FERC’s Order Redesigning PJM’s Capacity Market

If you haven’t heard, on June 29, FERC issued a whopper of an order requiring significant changes to PJM’s capacity market in the name of preserving competitive market fundamentals in the face of state subsidies.

I’ll do my best to explain the issues and FERC order in simple terms, then will follow up with another blog on implications.

Most states participating in PJM’s markets are restructured, meaning decisions about where, when, and how much to pay for generation capacity are determined by competitive markets, not by state utility commissions.

Production of Mid-Atlantic shale gas underlying the PJM footprint resulted in cheap and plentiful gas supplies being available to power inexpensive and easy-to-construct combined cycle gas plants. A disruptive influx of gas capacity resources entered PJM’s market, seeking to unseat less competitive generation and gain market share.

The resulting shift in the supply curve lowered energy prices for consumers, and market revenues for generators. Market prices for generators were so low that many were forced to leave the market. Coal capacity represented most retirements, but nuclear power also began to suffer.

The market worked as designed – low cost resources displaced higher cost resources – but the shift was fast, disruptive, and left some states feeling a bit out of control.

In PJM, a few states were concerned about the climate and job impacts associated with nuclear retirements, and put in place policies (like zero emissions credits or ZECs) to subsidizes existing at-risk nuclear plants.

Competitive generators that did not receive state subsidies expressed concern that by allowing large uneconomic nuclear resources to remain in the market through discounted capacity bids (i.e. discounted by the subsidy value) it would force truly economic generators out of the market and eventually end competitive markets. These interests advocated for mitigation of subsidies by PJM through a change in market design.

Nuclear interests shot back that the markets didn’t value their low carbon power and that states had the right to implement ZEC policy.

Other interests opined no intervention by PJM was needed, noting PJM’s plentiful supplies (i.e. record-high reserve margins) and lack of evidence that subsidies were suppressing market prices.

Significant debate around these issues has occurred for many months. (On a related note, the Kleinman Center has a great proceedings report on the topic, if you want to do more reading.)

Concerns were raised by PJM, within PJM’s stakeholder process and at FERC, eventually culminating in the June 29^th FERC order.  Without re-hashing all the history, I’ll focus on the order’s direction.

3-of-5 FERC commissioners agreed state-subsidies have the potential to inhibit the success and functioning of competitive markets through price suppression. They believe state-subsidies for nuclear power and renewable energy will only become more common and maintain the commission must protect market integrity while allowing states to subsidize preferred resources.

FERC found that PJM’s current capacity market rules require changes (i.e. are unjust and unreasonable).

But, FERC rejected the solution proposed by a coalition of merchant generators that would extend PJM’s minimum offer price rule (MOPR) – a technology-based proxy floor price on capacity market bids – to existing generators receiving subsidies, with exemptions for resources like new and existing renewable energy resources promoted by state renewable portfolio standard (RPS) policy.

FERC also rejected PJM’s two proposed alternatives, either a MOPR on existing resources (similar to the merchant coalition proposal, but would only exempt RPS-supported renewables as long as the RPS program is competitive and non-discriminatory), or development of a two-tiered capacity market auction with the goal of allowing for subsidies while mimicking a competitive market price.

Instead, FERC is opening a 90-day (yes, only 3 months) paper hearing to seek input on its proposed solutions. These include a MOPR that would apply to all new and existing resources receiving subsidies – including renewable energy promoted through state RPS policy – with almost no exemptions. Or, a proposed expansion and modification of the Fixed Resource Requirement Alternative (FRRA).

The FRRA is a mechanism currently used in PJM where (typically) a public power entity or other cost-of-service regulated capacity resource is permitted to participate in PJM without having to comply with standard requirements, such as bidding into the capacity market. 

This is done by taking all the load from the applicable utility’s entire service territory out of the demand curve for the capacity market, along with the generation supply resources supported by that territory’s customers. The FRRA entity is still required to develop a capacity plan and meet performance obligations, but customers in the territory pay (a much higher) cost-of-service rate for capacity instead of PJM’s capacity market clearing price.

FERC poses many questions about how this untested FRRA modifcation could work (especially when not related to locational load), and is looking to finalize its decision by January 4, 2019 in order to implement the new rules in advance of PJM’s May 2019 capacity auction.

But, FERC’s order may lead to a very unintended consequence…