In the aftermath of the March 11 earthquake and tsunami, questions are arising about the safety and survivability of reactors located in geologically active areas. Major changes might be required...
Carbon Costs: The Coming Battle
Where are prices going, and where have they been?
in almost all cases. A carbon price of more than $120/ton would be needed before gas would firmly displace coal in the generation stack, an unlikely price given concerns about reducing carbon output without wrecking the American economy.
Walking through the four price levels, at a $7/ton price in PJM, power prices could be expected to rise $3.71/MWh, assuming the marginal generator stayed the same. Coal spark spreads would drop by $6.86/MWh. Increasing this carbon price to $10/MWh, power prices would rise by $5.30/MWh, with coal units giving up $9.80/MWh in spark spreads. Increasing the cost to the recent EU price, $22.63/ton, would push power prices up by $12/MWh, with coal units seeing a spark spread drop by $22.18/MWh. Finally, setting the carbon price at $30/ton would increase wholesale power prices by nearly $16/MWh, while coal units would see a hit of $29.40/MWh. At the outset, a carbon price would be paid for by essentially two groups, consumers in the form of higher power prices, and coal generators who would lose the large spark-spread advantage that has fueled the recent boom in new coal generation, requiring project developers to make their pro formas work with sharply reduced peak-power net revenue expectations.
Natural gas is rarely the marginal fuel generator for the off peak, though its share of the off-peak hours is rising in the Midwest. Given coal’s dominance as the top-of-the-stack generator for the off peak, and that fuel’s relatively high costs to spark that would occur in a carbon-constrained environment, off-peak prices likely will rise further than on-peak pricing, narrowing the spread between the two and helping to smooth out the peaks and valleys of hourly power prices, even as load remains close to the same levels. Such a narrowing would see pumped hydro storage units, which depend on a wide spread to recover costs, be an inadvertent loser in such a pricing environment, while natural-gas units would encroach upon coal’s dominance of the off peak the more the carbon price rises.
Developers have been encouraged by market factors to accelerate construction of dual-fueled generators in the Northeast. Such generators typically switch to residual or other petroleum product to produce power when natural gas is either unavailable, has been sold as part of a peak-shaving agreement, or is more economic to sell the gas. While residual fuel often shows a higher spark spread to natural gas in the winter, despite less efficient operations, the fuel is often hampered by environmental permitting constraints.
These additional operating costs require a significant discount for liquid-fired generation to take the place of natural gas. Any carbon cost will hit the liquid generation portion of a dual-fueled generator much more so than the natural-gas portion, diminishing the advantage a dual-fueled generator has, and increasing wholesale power prices more so than regions that do not depend on petroleum liquids generation for peak loads.
From an economic perspective for generators, winners will include nuclear, hydro, and wind generation units where revenues are determined by the clearing price of the most expensive dispatched generator. These units will see increased