For more than a year, clean energy advocates have been asking the Federal Energy Regulatory Commission to reject market proposals from the country’s biggest grid operator, PJM, on the grounds that they could effectively bar state-subsidized clean power from participating in the country’s biggest capacity market. 

On Friday, FERC’s five-member commission voted on a 3-2 party line to throw out PJM’s proposals, declare its current capacity market as “unjust and unreasonable,” and start a proceeding to replace it with a plan that could be much more restrictive for state-sponsored clean energy — or, alternatively, much more open to states setting their own energy imperatives.

These are some of the alternative futures opened up by FERC’s order, according to the energy industry analysts and clean energy advocates who’ve been parsing through the 107-page document since its Friday release. 

In a surprising move, FERC’s three Republican commissioners — chairman Kevin McIntyre, commissioner Neil Chatterjee, and soon-to-retire Commissioner Robert Powelson — went far beyond rejecting PJM’s original proposals, as many in the industry were expecting. 

Instead, they took PJM’s original argument that its capacity market is being distorted by state-subsidized resources — namely, nuclear power plants receiving state zero-emissions credits (ZECs), but also wind and solar power backed by state renewable portfolio standard programs — and expanded it to declare the tariff that governs the market “unjust and unreasonable.” 

That finding, which received strong criticism from FERC’s two Democrats who voted against it, allows FERC’s ruling to demand an expedited 90-day timeline for PJM to create a new alternative to its capacity market. The rush could create increased uncertainty for state-supported power plants and renewable resources, critics say. 

The replacement suggested by FERC’s ruling has drawn a more mixed response from some of the same groups that are strongly opposed to its overall premise. 

While the first part of its remedy would likely bar many state policy-supported resources from competing in PJM’s capacity market, the second part could create a pathway for utilities to bring the same resources into play under a new structure that may be more, not less, responsive to state energy policy goals. 

“The language in the ruling is very bad — it states that FERC sees its role as undercutting state policy,” Robbie Orvis, policy director at Energy Innovation, said in a Monday interview. “But the proposed outcome is not necessarily a bad outcome for clean energy and state climate policy."

It all depends on how it's executed. 

The fundamental controversy: State policy vs. federal market authority 

PJM’s capacity market, officially called the Reliability Pricing Mechanism (RPM), is the country’s largest market of its kind, serving the future energy needs of a grid that spans 13 states and serves about 65 million customers. Beyond reducing consumer energy prices and maintaining robust reserves over its lifespan, PJM’s capacity market has also helped bring nontraditional resources into play as significant grid resources, becoming the country’s largest market for demand response. 

Wind and solar power have played a much smaller role in PJM’s capacity auction, given their relatively slender share of the grid operator’s overall energy mix, and the complications of creating contracts that allow their intermittent energy output to serve as future grid capacity. In PJM’s latest RPM base residual auction, demand response accounted for 11,000 megawatts of the total 163,600 megawatts procured, while wind accounted for only 1,417 megawatts and solar for 570 megawatts. 

The real push behind FERC’s ruling last week comes from a complaint filed by Calpine and other generators about the zero-emissions credits now being extended to economically uncompetitive nuclear power plants in Illinois and New Jersey, and potentially other states. Nuclear plants come in gigawatt size ranges, making their ability to bid capacity prices backed by state subsidies a more significant threat to fossil fuel generators. 

FERC took up Calpine’s argument that such payments allow these plants to bid capacity at lower than operating costs, undercutting opportunities for more competitive resources. But its majority ruling last week extended the same critique to state renewable portfolio standard-supported wind and solar power, stating that the share of renewables receiving out-of-market support “has increased significantly and raises price suppression concerns similar to other resources receiving out-of-market support.” 

FERC’s ruling states that the price distortions from these resources “compromise the capacity market’s integrity” and “create significant uncertainty, which may further compromise the market.” 

“Ultimately, these problems with PJM’s existing Tariff result in unjust and unreasonable rates, terms, and conditions of service,” the ruling states, citing the key legal threshold required for FERC to demand that a grid operator change its tariffs. 

This part of FERC’s ruling has been roundly criticized by clean energy groups and environmental and climate-change activists, who fear that Friday’s decision is part of a broader effort at the federal level to undermine state clean energy policies.

“State climate policies don’t distort power markets; they make them more fair and efficient. FERC’s decision attacks these state policies and in so doing threatens to destroy the very market FERC claims to protect,” John Moore, director of the Sustainable FERC Project at the Natural Resources Defense Council, wrote in a Monday email. 

FERC Commissioner Richard Glick concurred, writing in his dissent that the majority ruling “entirely fails to meet its burden to show that PJM’s tariff is unjust and unreasonable,” with a record “devoid of evidence” of its claim of a significant market harm from state energy policies. Instead, PJM’s capacity market structure has been delivering record-high reserve margins at historically low prices, he wrote. 

“The Commission’s role is not — and should not be — to exercise its authority over wholesale rates in a manner that aims to mitigate, frustrate, or otherwise limit the states’ exercise of their exclusive authority over electric generation facilities,” he wrote. 

Why a modified MOPR is bad news for state-supported resources

Despite these concerns, FERC’s majority ruling is pushing forward with a two-part proposed replacement for PJM’s capacity market. While each part has its own complexities, they might be summed up as the stick and the carrot for state-subsidized resources.

The first part is a request by FERC for PJM to “modify PJM’s MOPR such that it would apply to new and existing resources that receive out-of-market payments, regardless of resource type, but would include few to no exemptions.” 

The acronym MOPR stands for "minimum offer price rule," a market mechanism originally designed to prevent market gaming by natural-gas plants that happen to be owned by utilities that also have to buy capacity in PJM’s market. To prevent those plants from underbidding into that market to drive down prices, PJM set a minimum price and required any plants that bid under it to prove that they’re not actually bidding under their cost of production. 

Extending the concept of a MOPR to resources that have very low marginal costs, as with nuclear power plants, or effectively zero-marginal costs, as with wind and solar power, would require PJM to set administrative minimums for those resources as well, Energy Innovation's Robbie Orvis explained. 

Just how those minimums would be set, and how they would affect resources they’re applied to, is unclear. But according to FERC Commissioner Glick, applying a MOPR “could effectively bar state renewable portfolio standard solar and wind power from participating in PJM’s capacity market, by administratively setting minimum prices that could render them uncompetitive with coal, nuclear, natural gas or demand-side resources.” 

This is a double whammy for the states investing in building the capacity of their chosen resources, critics contend, because the utilities within their borders will need to buy the same amount of capacity from PJM’s market every year. As Glick put it in his dissent, it’s equivalent to “depriving them of a payment for capacity that they will actually provide and leaving it to the states to pick up that tab.” 

Closing a door, opening a window: The resource-specific Fixed Resource Requirement Alternative option

FERC’s ruling acknowledges this double-payment conundrum for states, despite citing court precedent to indicate it’s not responsible for solving the problems arising from rightful exercise of its powers. 

“Nonetheless, we do not take this concern — or the states’ right to pursue valid policy goals — lightly,” the ruling states. “Which brings us to the second aspect of our proposed replacement rate.” That is a preliminary finding that it “may be just and reasonable to accommodate resources that receive out-of-market support, and mitigate or avoid the potential for double payment and over procurement, by implementing a resource-specific FRR Alternative option.”

To unpack this bit of regulatory jargon, it's helpful to understand the term FRR, which stands for “Fixed Resource Requirement.” Put in the simplest terms possible, FRR is PJM’s program to allow utilities to opt out of acquiring their capacity through its Reliability Pricing Mechanism, and instead procure it themselves via bilateral contracts. 

While this has always been an option, it’s very rarely been pursued by utilities in PJM’s service territory, Orvis said. That’s because the FRR is currently an “all or nothing” choice — utilities must either obtain all of their capacity requirements on their own, or get all of them from PJM’s market. This restriction has limited the use of the FRR to a handful of the region’s biggest utilities, including Duke Energy and AEP. 

FERC’s new concept of a resource-specific FRR Alternative, by contrast, “would not require a load-serving entity to remove its entire footprint from the capacity market; rather it would remove a specific resource (and accompanying load).” In other words, as long as a resource is state-supported and thus subject to the MOPR, utilities can subtract it from their required purchases from PJM’s market, while still being able to rely on that market for whatever remains. 

“That would be a really big deal,” Orvis said. If utilities could be free to contract bilaterally for individual units of capacity, simply by procuring the same resources that their state regulators have mandated they procure, this could lead to a rapid reconfiguration of how the states within PJM territory fill their future resource mix, he said. 

“Speaking with some other people in the community, it’s possible this could lead to a weakening of the capacity market in PJM, somewhat substantially,” he said. 

Analysts with Bank of America Merrill Lynch agreed, writing in a Monday note that “FERC's proposal would effectively pass substantial decision making back to states on resource adequacy and ability to pursue their own subsidized generation approaches. Critically, the decision would be left to states to pull assets out, empowering every state involved to evaluate their respective portfolios.” 

Under FERC’s ruling, parties to the ruling, including the states in PJM territory, have 60 days to file their comments, with another 30 days for reply comments. Monday’s analyst note laid out a state-by-state prediction on how each might move in that time to assert their potential new prerogatives. For example, Illinois and New Jersey are likely to “vigorously defend their ability to remove their nuclear assets from the capacity market and pay them directly,” retaining their ZEC policies without losing their capacity value, the note forecasts. 

States like Virginia that are served by one dominant vertically integrated utility “will now have the latitude to effectively pull them out of PJM's capacity market altogether,” the analysts wrote, while Ohio may seek to pull out the nuclear plants now slated for closure under FirstEnergy’s bankruptcy for its generator division. 

While this could have negative consequences, it could also reduce reliance on a capacity market construct that has its fair share of critics.

So many questions, so little time

There are many potential problems with the resource-specific FRR Alternative option — and a boatload of uncertainties. FERC’s ruling acknowledges that its plan “would essentially create a bifurcated capacity construct — resources receiving out-of-market support and a commensurate amount of load would be outside of the PJM capacity market.” While it stands by its view that it would improve the “integrity of the PJM capacity market for competitive resources and load,” it does acknowledge that it will do so by creating a “relatively smaller” pool of market-based capacity.

FERC’s ruling also leaves the bulk of details on how the resource-specific FFR Alternative option would work in the form of questions to PJM stakeholders, with no clear guidance on how it intends PJM to comply. Some of the most fundamental concepts are left open to question, such as “the appropriate scope of out-of-market support,” identifying what forms of state subsidies will trigger FERC’s new rules, “the types of MOPR exemptions that should be included,” or what will get to be left out of them. 

“I think that the final determination of what qualifies as a subsidized resource will be very contentious,” Orvis said.

FERC’s ruling also asks parties to comment on the kinds of specifics that can derail new market constructs if not worked out in advance, such as “whether part of a resource should be eligible for the new resource-specific FRR Alternative, as well as how to address resources with split ownership”; “the length of time resources receiving out-of-market support who chose the resource-specific FRR Alternative must remain outside of the PJM capacity market auction and the mechanism by which such resources can return to the auction”; and “the best approach to ensure locational resource adequacy needs are met after removing load and resources from the capacity market.” 

“Finally,” the ruling notes, “some intervenors raise the question of whether federal sources of out-of-market support should be addressed by Commission action,” dropping into the conversation the potentially massively disruption that could occur if the Trump administration pushes through its plan to force utilities and customers to buy power from uncompetitive coal and nuclear power plants under its national security authority. 

Unfortunately, because FERC has opened a “paper hearing” on this issue, none of these issues will be open to discussion by stakeholder groups, as would be common for most proposed market changes of this magnitude. Instead, parties will have 60 days to file their own comments, and then 30 days to read and respond to everyone else’s, giving them no forum in which to negotiate, cooperate or otherwise manage the process leading up to a final decision. 

FERC Commissioner Cheryl LaFleur, the body's other Democrat and "no" vote in Friday’s ruling, reserved the bulk of her dissent to address this aspect of the decision. LaFleur warned that FERC’s choice of a paper hearing with no opportunity for workshops, conferences or any other form of ex parte discussions has left it “hamstrung in its ability to openly and honestly engage with the states about whether this proposal will meet their needs, and how they might operate under this construct.” 

“Let’s be clear: Through its action today, the majority signals its intent to adopt, through a 90-day paper hearing, the most sweeping changes to the PJM capacity construct since the market’s inception more than a decade ago,” she wrote. “Given this lack of clarity, today’s order injects significant uncertainty into how the PJM capacity construct will work going forward, and therefore how states and market participants should prepare for these transformative changes.”