PJM staff went down to the next level of granularity – the substation level. PJM varied the number of nodes per substation from 1 to 17 and found that with only 1 node per substation, 23% of nodes had a price separation of less than $1 and less than $5. Similarly, with 2 nodes per substation, PJM found that 20% of nodes had a price separation of less than $1, and 23% of nodes had a price separation of less than $5. A similar level of detail is missing from SPP’s analysis because SPP focused on transmission constraints in its historical congestion analysis and got bogged down in what appears to be 5-minute intervals of transmission constraint data. It is not clear from SPP’s limited historical analysis how many nodes have a price separation of less than $1, for example.

In the third analysis, PJM focused on a single zone in Dayton Power & Light (DPL). PJM stated that out of 286 demand-side pricing nodes in DPL, only 111 nodes had the lowest deviation of at least $1 price in an hour. Hence, 40% of the nodes could technically participate in a multi-nodal aggregation since they didn’t have greater than $1 price separation. SPP’s analysis does not focus on load nodes alone, unlike PJM’s. 

PJM also found that out of the remaining 175 DPL nodes, only 14 had consistent LMP patterns in the 5-year historical window. PJM used this data to illustrate that it would have to create 175 distinct sub-zones within the DPL zone to accommodate multi-nodal aggregation, which is infeasible. Hence, it is clear how PJM justified its multi-nodal approach at FERC, but it is unclear at this time how SPP plans to justify its locational requirements approach at FERC in December.   

Next steps

The clock to put together a proposal and file at FERC is winding down for SPP. SPP staff is making a big push at several stakeholder committees in September, including the Markets Working Group, before the Markets and Operations Policy Committee (MOPC) vote in October. SPP staff also stated they plan to hold workshops with the distribution utilities and state regulatory staff in September and October to discuss the proposal, including double counting concerns.

Time is running out for SPP to conduct additional analysis on this multi-nodal locational requirement. Simply borrowing PJM’s multi-nodal aggregation resources restriction is not going to cut it at FERC. SPP must put together a comprehensive analysis to persuade FERC.