Uncertainties

As with any long-term projections there are considerable uncertainties in these results. Among the key uncertainties are projections of the growth in the demand for electricity, future fuel prices, and the cost and performance of new generating equipment – renewable and nonrenewable. In addition, the design of the RPS program in S. 1766 could provide some incentives that are counter productive to the goal of increasing renewable generation. In the 1990s, the demand for electricity grew 2.3 percent per year. However, because of efficiency improvements in new appliances and equipment and the reduced energy intensity of the US economy, the demand for electricity is projected to grow 1.8 percent per year between 2000 and 2020 in the AEO Reference case. If the historical growth were to continue, the need for new capacity – both renewable and nonrenewable – would be larger and it could be more difficult to comply with the RPS.

Since natural gas plants are expected to account for most of the new capacity added over the next 20 years, future natural gas prices are important in determining the credit price needed to make new renewable plants competitive with other generation options. If natural gas prices turn out to be lower than are projected in this report, the renewable credit needed would be larger. Conversely, it would be lower if natural gas prices turn out to be higher than expected.

Projections of the future cost and performance of new generating equipment are always difficult, particularly for technologies that currently have little or no market experience. Nonhydroelectric renewable technologies currently produce about 2 percent of the power generated in the United States. Spurring the market penetration of these technologies with an RPS might allow developers – through mass production techniques and learning by doing – to make reductions in their costs and improve their performance. These types of improvements are incorporated in the NEMS. However, it could turn out that the current relatively low market shares for these technologies are due to high costs that cannot be easily reduced. In addition, even if renewable technology developers are successful in improving the cost and performance of their technologies their ability to penetrate the market will depend on what happens to the costs and performance of nonrenewable technologies. If renewable and nonrenewable technologies improve by similar amounts, the relative advantage that nonrenewable technologies have today would likely remain.

While there is uncertainty about the cost and performance of new generating technologies, the level of cofiring that might be stimulated by an RPS is also unknown. As mentioned, in this analysis coal plants are expected to be able to replace up to 5 percent of the coal they use with biomass when they receive a renewable credit. Without the RPS, few coal plants are expected to find it economical to displace relatively low cost coal with biomass fuels. It is possible that with the RPS incentive it might be economical for some coal plants to make modifications to allow them to use even larger shares – 10 percent or more - of biomass fuels. If this occurred these plants could satisfy a larger percentage of the RPS requirement than projected in the RPS 10 case. However, in today’s market coal plant operators are focused on how future environmental regulations, particularly any efforts to reduce U.S. carbon emissions, might impact them, and they are wary about making investments in their plants.

For both wind and biomass the level of development called for in the RPS 10 case comes with some uncertainty. The RPS 10 case shows wind capacity increasing from approximately 2 gigawatts in 1999 to 52 gigawatts in 2020 – a 2,500 percent increase. While data suggest that sufficient wind resources exist to support this level of development, it is difficult to predict how the costs of development might change as developers move from the best sites to those that are less economically attractive. In some cases, developers may have to forego building on economically attractive sites because of public resistance arising from concerns about visibility or injuries to birds. In this analysis, costs are assumed to increase as developers turn to more costly sites such as those with higher interconnection costs, higher land costs, or more difficult terrain. However, there is significant uncertainty about the actual cost increases that might occur. Wind development may also be constrained by its intermittent nature which leads to the need for backup capacity to ensure that consumers’ needs for electricity can be met at all times. In this analysis, wind and other intermittent resources (primarily solar) are limited to accounting for 15 percent of a region's total generation. In some regions with intensive wind building, this constraint limits the construction of new wind capacity in otherwise low-cost resource areas. In reality, the additional cost of providing backup capacity for intermittent generators could begin to impact the cost of this technology at penetration levels below 15 percent.¹⁶ Furthermore, markets may be able to absorb penetrations in excess of 15 percent by investing in additional backup capacity and other mitigating technologies (energy storage, improved grid monitoring and control, and improved power conversion on the wind turbine) if economic and policy conditions warrant.

As with wind, data suggest that there are sufficient biomass resources to fuel the increased biomass generation projected in the RPS 10 case. However, currently there are very few coal plants that cofire with biomass. To achieve the level of biomass cofiring called for in the RPS 10 case, infrastructure to reliability gather, process and deliver the available biomass to coal plants would have to be developed. This analysis includes estimates of the costs of building this infrastructure, but given the low level of biomass cofiring occurring today, these costs are highly uncertain. In addition, if power sector carbon emissions reductions were required, the potential for cofiring in coal plants would be much lower because coal generation would likely be much lower.

And, finally, two provisions of the RPS program in S. 1766, the small utilities exemption and the restriction of credits to new renewables, may provide incentives that lead to unwanted outcomes. As mentioned in the methodology section of this analysis, retail electricity providers with sales of less than 500,000,000 kilowatt-hours are exempt from the requirements of the program. In 1999, these companies accounted for 270 billion kilowatt-hours of sales or 9 percent of total sales. In this analysis, it is assumed that the 270 billion kilowatt-hours sales figure will remain constant through 2020. However, this RPS exemption for small companies could provide an incentive for potential retail suppliers to limit their size in order to avoid having to comply with the RPS program. If this occurred, it would lead to lower renewable generation than is projected in this analysis. Of course, requiring small companies to comply could also be burdensome for them. The restriction of renewable credits to new renewables could have the same impact for a different reason. This restriction could cause renewable project operators to try to find ways to convert their existing renewable facilities into new facilities. For example, when faced with the S. 1766 RPS program, an operator of an existing wind or geothermal facility might retire it arguing that it has become uneconomical, and replace it with a new facility on a nearby site. They could argue that the new plant should get full RPS credits because it is a totally new plant and the retirement decision on the old plant had nothing to do with the RPS. The impact of this type of action would be to lower the increase in renewable generation projected in this analysis. Clearly, restricting the credit to new or upgraded facilities is done to reduce the cost of the program by avoiding paying facilities who were built without the program (what economists would call free riders).