Author – Glen Thomas and Todd A. Snitchler
Published – Sept. 9, 2019
The following is a contributed article by PJM Power Providers Group President Glen Thomas and EPSA President and CEO Todd A. Snitchler.
Utility Dive recently published an article highlighting an August 2019 analysis released by Grid Strategies that found a strong application of the minimum offer price rule (MOPR) by FERC would increase capacity costs in PJM by $5.7 billion, or 60%, annually. However, a deep dive into the assumptions and methodologies used in the Grid Strategies report reveals significant flaws that lead us to question the integrity of the analysis.
In addition, the analysis fails to consider the costs of the underlying subsidies at issue in the report. We believe that competitive electricity markets are key to sustainable environmental progress; if the goal is to achieve sustainable carbon reductions, policymakers should consider long-term, economy-wide solutions to a national and global issue instead of high-cost, one-off, temporary fixes.
The Grid Strategies report cherry-picks a 2018 PJM Market Monitor report to find the highest possible capacity price increase — produced in a completely unrelated analysis — and applies it as justification for its conclusion that the MOPR will increase the cost of capacity in PJM by $5.7 billion annually. The lofty figure is based on one of fourteen scenarios estimating capacity price changes associated with the retention of uneconomic resources that would otherwise close, including over 17,000 MW of the aging coal fleet.
Only two of those scenarios resulted in price increases and none of the scenarios attempted to distinguish between subsidized and unsubsidized capacity, a key point of the Grid Strategies report. Finally, the basis of the figure assumes the auction price would be determined after nearly 24,000 MW of subsidized resources are removed from the market — a fundamentally different policy than the one at issue in the Grid Strategies report.
The Grid Strategies report conflates two completely different policies that results in an apples-to-oranges comparison and a startling cost estimate to the market that is both incorrect and disingenuous.
We think it is simply implausible that all resources targeting a 2030 compliance date, amounting to over 14,000 MW of capacity credit, would enter the next capacity auction.
For example, the Illinois Power Agency recently reported that Illinois is only at 7% renewables and is currently projected to peak at around 10% through 2036 — well short of its 25% RPS goal. Both the $5.7 billion “rate increase” and the 24,000 MW of capacity that would be affected in the next PJM auction are dramatically overblown for every year in the foreseeable future.
The authors of the Grid Strategies report further fail to consider the locational design of the PJM capacity market. To calculate the total annual cost of a “potential policy shift” by FERC on a state-by-state basis, the Grid Strategies report simply multiplies the capacity price increase estimate obtained from the PJM Market Monitor analysis by 163,627 — the amount of capacity procured in PJM’s last capacity auction. This does not paint a realistic picture of how PJM’s locational capacity market works.
PJM is made up of multiple Locational Deliverability Areas that can, and do, price at different levels across the PJM region. Since the first PJM capacity auction, only once has the entire RTO cleared at the same price. In other words, it is highly unlikely that every zone in PJM will pay the same price for capacity.
Unknown costs of state subsidies
What is conspicuously missing from the Grid Strategies report are the known costs of the state subsidies that are allowing certain resources to bid into PJM capacity markets well below their costs or at zero (thereby rendering PJM’s capacity rates unjust and unreasonable).
Based on publicly available data, the current annual cost of the subsidies paid to the resources listed in Table 3 of the Grid Strategies report is at least $2.2 billion above the market price for capacity; this number will only increase in the coming years as states make additional out-of-market procurements to meet their goals. Combined subsidies in Illinois, Ohio and New Jersey for nuclear power plants alone could approach $600 million in 2020.
Moreover, the current RPS compliance costs estimated by the PJM Market Monitor to be nearly $1 billion per year do not include ORECs for offshore wind projects in New Jersey and Maryland which will cost consumers at least $3.7 billion over the next twenty years; tack on the costs of the new transmission infrastructure that will be necessary and the figure will likely exceed $4 billion. Yet this figure only represents the costs associated with just over 25% of the New Jersey and Maryland offshore wind targets and will dramatically increase over the next few years as states make additional out-of-market procurements to meet their goals.
These costs must be considered in any thorough evaluation of any policy proposal, because in the end consumers will have to pay the costs associated with whatever state policies are implemented. A substantive comparison of all key variables instead of selectively chosen data will help ensure the best policy outcomes can be achieved.
Impacts on clearing prices
It is important to recognize that not all resources, when carved out of or excluded from the auction, would increase clearing prices, as the Grid Strategies report suggests. It has been well advertised that the subsidized nuclear plants in Illinois and Ohio, totaling over 4,000 MW, have not cleared certain previous PJM capacity auctions. In other words, their offers were too high to be selected by the market.
But the resource carve-out and “re-pricing” method does not change the auction clearing price if the resources being carved out would fail to clear the auction based on their offers. Hence, the total magnitude of existing subsidized resources — where carving them out based on their past offers would affect the clearing price — is even less than 10,000 MW and should be less than 6,000 MW.
This is a quarter of the 24,000 MW impact that needs to be presumed in order to claim a $5.7 billion rate increase and almost half of the 11,777 MW impact that yields a $1.6 billion increase. The cost when considering these important nuances is well below the $2.2 billion annual cost of the subsidies listed above.
Competitive electricity markets have been a fundamental tenet of FERC’s approach to regulation for over twenty years. FERC has a congressionally-mandated obligation to ensure just and reasonable wholesale rates, and a component of that has been FERC’s support for minimum offer price rules to protect consumers from costly, inefficient and distortive state subsidies. This approach to regulation is not new; the only thing that has changed is the magnitude of the state subsidies.
Temporary and inefficient policies
In practice, the state subsidies described above are ad hoc payments to profit-seeking companies who have convinced state legislatures that their plants: (1) are losing money in the competitive markets, and (2) have something to sell that the existing competitive market structure does not value. But the states’ answer to that has not been to pay all resources for their carbon-free attribute. Rather, the “answer” has been to have citizens make side payments to the companies seeking handouts in the state houses.
Legislatively-mandated, resource-specific policies are temporary and inefficient; upon expiration, should a state choose not to recommit resources to said policies, a resource retirement would increase carbon emissions, despite consumers spending billions of dollars.
Competitive electricity markets are key to sustainable environmental progress. Restructured electricity markets in the PJM footprint have seen carbon emissions reductions of 30% since 2005 while at the same time delivering lower costs to consumers of all types. These reductions were not the result of state mandates, but rather private investment, innovation and competition.
If the policy goal is to achieve sustainable carbon reductions, policymakers should consider long-term, economy-wide solutions to a national and global issue instead of high-cost, one-off, temporary fixes that fail to meaningfully address the problem.