UNIVERSITY OF CHICAGO PRESS JOURNALS
A new paper published in the Journal of the Association of Environmental and Resource Economists provides empirical evidence that risk aversion plays an important role in the coal contracting behavior of US power plants.
In “Regulatory Induced Risk Aversion in Coal Contracting at US Power Plants: Implications for Environmental Policy,” author Akshaya Jha notes that from 1983 to 1997, US power plants purchased the majority of their input coal from long-term contracts, consistently paying contract prices in excess of prevailing spot coal prices. Jha proposes a regulatory mechanism for why power plants specifically might exhibit risk aversion when purchasing inputs, arguing that regulators in practice are less likely to incorporate high input cost realizations into the output price they set for utilities. Utilities respond to this regulatory practice by taking costly actions to reduce the variance of their input costs.
Jha specifies an illustrative model in which an expected profit-maximizing firm receives a regulated revenue stream. This regulated revenue stream only reimburses the firm for total costs below a particular “prudence” threshold. Jha demonstrates that the price-regulated firm in this framework does not minimize expected total costs, instead expressing preferences for both a lower expected total cost and a lower variance in total.
Jha estimates the degree of risk aversion exhibited by US power plants using transaction-level data on the coal purchases made by virtually every power plant in the United States from 1983–97. The spot price uncertainty faced by each plant in each month is estimated using a panel-data version of a third-order autoregressive model for the growth rate of spot prices; both the mean and the variance of this growth rate are allowed to vary by the region where the plant is located and month of year.
Jha finds that power plants facing more spot coal price uncertainty sign longer duration coal contracts, purchase contract coal from a larger number of origin counties, and pay higher contract coal prices on average. To put his estimates in perspective, Jha notes, “if every power plant purchased all of their coal from the spot market, the annual aggregate cost savings would be $2.9 billion on average.”
The results indicate that a 10% increase in spot price uncertainty is associated with 0.9% increase in contract coal prices, and that both risk aversion and relationship-specific investments are important determinants of the coal contracting behavior of US power plants. “This suggests that any empirical analysis of contracting should account for the roles played by both transaction costs and risk aversion,” Jha writes. His estimated effect of spot price uncertainty on contract prices implies that plants are willing to trade off a $1.62 increase in their expected total costs for a $1 decrease in their standard deviation of total costs. “This is far larger than the risk premiums traditionally paid in commodities markets, suggesting that price regulated electric utilities have an especially low tolerance for risk.”
Jha uses his estimate of risk aversion to conduct a simple simulation analysis of the cost-effectiveness of a carbon tax relative to cap and trade. The inputs to this simulation analysis are plant-level risk aversion, the mean of the permit price, volatility in the permit price, and the correlation between the permit price and the spot coal price. The carbon tax is set equal to the mean permit price, noting that the conditional variance of the carbon tax is equal to zero. At the central parameter values, the ratio of the aggregate costs incurred by plants under cap and trade relative to the carbon tax is 1.27. When the risk aversion parameter is set to 50% of his estimate, the relative cost-effectiveness ratio is 1.13. This relative cost-effectiveness ratio is thus highly sensitive to the assumed level of risk aversion. He concludes, “The results of my simulation analysis highlight that risk aversion should play an important role in the decision regarding which of these two policy instruments are implemented.”
JOURNAL
Journal of the Association of Environmental and Resource Economists
DOI
METHOD OF RESEARCH
Data/statistical analysis
SUBJECT OF RESEARCH
Not applicable
ARTICLE TITLE
Regulatory Induced Risk Aversion in Coal Contracting at US Power Plants: Implications for Environmental Policy
ARTICLE PUBLICATION DATE
3-Nov-2021
In many cases in the US, the coal plants are operated by regulated utilities. Satisfying the regulators is more of a concern than the chance of making more profit by speculating on the commodity coal market.
Because of energy cost adjustments, $fuel/kWh, fuel operating costs are passed through to the ratepayers so utilities have no motivation to keep fuel costs down.
But $/kWh has two factors: $fuel/mmbtu and mmbtu/kWh aka heat rate.
So efficiency or not is also passed thru so utilities have no incentive to reduce heat rate.
As usual know-it-all regulators screw it up.
Akshaya Jha appears to know little or nothing about how regulated utilities operate and apparently nothing about how the market for resources works. Every regulated utility has an obligation to demonstrate prudence on the cost side of the ledger. If the regulator fails to enforce that, it fails the customers of that utility. Its not clear from the news release on the study whether that is Jha’s argument.
On the market side the spot prices for coal identified by Jha are low because there are long term contracts for coal, leaving remaining uncommitted coal inventories that producers want to clear into the market that are somewhat in excess to demand. The normal market response to excess inventory of a natural resource is to reduce the asking price until it reaches a market clearing price.
Jha seems to be suggesting there is a phantom savings to be made for customers if utilities purchased their coal requirements in the spot market. The opposite would likely occur; the spot market price would shoot through the roof as utilities began competing with each other for essential energy input to their facilities on a daily, weekly or even monthly basis. Stability of coal supply is actually more important for an electrical utility than the input cost.
His argument is the last statement
>> “The results of my simulation analysis highlight that risk aversion should play an important role in the decision regarding which of these two policy instruments are implemented.”
In other words you need to put a really really big stick or penalty on not meeting emission targets by the use of carbon credits so the coal plants who are risk averse buy in. Otherwise the carbon credits are useless if they represent no risk.
thanks for sharing keep it up
Mods:
This guy is a spammer
If you hover over his name the link takes you to a website for jobs in Pakistan
The overwhelming rationale for the conservative coal-purchasing strategy was the desire to be able to provide power at all times. The economists who have all these great ideas for saving money if only the generators followed their recommendations don’t account for the worst case. Spot market prices between 1983-1997 were cheaper in no small part because most of the needed coal was contracted. If everybody is buying from the spot market the variability goes up in general and sky rockets when the need is greatest. Most of the time it may be cheaper but all those gains can get wiped out in short order. Furthermore, all the markets have changed since 1997 with de-regulation of many of the coal generating companies. You need look no further than Texas in February 2021 to see how well the market handled a worst-case energy shortage. In my opinion it is going to get worse – much worse.
No one seems to have learned from the California/Enron debacle of the early 2000s. Texas and the rest of the Midwest in 2021 are a fine example of that, and the stupidity lingers on.
CO2 poses no risks to the environment. Hence, no ‘carbon’ taxes are needed. They are nonsolution to a nonproblem.