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Enviros: States may need to leave PJM market to advance clean energy goals

Legacy provisions in the PJM Interconnection’s tariff may be the answer to staving off some of the worst purported impacts of new capacity market rules to clean energy development in the largest power market in the U.S., two clean energy advocates said Jan. 8.

The Federal Energy Regulatory Commission’s Dec. 19, 2019, order revamping the PJM’s capacity market to combat the potential price-suppressing effects of state subsidy programs has provoked a sharp rebuke from the renewable energy sector. A number of critics say the order, which expands the application of the minimum offer price rule, or MOPR, to all new resources receiving state subsidies, puts states’ clean energy policies in the crosshairs.

Tom Rutigliano, a senior advocate for the Natural Resources Defense Council’s Sustainable FERC Project, said the MOPR, as contemplated, would be “devastating to state clean energy policies.” He asserted during a webinar hosted by the trade group Advanced Energy Economy that the expanded MOPR would increase the cost of developing renewables while also requiring the purchase of “an entire backup fleet of probably fossil fuel units.”

Casey Roberts, a staff attorney with the Sierra Club’s Environmental Law Program, added during the webinar that the MOPR would likely exacerbate PJM’s capacity over procurement problem, increasing "the need for state policies to achieve decarbonization over and above what the market might accomplish on its own, at the same time as those policies are going to become more expensive" as clean energy resources lose their capacity revenue stream.

The two officials contended that states were left with few options for mitigating the impacts on their clean energy goals. Among them: opting out of the capacity market. That option could play out through load-serving entities’ election of PJM’s fixed resource requirement, or FRR alternative, a legacy tariff provision originally meant to accommodate vertically integrated utilities.

Though FRR plans are executed by utilities or public power entities, Rutigliano said the amount of regulatory oversight involved essentially makes the state the decision-maker while the utility is the implementer.

A load-serving entity that pursues the FRR route must demonstrate to PJM that it either owns or has under its control enough capacity to serve 100% of the load in its service territory, and each resource included in the plan must individually meet PJM’s existing capacity requirements.

But there is an option for FRR resources “to be judged as a portfolio, which we believe creates some pretty interesting opportunities for aggregation of renewables, risk sharing, more aggressive use of seasonal resources and so on,” Rutigliano said.

‘Silver lining’

Utility use of FRR plans has dwindled in past years as the capacity market has been heavily relied on for resource adequacy. The “silver lining” to FERC’s capacity market order is that “the MOPR is a significant enough policy shift that nearly every state, certainly any state with clean energy goals, is going to have to take a very close look at FRR plans, and that might actually provide a path to better use of renewables,” Rutigliano said.

But FRR plans also come with challenges, the biggest of which may be overcoming inertia as states and utilities have generally become accustomed to serving a passive role in capacity procurement, Roberts said. "There’s going to be a lot of work needed to understand the impacts and assess what changes might be needed at the regulatory or statutory level to enable [the FRR alternative] to be used in the most cost-effective way possible."

For instance, state utility regulators would have to ensure that capacity procurements are competitive and that there are sufficient measures in place to address market power and affiliate deals. Retail choice statutes and default service offer processes may also need to be revised if a utility elects FRR, Roberts said.

PJM is expected to provide a timetable for when it proposes to hold its next capacity auction in a compliance filing due March 18. Though there is pressure to move with haste in light of last year’s auction for the 2022-23 delivery year being placed on indefinite hold while new market rules are worked out, Rutigliano and Roberts cautioned against scheduling an auction before states can weigh and exercise their options.

Load-serving entities must declare their intent to use an FRR plan four months prior to the start of the capacity auction, and the election of that alternative comes with a minimum five-year commitment.

“In many states, you’re going to at the very least need utility commission action and quite possibly legislation to get these FRR plans in place,” Rutigliano said. He added that states likely need about a year to fully exercise the FRR option and “should be pretty aggressive in fighting” for the necessary time to pursue that path. “Not having the next auction occur in a hasty manner will be really important to minimizing the [adverse] impacts of this order," he asserted. (FERC docket EL16-49, EL18-178)

This article was published by S&P Global Market Intelligence and not by S&P Global Ratings, which is a separately managed division of S&P Global.