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Mandating Federal Renewables

The importance of getting the REC markets right.

Fortnightly Magazine - January 2010

place, the United States will have to compete for these credits with Europe and countries that have signed the Kyoto protocol. Selling the credits in the market will further reduce the need for subsidizing renewable energy generators, as these added revenues would improve the financial returns of such projects.

RECs in Electric Wholesale Markets

Thus far, the impact of RPS requirements and RECs on wholesale prices has been quite limited. The Lawrence Berkeley National Laboratories, in a study published in 2008, has estimated that this overall impact was less than 1 percent of rates. 1

But this situation likely will change in the coming years as more states implement RPS requirements, and it certainly will change if a federally mandated RES is implemented. Today, renewable energy doesn’t represent a significant portion of U.S. generating capacity—less than 4 percent of the total installed capacity—or energy generated. For example, under a federally mandated RES of 20 percent of energy by 2025, and assuming full compliance is achieved, the United States will require an additional 255 GW of new renewable generation. Such a massive deployment of capital will impact retail rates by at least 11 percent—or 1.1 cents per kWh. 2 To minimize the impact of this potential capital deployment, a combination of market forces and regulation can be used to increase the coordination of inter-regional energy flow and local REC markets.

First, the regions in the United States with the most favorable wind conditions happen to be located in the West and Midwest, far away from load centers. Developing wind generation in these regions might be highly cost effective because these assets would have high capacity factors and would require a minimal amount of backup generation from such traditional sources as natural gas. As a result, levelized wind energy costs potentially could fall by 20 to 30 percent. However, due to the localized nature of utility markets in the United States, challenges arise when trying to provide infrastructure—such as transmission—to support these new generation assets. To date, there’s been little consensus on how to resolve cost allocation issues ( i.e., who benefits from a project and who should pay for it). What is clear is that the grid would benefit if transfer capacity between regions were increased. This increase in transfer capacity between interconnections would allow regions rich with intermittent renewable energy to import base-load energy on days when the sun doesn’t shine or the wind doesn’t blow. It also would allow them to export energy to other regions when available renewable energy exceeds local requirements.

Second, new nuclear generation should be considered eligible for RECs under this nationwide market. Nuclear is the only current base-load, high-capacity factor and at-scale technology that is virtually carbon free. Allowing nuclear to be eligible for RECs might accelerate the nuclear renaissance by attracting investors with potentially higher returns. This revenue stream could, under certain scenarios, reduce the need for loan guarantees from the U.S. government. Speeding the nuclear build up would help mitigate the dash-to-gas effect that market analysts have been predicting. Under aggressive greenhouse-gas (GHG)