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External Publications by Harrison Fell & James Glynn • September 20, 2021
The US House Energy and Commerce Committee recently released recommendations for the Build Back Better Act (the budget reconciliation legislation), including a more detailed description of one of the act’s central energy and climate plans: the Clean Electricity Performance Program. Dr. Harrison Fell, senior research scholar and co-lead of the Center on Global Energy Policy’s (CGEP) power sector group, and Dr. James Glynn, senior research scholar at CGEP, answered questions related to the general structure of this program and some potential incentive misalignment issues along with recommendations for correcting them.
Q. What is the basic structure of the CEPP and how does it differ from a traditional clean energy standard (CES)?
A. A standard CES sets a fixed target that all regulated entities must reach. Typically, it affects load serving entities (LSEs), such as vertically integrated utilities or energy retailers, so the target is usually stipulated as a percentage of the load that the LSE supplies. For example, if the CES target is 50 percent, each LSE has to make a claim to clean energy (either by directly producing or procuring non-fossil energy or by purchasing clean energy credits associated with clean energy production consumed by others) equaling 50 percent of the load they serve. If the LSE exceeds this target, it usually is allowed to bank those clean energy credits to be used for future compliance or it can sell those credits to other LSEs that would otherwise miss their targets. The regulator typically has no financial obligation in this CES, but rather is simply in charge of setting the target levels and ensuring compliance.
The CEPP, on the other hand, creates targets based on each LSE’s previous years’ clean energy percentages, and provides grants for meeting or exceeding the target and recovers payments for falling short of the target. In its basic form, the CEPP sets the given LSE’s clean-energy-as-percentage-of-load target in year t as the maximum clean energy percentage from previous years plus 4 percentage points. So, for example, if in previous years of the program a given LSE can, at a maximum, claim clean energy (production, procurement, or credits) equaling 12 percent of its load, then in the current year its target will be 16 percent. If the LSE meets or exceeds their 4 percentage point increase goal, the federal government pays a grant of $150 per megawatt hour (MWh) of clean energy claimed in the current year minus the previous annual maximum MWhs of claimed clean energy minus 1.5 percent of the load served. If the LSE doesn’t hit its 4 percentage point addition, then, in its simplest form, the LSE forfeits a payment to the government equal to $40/MWh times the number of MWhs needed to get them up to their 4 percentage point addition target. It actually gets quite a lot more complicated as one gets into year-over-year compliance or noncompliance possibilities.
Q. How will compliance be operationalized?
A. As noted above, it seems compliance will be operationalized through a market for clean energy credits. This is necessary because some load serving entities own little or no generation assets, such as energy retailers in deregulated electricity markets and some electric cooperatives. These LSEs would likely comply with the regulation via purchasing clean energy credits that serve as its claim to the CEPP-qualifying clean energy. Likewise, those LSEs that own clean energy generation assets will also likely participate in the credit market as they face an opportunity cost associated with using the credits created from those generation sources for their compliance obligations. The supply of these credits will be based on the generation from independent power producers and possibly clean-energy-generating assets owned by other LSEs.
Q. Can you discuss at what price these clean energy credits will likely trade?
A. The incentive structure of the CEPP makes this an interesting question. Consider an LSE that serves a constant 100 MWh load with a baseline clean energy rate of 0. If this LSE meets the minimum standard for a grant each year of the program (2023–2030) its end-of-the-year credit holdings would be 4, 8, 12, 16, 20, 24, 28, and 32. In this setting, the grant payment each year is a constant $375, but the credits needed to be grant eligible are growing each year—the per-unit value of credits is diminishing over the program. In this example, the value of the grant per credit falls from $93.75 to $11.72. However, the market for credits shouldn’t clear at these grant-per-credit values because if the credit price, P, is under the $150 grant rate then a given LSE that has already secured enough credits to be grant eligible could buy more credits and make $150 – P on each additional credit.
This suggests that the credit price should be near $150, but it’s actually quite a bit more complicated. The LSE’s clean energy baseline percentage, to which it must add 4 percentage points of clean energy to be grant-eligible, is based on the maximum clean energy rate it has had in the past. Therefore, if the LSE buys a bunch of credits this year to cash-in on grant payouts, it will have to buy at least that many next year, plus some more, to avoid a penalty in future years. If there is a possibility that it would not be able to procure enough credits in future years to be grant eligible then its valuation of credits now is diminished. On a related side-note, if, in a given year, total credits supplied are insufficient for all load serving entities to claim enough credits to be grant eligible, some LSEs should purchase no credits at all. Why? If credits are selling at a price greater than $40, which they almost certainly would be given the payout rate for exceeding the 4 percentage point target, then a given LSE would be better off purchasing no credits and paying the penalty than purchasing some credits but not enough to be grant eligible. Such a credit shortage combined with the asymmetric grant and payment rates will then likely lead to a separating equilibrium where some LSEs are flush with permits and others hold none.
To find a valuation for permits, LSEs need to form some expectations about the availability of permits in future years to determine if a permit shortage may be possible. That’s not a simple calculation. It requires understanding how current and future credit prices and other subsidies will drive investment in clean energy deployment. It also requires making estimates about how productive clean energy generators will be in future years, which can have considerable variation. For example, European markets are experiencing higher than normal electricity prices this year in part because wind generation in some areas is down year-over-year by about 20 percent. Such year-over-year fluctuations in wind energy are also seen across individual wind generators in the US.
Finally, LSEs have varying degrees of risk tolerance given, among other factors, their ownership structures and liquidity. This means that the degree of uncertainty about future availability of permits may affect the current valuation of credits differently across LSEs. All of this equates to making it very difficult to model what credit prices will be under a CEPP. Without knowing what credit prices will be, we don’t know what the full incentives will be for clean energy developers, which means we don’t know how much investment will be spurred by the CEPP. Without knowing how much CEPP-driven investment in clean energy we will get, it’s difficult to determine how much CEPP-driven emissions reduction we will achieve and, in the end, reducing emissions is the goal.
Q. Is there another way to avoid penalty payments other than purchasing more permits?
A. Yes, but there is a catch, at least as the CEPP is currently written. The target rate is based on clean energy as a percentage of load. Reducing load (reducing the denominator) while holding constant the number of permits held (keeping the numerator constant) increases an LSE’s clean energy as a percent of its load. However, the grant payout is denominated in MWhs: $150 x (MWhs of clean energy this year − the maximum past annual MWhs of clean energy − [0.015 x load in MWhs]). So, technically, if an LSE became grant eligible by reducing its load and the MWhs of clean energy in the given year do not exceed previous maximum MWhs of clean energy, the grant value would be negative. Obviously, this could easily be fixed by altering the grant payout rules to be percentage based (e.g., make the grant $150 x [current year’s fraction of clean energy − previous years’ max of fraction of clean energy − 0.015] x load).
Q. How could the program be enhanced or altered in other ways to more effectively achieve emission reductions?
A. A modest emissions price could complement the CEPP in several ways. A known emissions price generally increases wholesale electricity prices in relatively easy-to-model ways, which in turn gives a more clearly defined incentive for investment in zero- or low-marginal-cost clean energy (e.g., wind, solar, nuclear). This additional incentive should further clean energy investment, making credit scarcity for CEPP compliance less likely. In addition, the wholesale electricity prices under an emissions price will increase more in areas with more emissions-intensive generation (at least more emissions-intensive at the margin), which increases the incentive to build clean energy capacity in these regions. The CEPP does not include these implicit incentives to build renewables in emissions-intensive areas as it simply incentivizes MWhs of clean energy regardless of their origin. Additionally, a carbon tax would further the switch from coal to natural gas in ways the CEPP would not. The CEPP effectively disincentivizes all non-clean energy sources equally. While such a coal-to-gas switch is obviously not the long-run goal of a net-zero emissions sector, it would provide considerable interim reductions in carbon emissions and other local pollutants. Finally, a carbon price could further incentivize load reduction for LSEs that own emissions-intensive generation assets as reducing load reduces the need for generation from those sources.
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External Publications by Harrison Fell & James Glynn • September 20, 2021