Distributed resources have notched a handful of wins in PJM dockets in recent weeks that have set them up to expand capacity deals with data centers even further. And the latest update out of PJM, a recently announced delay in the reliability backstop auction, could benefit DERs even further.
On Tuesday, the Federal Energy Regulatory Commission accepted the broad framework of PJM’s Reliability Backstop Procurement, its plan for securing new supply to meet large load growth. The plan, filed to FERC on July 31, includes a window during which large loads can ink bilateral deals in order to avoid having to curtail their operations during times of grid stress. PJM is looking to secure 6.8 gigawatts of capacity, the shortfall from the region’s last capacity auction, and anything not covered in bilateral deals will be purchased in a centralized, one-time auction.
But FERC delayed the proposal’s effective date by five months, sending the central procurement portion back for review and pushing back the auction, which PJM had hoped to open yesterday. The key issue, FERC said, was that PJM hadn’t sufficiently shown that its proposed plan for allocating the cost of capacity secured during the auction would actually ensure data centers footed the bill. The regulator instead suggested PJM to revise its zone-based approach using updated load forecasts.
As the investment bank Jeffries put it in a note to investors, this “unexpected twist” provides more time for bilateral contracts on new assets like distributed capacity aggregations, potentially reducing the amount of capacity PJM needs to contract in the auction when it does take place — and potentially mitigating over-procurement risks.
That’s good news for VPPs specifically, which have already been announcing bilateral deals in the region in the hopes that a bring-your-own-capacity option would be formalized as part of the process. These moves have been largely strategic rather than evidence of their auction plans, explained Julia Hoos, who covers the eastern U.S. at Aurora Energy Research. She didn’t expect them to actually participate regardless of when it was held, because the process requires them to know the exact site of an asset, and guarantee its availability for 15 years. That’s just not a good fit for demand response, because an aggregator’s customer mix generally changes over time.
But it’s a different story in the bilateral contracting phase, Hoos said. As PJM has ironed out the intricacies of what types of capacity can help a large load avoid the curtailment list, DER aggregators have weighed in on policies that would enable their full participation, and in some cases, have been rewarded with tweaks to language in PJM’s plan.
Last week, for example, the grid operator agreed to allow locations that had previously participated in demand response to be counted as new capacity, provided that they hadn’t participated in demand response the prior year. Aggregators can now “reactivate” these “dormant” locations. For the purposes of the procurement process, PJM also agreed to count incremental capacity, like new batteries or other physical assets added at existing demand response locations.
Questions ahead
FERC’s broad approval of the capacity procurement framework provides some regulatory clarity for aggregators, but key questions remain.
PJM’s wider plan for capacity procurement is split into two dockets: the reliability backstop procurement, including the bilateral and auction phases; and a second, separate proceeding for the region’s curtailment plan, dubbed the Interim Resource Adequacy Study, or IRAS.
Analysts at Capstone, a Washington, D.C.-based policy research firm said in a recent note that FERC’s decision on IRAS is more impactful for the market than the decision to delay the auction because the former will ultimately impact prices in PJM. Under IRAS, a large load would only be included in PJM’s capacity auction demand curve if it brings its own capacity; without IRAS, those loads would be included, meaning the next auction is likely to clear at the price cap.
The fact that FERC delayed PJM’s reliability backstop plan makes it more likely that IRAS, which is more controversial among stakeholders, will be implemented on time, Jeffries added. The key issues there are the creation of a large load registry to track sites greater than 50MW, and whether large loads that don’t bring their own capacity get curtailed before existing demand response.
For VPPs, the delay in IRAS approval is a mixed bag. As of now, FERC hasn’t confirmed that distributed capacity will count to offset a large load’s IRAS obligation. So even as a delay in the central auction leaves a window for more bilateral deals to be signed, one important source of demand for those deals is watching the process from a holding pattern.
