The energy industry has known for decades that federal regulators eventually would set rules under the Clean Air Act to govern emissions of mercury and other air toxics from coal-fired power...
EPA's Big Bet on Green Trading
Environmental Emissions: The cost to power markets of the Clean Air Interstate Rule depends on the ability to trade mercury.
Also leading the wave of new controls and helping determine the size of the near-term emissions and coal markets are generators in North Carolina. That state had sharp reductions of SO 2 and NOx enacted in 2002, prior to implementation of the federal rules, requiring plant owners such as Duke Energy’s Duke Power unit and Progress Energy’s Progress Carolinas to retrofit much of their coal fleet. The added value in complying with the new federal rules has encouraged Duke to fit its scrubbers sooner than originally planned, pushing installation on the five units at its Allen station up by two to three years, to 2009. Unit installation at Cliffside and Bellews Creek also will move up by one year each to 2008 and 2007, respectively, the utility said in a filing to state regulators in early April.
While there are limits under the current program in carrying or “banking” allowances from one year to the next, SO 2 maintains its value each year. And under CAIR, SO 2 allowances given out prior to 2010 will be usable on a one-for-one basis from 2010 on, while those allocations made in 2010 and after will require two allowances for every ton emitted. This calculation is one of the principal reasons for the rise in SO 2 prices, and for the increased volatility ( see Figure 3, p. 79 ), as coal generators seek to hoard allowances prior to 2010.
Emissions of SO 2 have been above the EPA cap each year since 2000, which has diminished the bank to about 6.5 million tons entering 2005. And while emissions were almost flat in 2004 and are estimated to be slightly lower in the first quarter of 2005 than the previous year, the bank continues to be depleted.
As much of these pollution control costs are passed directly to ratepayers or amoritized over many years, the impact on wholesale power rates may be mitigated. The choice of fuels and changes that occur as a result of these new controls will be the driver for baseload and off-peak pricing during the next decade.
Assuming most large coal plants are not retired as a result of these rules and enough capacity is maintained to meet at least that minimum demand, the power price in the Midwest will be driven by the cost of the most expensive delivered coal. Off-peak prices edged up beginning in late 2003 as prices for low-sulfur eastern coal were moving higher. If enough plants install scrubbers, then the use of high-sulfur Illinois Basin and Northern Appalachian coals may become attractive again. That depends on both the ability of the region’s producers to boost output and getting the coal to market cheaply.
The continued 5 percent per year growth of ultra low-sulfur coal from Wyoming’s Powder River Basin (PRB), which is accelerating this year, will depend on the calculation of its delivered cost in Btus against higher-sulfur varieties. A coal plant with a scrubber can choose whichever coal it wants and ignore the sulfur penalty, but without one at current emissions allowance prices, the