Ongoing litigation over EPA rules raises compliance risks and costs. North Carolina utilities, however, benefited from the state’s forward thinking.
Coal's Black Future
Turbulent politics and market trends cloud prospects for coal-fired power.
to correspondingly faster replacement.
Other considerations will help accelerate this transition. In particular, Phase II of the Clean Air Act takes effect in 2010, requiring nearly 200 additional existing coal plants to retrofit to reduce sulfur dioxide and nitrogen oxide emission levels. The additional pressure of prospective GHG restrictions makes those investments even less attractive.
The logic of GHG regulation cuts both ways. Most politicians favor implementing GHG restrictions through some sort of economy-wide cap-and-trade scheme that puts a market price on GHG-emission allowances. But at what price? The lowest price that will hold economy-wide emissions flat (much less reduce them) must be high enough to motivate the replacement of existing coal-fired plants. At today’s natural-gas prices, that means emissions allowances trading at $30 to $40 a ton or higher. Conversely, an allowance price in that range will motivate ample volumes of conversion, so the price need not go much higher for many years. In effect, the price of natural gas sets the price of emissions allowances, over a fairly-wide range.
This is happening in other jurisdictions. The European Union (EU) has imposed a broad-based cap-and-trade program on its GHG emissions. That program had a clumsy start, with an unsustainable level of emission allowances issued in the first round. But it now has moved to a second round, with allowances more closely managed. The market has priced these second-round allowances at $30 to $40 a ton, because the cost of converting from coal to natural gas is roughly the same in Europe as it is in North America.
It’s worth noting how all this would concentrate America’s response to greenhouse gases in a few key regions. The mix of coal-fired generation ranges from about 80 percent coal-fired in ECAR and MAPP down to around 15 percent in California, New York and New England generally. In particular, an economy-wide cap-and-trade program would have coal-light regions buying up emissions allowances from coal-heavy regions, which would use the proceeds to fund conversion away from coal.
California’s current dilemma illustrates this point nicely. The state has essentially no coal-fired generation within its borders, and only imports a limited amount of coal-generated power. Yet California recently has launched an initiative to roll its GHG emissions back to 1990 levels by 2020—an anticipated 25 percent reduction. If this reduction must come from actually abating in-state sources such as industrial plants and vehicle tailpipes, then the abatement costs likely will run to $100 a ton or more. But if in-state sources can meet their reduction targets by paying for abatements in coal-fired generation elsewhere, then the same GHG reduction can be achieved for only $30 to $40 a ton. (It remains uncertain if California will accept such out-of-state abatements as an integral part of its GHG program.)
Of course, predictions of coal’s decline assume alternative generation technologies and fuels will be available at reasonable costs—natural gas, or perhaps nuclear. For natural gas, the sticking point is supply availability at a reasonable price.
Historically, a price spread has existed between coal and natural gas. In the 1990s, when