The state of wholesale power markets: What's wrong with proposed changes in Eastern RTOs?
In part 2 of the series, Energy Innovation's Robbie Orvis and Eric Gimon critique proposals for capacity auction changes and carbon adders
The following is the second of a three-part guest post series from Robbie Orvis, policy design projects manager, and Eric Gimon, senior fellow at the analysis firm Energy Innovation.
In part one of this series, we discussed why generators are struggling to make ends meet in wholesale power markets, summarizing the reason for low revenues in one word: overcapacity.
In many markets, oversupply is chasing after flat or decreasing demand. Coupled with very low natural gas prices, energy and capacity prices are at all-time lows, pinching generators. In response, several states have provided subsidies or out-of-market support for plants that would otherwise retire. This, in turn, exacerbates overcapacity.
Generators that have not benefited from these recent state policies are now asking market operators for new rules to increase revenue, making unsubstantiated claims about reliability risk from state policy support for certain resources. In response, three market operators — ISO-NE, PJM, and NYISO — have proposed new rules.
This article analyzes the proposed market reforms and evaluates each on policy merits. We consider how these reforms would address the near-term overcapacity issue, evaluate long-term market impacts, and assess how well they integrate market goals with state and customer goals.
How state policy interacts with capacity markets
Several market operators trade capacity (megawatts) in addition to energy (megawatt-hours). In forward capacity mechanisms (FCMs), market operators run an auction that selects plants to receive a payment for being available to generate electricity at a future date. Plants bid into FCMs based on the expected amount of revenue needed outside of the energy market and other sources (e.g. subsidies) to make them economic.
State policy can impact FCMs two ways. First, units receiving state subsidies can bid into the auction at a lower price because they have additional revenue. These subsidized units are therefore selected more often in the auctions than they otherwise would have been, given their lower bids. Consequently, the most-expensive unit selected in the auction, which sets payments for all units, is now a less-expensive unit, lowering prices for everyone.
Second, if state policies incent additional resources to be built beyond those selected in the FCM auction, the result is generation overcapacity, which exacerbates oversupply impacts, for example further depressing energy market prices.
In light of new state policies coupled with the above concerns, PJM and ISO-NE have each proposed changes to their capacity markets, moving each to a two-staged process.
The two-stage capacity market proposals
PJM and ISO-NE have proposed similar changes to address the low revenue challenge for generators not supported by recent state policies. Both proposals involve running the capacity market in two stages.
Under PJM’s proposal, the market operator solicits bids from generators the same way it does today: In the first stage, PJM runs the capacity market like it has in the past, keeping “subsidized” units in the market. In the second stage, PJM reruns the market but uses administratively determined prices that add back state subsidies, raising payments to all resources selected by the market.
ISO-NE’s proposal also uses a two-stage approach. In the first stage, ISO-NE runs the capacity market as usual, but uses administratively determined prices that add in state subsidies. In the second stage, ISO-NE runs a different auction to pair resources that were not selected in the first auction with resources that were selected, but are open to retiring. For example, if a coal plant cleared the first auction at $10/kW-month and cleared the second auction at $2/kW-month, it could make a profit of $8/kW-month from transferring its capacity obligation to a new unit and permanently exiting the market. That’s nearly $50 million for a 500-megawatt (MW) plant. The goal is to pair units that are willing to retire with other resources that are not selected in the first auction, in a pay-for-retirement scheme.
The reasonable intention of two-stage capacity markets
While neither of these proposals is likely to address current market concerns, the ISO-NE proposal rightly aims to correct the supply-demand imbalance by encouraging uneconomic units to exit. This highlights the merit of encouraging retirements in the short term in an effort to bring supply and demand back into equilibrium.
The cons of two-stage capacity markets
Both proposals introduce significant problems. First, the proposals require grid operators to calculate subsidies for different resources. Yet subsidies come in many forms – tax credits, land leases, sales tax exemption, and worker training, to name a few – and vary by region and over time. RTOs are not set up to handle this type of ongoing analysis.
Second, the proposals will likely over-procure resources and further depress energy market prices. In PJM, market operators use a demand curve when choosing the amount of resources procured. Lower resource offer prices mean more capacity is procured. However, because units know their prices will be inflated in the second stage of the auction when subsidies are added in, they are likely to lower their offer prices, resulting in even more capacity being procured. In ISO-NE, if resources don’t clear the second stage of the market but are built anyway due to state policy, too much capacity will be built.
Finally, the proposals artificially increase payments on the backs of customers. Higher payments are likely to exacerbate oversupply because uneconomic units will be able to stay around longer. With more units online, energy prices will be further depressed, furthering the stretch of low prices for generators.
The upshot: Two thumbs down for two-stage markets
Both proposals, by trying to accommodate state policy rather than simply acknowledge it, put forward clunky, discriminatory solutions that will likely continue driving overcapacity and exacerbate existing market conditions.
The carbon adder proposal
Both NYISO and PJM are considering a carbon adder (CA), which adds a price to generator offers in the energy market based on a price of carbon and the emissions intensity of each plant. Economists like the CA because it aligns the long-term carbon reduction policy goal with market signals.
In practice, though all polluters pay the CA, they also receive higher payments based on the emissions intensity of the last (marginal) unit selected by the market. Generators whose emissions intensity is lower than the marginal unit make more money, while dirtier generators are penalized. In aggregate, generators are likely to increase profit. The financial and emissions impact of the CA is significantly dependent on the level of the carbon price over time.
The pros of a carbon adder
A well-designed CA has potential upside. By providing a clear price for the carbon externality in power markets, the CA builds state carbon goals into the market. For example, a sufficiently high CA could raise prices enough to support existing nuclear plants through the current low-revenue period, accomplishing a policy goal some states have pursued. Similarly, it also provides extra revenue for new clean generation.
Since the marginal unit typically has higher-than-average emission intensity, a CA increases the incentive for energy efficiency, providing the largest efficiency incentive in hours when carbon emissions are highest. The CA also incentivizes generators in direct proportion to how much they emit, creating a consistent market signal to move toward cleaner resources. And because the marginal unit in periods of high demand tends to be dirtier than the marginal unit in periods of low demand, the CA increases that price differential, providing a welcome incentive for more flexible supply.
The cons of the carbon adder
Given that the CA has to be high enough to accomplish policy goals, the process for setting and adjusting the price is critical to its success. For example, to continue driving emissions reductions, the CA must increase as the fleet decarbonizes. In multi-state regions like PJM, it may be very difficult to reach agreement on a uniform price across states. If the lowest common denominator is too low for some states, they will again reach for out-of-market solutions. The key vulnerability of a CA is the need for agreement on setting and changing the price.
This challenge becomes more difficult in a two-region scheme like PJM’s, where part of the region adopts a CA and part does not, with inter-regional flows handled via a border adjustment. Border adjustments separate the physical reality of the grid with its financial management, which can have important unintended consequences, as the market is predicated on the underlying assumption that generators are paid where they generate and consumers pay where they buy power.
For example, a border adjustment will likely create large financial transfers between regions with a CA and ones without. Because resources with different emissions intensity can access both markets via financial transactions, dirtier resources will end up exporting emissions from regions with the CA to regions without the CA. The net effect mostly negates the emissions reduction from a CA, undermining incentives for new clean generation, while increasing ratepayer costs. If this happens, states will feel they need to provide additional policy support.
Finally, the CA only addresses one type of externality. States will still have reasons to provide out-of-market support for other compelling public policy reasons.
The upshot: One thumb down for the carbon adder
While a sufficiently high CA could help reduce emissions and drive healthy retirements if applied to 100 percent of each market, this approach is fraught with policy and legal risk. Most notably, creating consensus among participating states for the current and future price of the CA is likely to prove difficult, and the proposed design of the CA may undermine its ability to reduce emissions. In a single state market like NYISO, a CA is more likely to work. It could in principle lower carbon emissions, improve flexibility and help retire over-supply, but it is still unlikely to single-handedly accomplish New York’s other policy goals for electricity generation. In a multi-state market, the policy and legal risks are likely too great to overcome.
Proposed options not sufficient
None of the current proposals address the interaction between state policy and federal power markets in a sustainable way. In part three of this series, we will lay out principles for designing solutions to address short-term issues in a way that sets markets up for long-term success.