Why Marginal Pricing in Wholesale Electric Markets May Need Reform
As the United States attempts to integrate more renewables into its electric system to achieve a zero-emissions grid, it’s time to ask why more of the financial benefits of low-cost renewable resources are not being passed on to customers. In particular: Why are customers in so many states that participate in FERC-regulated wholesale electric markets (such as Regional Transmission Organizations and Independent System Operators) paying more for their electricity than customers in traditional, vertically integrated, rate-regulated utility states?
According to Energy Information Administration data, many customers living in states with RTOs and ISOs pay more per kilowatt hour (kWh) than customers in non-RTO states. In 2019, the national average price per kWh for residential customers was 13.01 cents/kWh. In the southeastern states, where there is no RTO, the average was 11.83 cents/kWh (ranging from 10.87 to 12.99 cents/kWh). But for states in RTOs, the price was much higher. In California (CAISO), the price was 19.15 cents/kWh; Massachusetts (ISO-NE), 21.92 cents /kWh; New Jersey (PJM), 15.85 cents/kWh; and New York (NYISO), 17.94 cents/kWh. Of course, there are some states in RTOs with rates lower than the national average and some with higher rates than those listed. But the point is that being in an RTO does not necessarily mean that customer retail rates are lower than non-RTO states.
Even in Texas, where the residential retail rate in 2019 averaged 11.76 cents/kWh, the savings may not be what it seems. While examining the failures of ERCOT during the winter storm, journalists at The Wall Street Journal determined that “deregulated Texas residential consumers paid $28 billion more for their power since 2004 than they would have paid at the rates charged to the customers of the state’s traditional utilities.”
Despite the evidence, we are constantly told that “competitive” electric markets have saved billions of dollars, and therefore that all states should operate under an RTO.
Unravelling these competing claims is difficult mainly because the analysis is usually comparing prices now to where they were predicted to be – in other words, there are many assumptions about price but few ways to prove the economic conclusions.
So if retail rates for customers are lower in many states that have not joined an RTO and still receive service from vertically integrated, rate-regulated utilities, then such information needs to be considered when advocates push for more states to join RTOs. Moreover, we need to pay attention to the warning signs in places like Texas and California where reliability is decreasing.
Unlike traditional regulation of vertically integrated utilities – in which public-service commissions establish rates on a cost-of-service basis – RTOs use competitive marginal-cost auction markets to set a clearing price for energy (some also do so for capacity). Under this market process, the amount of electricity that the RTO predicts is needed at any given time is published, and electric generators then bid to serve that need. The last megawatt of generation needed sets the price for energy paid to all the generators who clear the market.
When the RTOs and their marginal pricing models were developed in the late 1990s and early 2000s, most of the electric grid got its energy and capacity from resources that used fuel to generate electricity – coal, nuclear, and natural gas, along with hydro. Because the demand for electricity would rise and fall depending on the time of day (the load curve), generation resources were generally stacked in the bidding to serve load. Coal and nuclear tended to run 24/7 and served the base load. Their capital costs were generally high and their operating costs, including fuel costs, relatively low.
Natural gas would serve the intermediate and peak load. Natural gas plants had lower capital costs but relatively more expensive fuel costs. Because natural gas generation at the time was usually the most expensive and most flexible resource, the last selected natural gas generating unit would usually set the energy clearing price. This meant that all the generation resources selected would be paid the natural gas resource clearing price for energy regardless of their costs – including at the peak times of day, when scarcity would drive up the overall price for energy.
The economic benefit of this system was that the markets would motivate the development of more efficient generation technology and the cheapest fuel to meet the needs of the grid. Arguably, and as many studies concluded, this incentive model helped reduce overall wholesale electric rates. These savings were also spurred by a combination of cheap natural gas, additional subsidized renewables, and low load growth.
But things have changed in the electric markets since they were first developed. Today, we see more and more intermittent renewables resources entering the energy markets. These resources have no fuel costs and receive substantial government subsidies such as production tax credits, investment tax credits, and state subsidies.
Because marginal pricing means that the energy price set by the last resource picked is paid to all resources that clear the market, renewables with little to zero costs are paid the same amount of money as dispatchable on-demand resources – usually a natural gas plant. (Of course, this is a little more complicated because markets use locational marginal prices (LMP), which include things like transmission congestion costs and line losses, in addition to the system energy price.) And because of the nature of the RTOs, this means the actual lower-cost benefits of renewables – no fuel, tax credits, and RECs – do not always flow through to end-use customers. This arrangement can be compared to states with rate-regulated utilities under a cost-of-service model, where the utility is usually obligated to pass fuel, tax, and operating savings to customers.
So even though renewables can provide a benefit in lowering the overall clearing price for energy, there will come a point – if we have not already reached it – where there will be so many wind and solar resources bidding into the RTO markets that marginal clearing prices no longer benefit customers. Paradoxically, though all the financial benefits of these resources may not be flowing to customers, the overall effect on the grid may be to suppress prices – and make dispatchable-on-demand generation resources needed for system reliability unable to survive economically.
As policymakers look to electrify the energy economy and achieve zero emissions for the electric grid, Americans will still demand affordability and reliability. We should consider ways to reform RTOs in order to pass more of the economic benefits of renewables to customers and make sure that the grid maintains reliability. We should also acknowledge that some parts of the country have determined that the best way to achieve clean energy goals, ensure reliability, and promote affordability is through state-regulated utilities with cost-of-service regulation.
Bernard L. McNamee is a former commissioner of the Federal Energy Regulatory Commission and is the Street Distinguished Visiting Professor of Law at Appalachian School of Law.