In December 2019, the Federal Energy Regulatory Commission (FERC) released an order directing PJM, the electric grid operator covering 13 states plus the District of Columbia, to significantly expand its minimum offer price rule (MOPR) to mitigate the impacts of state-subsidized resources on the capacity market. The long-awaited decision came after an initial FERC order from June 2018, which found PJM’s tariff to be “unjust and unreasonable” because it allowed state-subsidized resources to artificially deflate capacity prices.
The order received immediate backlash from many groups, particularly environmental organizations, who claim that FERC’s order arbitrarily discriminates against clean energy resources in favor of incumbent fossil generation. And while the MOPR order will certainly have consequences for clean energy—not to mention an almost certain increase in costs for consumers—the reality of how this order will affect energy in PJM is more nuanced.
Under these new rules, PJM must establish resource-specific MOPRs for new and existing resources that receive (or are eligible to receive) state subsidies, including renewable energy credits used to promote renewable energy and zero-emission credits (ZECs) that are intended to keep some existing carbon-free nuclear plants online. The order also requires that new demand response, energy efficiency, and storage resources be subject to a MOPR as well, if they receive (or are entitled to receive) state subsidies.
For new resources subject to the MOPR, the price floor will be equal to a resource-specific net cost of new entry (Net CONE), which equals the revenue that a plant needs to earn during its first year in the capacity market, minus the expected revenues earned from the energy and ancillary services markets, in order to cover investment and fixed operating costs. For existing resources that receive a state subsidy but have previously cleared the capacity market, the MOPR will be equal to the net avoidable cost rate (Net ACR), which is similarly determined for each resource type and is based on the annual fixed costs minus net expected revenues from energy and ancillary services markets.
Several exemptions to the MOPR are available for generating units. Existing renewables, demand response, energy efficiency, storage resources, and self-supply resources (owned by vertically-integrated utilities) are exempt from the MOPR if they have previously cleared an auction (or have an interconnection agreement in place as of the date of the order). Similarly, units can apply for the Unit-Specific Exemption, which allows a unit to argue for a different price floor based on its own costs, or the Competitive Exemption, which allows a unit to certify that it will reject any available state subsidies in order to avoid being subject to the MOPR.
PJM submitted proposed MOPR values in its last filing for each resource type for the 2022/2023 auction, which is expected to take place sometime later in the spring and will be the first to run with an expanded MOPR in place. The MOPR values for new resources are listed in Table 1. In the order, FERC tentatively approved the default MOPR values for new resources, contingent on PJM providing more information on how the numbers were calculated. For existing resources, however, FERC directed PJM to recalculate the ACR numbers, which were inflated based on calculations from 2011.
Table 1. PJM’s Proposed Minimum Offer Price Rules (MOPRs) by Resource Type
|Default MOPR (new resources)
Are Renewables Doomed? Probably Not, But They Will Cost Customers More
While the MOPR excludes most existing renewables under the Renewable Portfolio Standards Exemption (as mentioned above), it will likely significantly restrict the participation of new renewables in the capacity market. New renewables will be required to offer initial bids at the values specified in Table 1, which are much higher than recent capacity clearing prices that ranged from $140 to $205 per megawatt (MW)-day in the 2021/2022 Base Residual Auction. These high price floors will consequently prevent most of the new capacity from clearing the market and receiving capacity revenues.
However, while the participation of new renewables in the capacity market will be limited, the MOPR may not necessarily discourage the deployment of renewables in PJM’s territory overall for a few reasons.
First, renewables in the PJM territory are not benefiting much from the capacity market even without a MOPR in place. PJM awards capacity credits to only a portion of solar and wind, which are based on capacity factors that represent a percentage of the nameplate capacity of the resource and account for the intermittency of the resources during peak summer hours. For the 2022/2023 auction, PJM’s filing states that solar photovoltaics, onshore wind, and offshore wind will receive credits for 42.0 percent, 14.7 percent, and 26.0 percent of their nameplate capacity, respectively. (These calculations are based on the contribution of each resource during summer peak hours, while accounting for the intermittency of each resource. The solar capacity value is higher because solar photovoltaics produce more during the summer peak than wind.) The result is reduced capacity revenue relative to the capacity the resource may actually provide, especially during the winter (such as the contribution of wind energy during the Polar Vortex of 2014).
In the 2021/2022 Base Residual Auction, for example, only 1,416.7 MW of onshore wind resources received capacity credit, even though the nameplate capacity of these resources was over 8,000 MW. Consequently, the majority of revenue that wind projects can earn in wholesale markets is from the energy market, which credits every megawatt hour of power generated. Solar energy has higher potential to earn more revenue in the capacity market due to its higher capacity factor, but many solar projects do not participate in the capacity market at all. (The 2021/2022 Base Residual Auction cleared 569.9 MW of solar photovoltaics, representing a total of 1,641 MW of nameplate capacity, which represents only about half of the existing projects in PJM, not including rooftop solar.)
Second, many of the PJM states have mandatory renewable portfolio standards that must be met by a certain year, with or without the assistance of the capacity market. New Jersey’s policy, for example, requires that 50 percent of electricity comes from renewables by 2030, of which 3,500 MW must come from offshore wind. Therefore, to the extent that renewables do rely on capacity revenues, the MOPR could drive up renewable energy credit prices.
Costs for offshore wind procurement may be most impacted by the MOPR. Unlike onshore wind or solar, offshore wind projects may rely more heavily on capacity markets because offshore wind has greater potential to earn higher capacity revenues relative to onshore wind (due to their peak coincident availability and capacity factors), and offshore wind has a much higher MOPR that will almost certainly prevent them from clearing the market. New Jersey’s competitive solicitations for offshore wind renewable energy credits include energy and capacity, and any revenues that these projects earn in wholesale markets are required to be returned to ratepayers. Thus, if offshore wind projects are unable to clear and earn revenues in the capacity market, then the costs to ratepayers of procuring these projects would increase. If states remain committed, these projects will likely still get built–but for a much higher price .
The Bigger Concern: Impacts to Nuclear
The generators that may be hit hardest by the new order may be the existing nuclear fleet, which depends on capacity revenues. Many PJM states—specifically Illinois, New Jersey, and Ohio—have chosen to offer financial assistance to economically struggling nuclear plants to keep these carbon-free plants online. The nameplate capacity of the nuclear plants currently receiving subsidies across these three states totals nearly 8,000 MW (EIA Monthly Electric Generator Inventory, ICF), representing nearly one quarter of PJM’s nuclear capacity.
In contrast to the exemptions available for many existing resources like renewables, the order does not offer an exemption for existing nuclear plants that currently receive state support. With the new order, these existing plants would have to bid into the market at their Net ACR, which equals a predetermined avoidable cost rate, minus any expected net revenues from the energy and ancillary services markets.
While PJM is currently revising the ACRs for each technology, the proposed numbers from its October 2018 filing showed that nuclear had the highest possible ACR value of any technology, at $631/MW-day. If this number is set high enough to result in these plants not clearing the capacity market, then nearly 8,000 MW of clean generation could be at high risk of retirement, even after states have already spent millions of dollars in zero-emission credits to keep these plants online. Retirement of these nuclear plants could lead to a substantial increase in carbon emissions, especially if they are replaced by natural gas or coal plants. In order to continue to keep these plants online, states could increase support to these nuclear plants, but this approach would raise costs for consumers and require them to pay twice for capacity.
Alternatively, if capacity market prices rise substantially as a result of the order, these plants could opt for the Competitive Exemption, as discussed earlier, and choose to forgo state subsidies so they can avoid the MOPR and earn capacity revenues. However, doing so could still be a risky decision if nuclear plants that forgo state subsidies fail to clear in the capacity market.
Notably, the order also applies to resources that are eligible to receive state subsidies, even if they do not receive them currently. While the definition of “eligible” remains unclear, it is possible that nuclear plants that are in PJM’s jurisdiction and reside in states with nuclear subsidy programs could be subject to the MOPR, even if they do not currently receive state support but technically could. Currently, over 9,000 MW in Illinois and New Jersey fall into this category (though these plants would similarly have the option to claim the Competitive Exemption).
The Biggest Concern: Cost Impacts
Above all else, the biggest impact of this rule will likely be an increase in costs for ratepayers. Since all new and existing state-subsidized resources will be subject to price floors, capacity market clearing prices will likely increase, meaning that PJM customers will pay more to obtain the same capacity.
Additionally, since most state-sponsored clean energy programs are binding, states will continue to build these resources even if they do not clear the capacity market, meaning that customers will be forced to pay for unnecessary capacity in the market, despite sufficient availability of resources outside PJM’s market.
A Grid Strategies report from August 2019 estimates the costs of the MOPR to be as much as $5.7 billion per year, representing a 60 percent increase in capacity market costs and an average increase of $6.06 on a monthly residential electricity bill. However, it is possible that the costs could potentially be even greater: when that report was released, little was known about the contents of FERC’s final order, which ended up being more expansive than many expected.
The resources least impacted by the MOPR are coal plants (other than those currently supported by Ohio state subsidies), along with existing natural gas plants. Notably, these are the most polluting resources in PJM’s jurisdiction. As a result of the MOPR, these plants could become more competitive in the capacity market relative to cleaner options, which may mean that they’ll stay online for longer than they would have otherwise, potentially increasing carbon emissions in the region.
However, given that renewables will still be built under state law, the extent to which the dispatch of resources in the energy market will be impacted by changing capacity resources is unknown. In some cases, it is possible that the coal plants might be kept online but will not run because other resources are dispatched first in the energy market, in which case there would be little impact on emissions. Emissions are most likely to rise if any nuclear plants retire as a result of the order and are replaced with natural gas or coal.
PJM has 90 days from the date of the order to submit a compliance filing. How states will react is still uncertain.