Blog Series – Part 2: DOE’s Grid Resiliency Pricing Rule

Blog Series – Part 2: DOE’s Grid Resiliency Pricing Rule

Compounding Inequality for Customers

This second blog in a series discussing the Notice of Proposed Rulemaking (NOPR) issued by the Department of Energy (DOE) examines potential adverse effects on electricity customers. Aside from the debate around whether this NOPR would improve grid resiliency, the proposed pricing rule can fundamentally alter wholesale electricity markets. However, since the proposed rule fails to specify the precise mechanism for coal and nuclear plant owners to garner higher prices, we explore potential mechanisms and how they might affect customers.

Baseload backed into a corner

Coal and nuclear are baseload generators with less flexibility than those fueled by natural gas or oil. Because of the time required and costs associated with ramping up, down, or even to go off-line, coal and nuclear are price takers, though coal plants have more flexibility of operational decisions based on multi-day market forecasts. Today, with low natural gas prices and the need for additional capacity beyond what coal and nuclear are bidding in as price takers, natural gas-fired plants are often setting the market clearing price.

The current issue for coal and nuclear is that these clearing prices are lower than historical prices and are causing some of these plants to operate uneconomically. It is important to note, that as price takers, these same plants were over-earning when natural gas prices were high. The NOPR aims to ensure that these plants not operate at a loss, but in fact, yield “a fair return on equity and investment.” This subsidy can manifest as alterations to the wholesale market rules and pricing or as a separate payment outside of the market. In the next few paragraphs, we demonstrate how these two mechanisms can affect customers differently.

Subsidizing or increasing prices paid to coal and nuclear plant owners

If these plants remain in the wholesale market, are treated as must-run, and bid in at a price that would yield fair returns reflecting their value, including ancillary service provision, energy prices would increase during low-demand times. During higher-demand times, however, the types of generation dispatched tends to be more flexible (quicker to come on-line, ramp up, and ramp down) but also more expensive than traditional baseload generation on a cost/MWh basis. As a result, unless the coal and nuclear generators are bidding in at a much higher price than historically, the market clearing price will be set by other generators (and result in improved economics for the coal and nuclear plants).

Critical infrastructure and industry bearing the brunt

If the proposed pricing rule results in higher energy costs during low-demand times, certain customers on time-varying energy rates could face significant increases in energy costs. At present, low-demand times occur during the night. Therefore, customers with higher loads during the night would see a higher increase in energy costs than customers with loads that occur mostly during the day. Figure 1 illustrates this scenario, where Customer A and Customer B both consume the same amount of energy during the month, yet Customer B’s energy costs increased by over 3% compared to the 0.1% increase seen by Customer A.

Alternative mechanisms and implications

Two alternative mechanisms for coal and nuclear plants to receive these benefits might be to:Two alternative mechanisms for coal and nuclear plants to receive these benefits might be to:

  1. Continue participating in the wholesale market as price takers but receive a separate payment outside of the wholesale market, still increasing energy costs overall to consumers, as the subsidy would ultimately be paid for by them anyway
  2. Enter into power purchase agreements (PPAs)

In the first scenario, the subsidy provided to coal and nuclear will be recouped through a special rider on an electric bill, which could be defined as a fixed volumetric rate (¢/kWh). This would affect almost all customers, with the greatest impact on high-energy consumers and the least impact on low-energy consumers as well as those that use behind-the-meter solar with net metering to reduce total kWhs billed. In the second scenario, coal and nuclear plants could enter long-term PPAs. However, with other PPAs available from other generators, including wind and solar as they become more cost competitive, these plants might struggle securing a PPA if their required rates are too high and there is no mandate for the PPA. Another consideration would be the location of the coal and nuclear plants on the grid. Regional Transmission Organizations can designate plants as “must-run”, requiring that they not shut down and that a payment scheme be developed for compensating plant owners for continuing to operate until replacement capacity is made available.

Conclusions and recommendations

If struggling coal and nuclear plants are deemed necessary for maintaining grid resiliency, it is imperative to find the most equitable way of passing the costs of these subsidies on to the customers. The customer base is not a single stakeholder as nuances of rate design and energy price structures can yield a significant range of impact .

The next blog in our series will examine alternate solutions to address grid reliability and resiliency including capacity performance reforms, physical and technical grid upgrades, and demand-side policy changes.

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