Docket Nos. ER24-99-000, ER24-99-001
The risk modeling enhancements at the core of PJM’s proposal are an important step forward in modernizing its capacity market. Over a decade’s worth of extreme weather experience, along with other historical operational data, have made plain that the traditional model of procuring capacity solely based on summer peak demand is outmoded. Instead, grid operators’ risk modeling must become more sophisticated to ensure capacity markets send accurate demand signals today and into the future. PJM’s development of a new framework that seeks to assess the patterns, drivers, and probabilities of reliability risk across all hours of the year is an important advancement in this effort. PJM’s new approach to capacity accreditation will enhance system reliability because it more accurately addresses system risk than PJM’s current method. While I would not have made all of the same specific market design choices as PJM, in my view PJM cleared the bar in demonstrating its filing to be just and reasonable.
I write separately for two reasons. First, regrettably, despite my view that PJM has demonstrated its proposal to be just and reasonable, I dissent in part from the Order because its response to arguments regarding PJM’s choice not to modify its Demand Resource availability window is overbroad and unsupported. I agree with the Order that any potential changes to the Demand Resource availability window are outside the scope of PJM’s proposal, and I would have signed onto an order that simply stated and justified this conclusion. Yet the Order gratuitously adds a conclusory statement declaring that the Advanced Energy Management Alliance (AEMA) and Clean Energy Associations “have not demonstrated that PJM’s proposed changes in the accreditation methodology and the Reserve Requirement Study render the Demand Resource ‘performance’ window unjust and unreasonable.”[1]
The Order provides no support for this conclusion. And the record leads to a contrary result. AEMA argues that the Demand Resource availability windows currently enshrined in PJM’s rules “reflect PJM’s historical understanding of reliability risk.”[2] PJM’s proposal reflects an evolved understanding of system risk, such that “the current DR performance window in the winter period does not cover hours that show loss of load risk in the model.”[3] Further, “AEMA members include the vast majority of Curtailment Service Providers and support expanding the winter availability window to include the hours from 6 a.m. to 12 a.m. consistent with PJM’s evolving understanding of reliability risk.”[4] Yet, rather than including an expansion to the availability window within the scope of its filing to match its new understanding of system risk, PJM has chosen to apply a haircut to the capacity accreditation of demand response resources.[5] To the extent that this denies demand response resources an opportunity to deliver a service that they stand ready, willing, and able to provide, this does appear to render the existing tariff unjust and unreasonable and unduly discriminatory. Not only does the Order fail to rebut any of these arguments, it fails to even provide any indication as to what step of this logical chain, if any, the majority takes issue with.
While I would have found the Demand Resource availability window to be out of scope to PJM’s filing because it has not proposed any changes thereto, the Commission should have initiated an order to show cause pursuant to section 206 of the Federal Power Act to address the clear mismatch between PJM’s existing Demand Resource availability window and its new understanding of system risk. PJM should be required to either adjust the availability window to reflect its new understanding of risk, or else demonstrate why its proposed changes have not rendered the current availability window unjust and unreasonable or unduly discriminatory.
Beyond dissenting from the Commission’s arbitrary and capricious[6] response to demand response providers, I also write separately to explain my support for the Commission’s rejection of Public Interest Organizations’ concern that “cost allocation under PJM’s marginal ELCC framework will ‘improperly socialize investments in electricity supply.’”[7]
As PJM explains, it allocates costs according to the commonly accepted principles under the Federal Power Act, where collateral benefits that accrue to the whole PJM region due to each given resource investment are shared across the region rather than disaggregated and assigned to the host state or load serving entity in which the investment is located.[8] In my view, this approach makes sense. State and local policies of all stripes naturally affect the supply of capacity resources, thereby influencing the costs and benefits that others receive by participating in the capacity market.[9] In this case, as with some other regional investments, benefits accrue broadly to customers across the region when ELCC resources enter the capacity market such that a resource’s marginal cost is lower than its average capacity value. But while the Federal Power Act requires rates to be just and reasonable and not unduly discriminatory, that does not require isolating state policies, attributing the development of certain resources to specific policies (where they may be developed due to many different factors), and charging wholesale customer different capacity rates based on the policy of the state(s) in which they are located. Rather, the just and reasonable standard is met where the relevant public utility engages in the more straightforward exercise of determining a cost of the relevant product (here, capacity), and charging each customer for the share of that capacity which they need to purchase.[10] Attempting to disaggregate the effects of state policy, as Public Interest Organizations suggest the Commission do, opens the door to a contentious exercise that will ultimately prove impracticable given the “inextricable link[]”[11] between matters of state and federal jurisdiction over electricity markets.
As markets continue to develop, evidence continues to demonstrate that utilities stand stronger together, delivering greater reliability and lower costs by pooling resources across broad geographical areas.[12] Reserving specific cost savings for only those load serving entities or market participants in which a particular investment is located is not only practically unworkable and legally unnecessary in a shared pool, it overlooks the reliability and cost benefits that pooled markets impart.
For these reasons, I respectfully concur in part and dissent in part.
[1] Order at P 107. The Commission’s discussion of cost allocation is similarly perplexing, though less demonstrably incorrect. The Order concludes that there is “no basis to find that PJM’s just and reasonable revisions to its capacity accreditation and resource adequacy risk modeling must be rejected because PJM has determined to continue its current longstanding capacity market cost allocation.” Order at P 185. So far as I can tell, this conclusion follows because revisions to PJM’s peak-demand-based allocation of capacity costs are outside the scope of PJM’s filing, a defensible conclusion. But the Order does not clearly state this, leaving its logic ambiguous and muddled.
[2] AEMA Comments/Protest at 3.
[3] Deficiency Response at 28.
[4] Id. at 4.
[5] See Order at P 95.
[6] FERC’s fails to “engage in the reasoned decisionmaking required by the Administrative Procedure Act” where its arguments “amount[] to conclusory statements that dismiss . . . concerns without providing reasoned analysis.” New England Power Generators Ass’n, Inc. v. FERC, 881 F.3d 202, 211 (D.C. Cir. 2018).
[7] Order at P 186 (quoting Public Interest Organizations’ Protest at 44).
[8] Bruno and Graf Reply Aff. at ¶ 39; Order at P 174 n. 340.
[9] See Joint Statement of Chairman Glick and Commissioner Regarding the Fair Rates Act on PJM MOPR, Docket No. ER21-2582 (October 19, 2021) (“[P]ublic policy and electricity markets are inextricably intertwined. Nearly every aspect of the electricity market is affected by at least one—and more often many—federal, state, or local policies.”).
[10] The Commission adheres to the same basic principles in allocating transmission costs, where the costs charged to each customer must be “roughly commensurate” with the benefits they receive. See Coalition of MISO Transmission Customers v. FERC, 45 F.4th 1004, 1009 (D.C. Cir. 2022).
[11] FERC v. EPSA, 577 U.S. 260, 265 (2016)
[12] See, e.g., Chang et al., Potential Benefits of a Regional Wholesale Power Market to North Carolina’s Electricity Customers, at 4-6 (April 2019), available at https://www.brattle.com/wp‑content/uploads/2021/05/16092_nc_wholesale_power_market_whitepaper_april_2019_final.pdf (listing many different studies, including both prospective and retrospective estimates of benefits).