A key element of the Clean Power Program proposal announced by EPA is its encouragement of states to develop and use trading programs as a method of reaching each state’s performance goal. Having set a goal for each state to meet, and outlined its four “building blocks” to meet those goals, EPA also made clear it would be receptive to multistate programs to allow for the trading of allowances.

Of course, the use of environmental commodities is well known under the Clean Air Act and in state implementation plans (SIPs). The utility sector is familiar with this tool which has also been used for reducing nitrogen oxide (NOx) and sulfur oxide (SOx) emissions from Electric Generating Units (EGUs). Like the allotments under Title IV of the 1990 Clean Air Act Amendments (the “acid rain” program) these environmental commodities delivered emission reductions at a lower cost than a facility-by-facility, command and control approach. Indeed, EPA's use of a performance standard for each state to meet appears intended to address the requirement that SIPs be measured on a state-by-state basis. The state-by-state performance standards proposed by EPA do not reflect a uniform reduction of carbon dioxide emissions from the EGU sector and appear to recognize the existing fuels and technologies which different states have available.

The reader will recall that there are presently two state-based systems using tradable carbon allowances, one a multistate program for nine northeastern states, the Regional Greenhouse Gas Initiative (RGGI), and the other an economy-wide carbon trading program in California. The states of Washington and Oregon (and other western states) were involved in forming the Western Climate Initiative and are considering a new agreement with California for trading of GHG allotments. The RGGI market is certainly a potential option for states to join. Recall that the Midwest Governors Association also had considered launching a platform for interstate trading when it appeared likely that Congress might pass national legislation, in part in order to have a role in a federal system. Now, the issue may be much simpler: how to meet the regulatory expectations of EPA at the lowest cost.

The recognition of increased renewable power as one of the building blocks may affect another potential tradable commodity: the Renewable Energy Credit (REC). Twenty-nine states and the District of Columbia have renewable portfolio standards (RPS). Under those standards, these RECs are, for the most part, tradable among regulated utilities to meet the state-specific RPS. But they are not the same as a carbon credit, and the two commodities have operated in separate trading programs. While EPA did not equate existing RPS with measures to meet the CPP proposed regulation, there may come a convergence of RECs into a CPP carbon trading scheme with new renewable generating units.

The use of tradable credits, tied into a state-based strategy, is not a unique development. Environmental trading programs have been in use for more than 20 years and are not uncommon, particularly for utilities in the Midwest and the eastern United States for other pollutants from coal-combustion in EGUs: NOx and SOx. A difference in this proposal is that EPA has set state-by-state goals based on the “best system of emission reduction” which are available to a state instead of on a regional atmospheric model. This may give states a wide range of alternatives, including trading programs, to meet those goals. Moreover, the use of state implementation programs involve more familiar stakeholders and economic considerations than is the case with the usual federal, technology-specific, standards. Once again, the use of interstate trading programs seems intended to provide a method of controlling costs for the electric sector.