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Analysis
A. Generation
The imposition of the RPS is projected to have modest impacts on some aspects of the electricity business, including the fuels and technologies used to generate electricity, the types of capacity built, the various fuels consumed and their prices, power plant emissions, electricity prices, and resource costs.
In the Reference case, plants using fossil fuels are projected to meet most of the growth in demand expected over the next 20 years, as shown in Table 3. Increased generation from natural gas and coal are expected to be especially important; for example, between 2001 and 2025 the generation from natural gas is projected to increase from 618 billion kilowatt-hours to 1,637 billion kilowatt-hours. The share of total generation coming from natural gas is projected to increase from 17 percent to 28 percent over the same time period. Although coal generation increases by 900 billion kilowatt-hours from 2001 through 2025, its share of generation drops from 51 percent to 48 percent.
The generation from non-hydroelectric renewable resources is projected to grow from 80 billion kilowatt-hours in 2001 to 185 billion kilowatt-hours in 2025 in the Reference case, including combined heat and power applications. Much of this growth in generation from non-hydroelectric renewable resources is expected to be encouraged by various State mandates, RPS, and other programs, with a smaller amount coming from new merchant power plants. However, even with this increase in generation, the Reference case share of generation coming from these resources is only projected to increase from 2.2 percent in 2001 to 3.2 percent in 2025.
Even with the increase in renewable generation projected to result from the RPS, the mix of fuels used to produce electricity is not expected to change dramatically from the Reference case (Figure 1). For example, while generation from natural gas is projected to account for 28 percent of total generation in 2025 in the Reference case, it is projected to account for 27 percent in the RPS case. Similarly, generation from coal is projected to account for 48 percent of total generation in 2025 in the Reference case and accounts for 47 percent of total generation in the RPS case. Because the RPS is defined as a percentage of sales (excluding small utilities) minus renewable generation, when converted into the percentage of sales required to come from all non-hydroelectric renewables in 2025, it amounts to approximately 8.8 percent of sales.
The lower coal and gas generation projected with the RPS is offset by the higher renewable generation stimulated by the RPS. In the Reference case, the generation from non-hydroelectric renewable generators is projected to reach 3.3 percent of electricity sales in 2025. With the RPS, the 2025 share of qualifying renewables is projected to reach 5.6 percent of electricity sales.
The generation from qualifying renewables, shown in Figure 2, is not projected to reach the share as adjusted from the share called for by the RPS program. This is projected to occur because of the 1.5-cent per kilowatt-hour credit price cap and the 2030 sunset of the RPS. In the later years of the projections, as 2030 approaches, the number of years during which new renewable power plants will receive credits declines and, as a result, the value of the credit over the remaining years must increase to make them competitive with other generation options. In 2016 and beyond, with the RPS, the credit price needed to make new renewable plants competitive is projected to exceed the nominal 1.5- cents per kilowatt-hour. This results in retail electricity suppliers purchasing credits from the government rather than building new renewables or purchase additional credits on the private market.
Wind and, to a lesser extent, biomass are projected to be the most important renewable resources stimulated by the RPS. The increased wind generation is projected to come from new power plants while the increased biomass generation is projected to come from the increased use of biomass in coal plants – known as cofiring. Since the capital cost of cofiring applications is much lower than for dedicated biomass capacity, it is much easier to recover costs with this option given the credit cap and sunset provision. Generation from landfill gas facilities increases relative to the Reference case, but is still a relatively small contributor to overall renewable generation. With the RPS, generation from geothermal resources increases early in the projection period, but by 2025 it is within 2 percent of its 2025 Reference case level. Generation from solar resources is not projected to change with the RPS.
B. Capacity
As with generation, the addition of renewable capacity to comply with the RPS is not projected to lead to a dramatic shift in the mix of generating capacity (Figures 3). Only wind capacity is projected to make a significant change between the Reference and RPS cases. As is the case with generation by fuel, coal and gas capacity are lower with the RPS than in the Reference case. However, the combined reduction in coal and gas capacity is much less than the increase in renewable capacity. Total capacity is higher with the RPS than in the Reference case because the intermittent nature of wind resources requires additional dispatchable capacity for back-up. This intermittency also contributes to a shift in the type of natural gas capacity added when the RPS is imposed. Over the 2001 to 2025 period, relative to the Reference case, 11 gigawatts fewer natural gas combined cycle plants are projected to be added while nearly 6 gigawatts more natural gas combustion turbines are added with the RPS. Because generation from wind plants is only available when the wind is blowing, more backup capacity – generally natural gas turbines – is needed to ensure that consumers’ demands can be met at all times.
With the RPS, overall wind capacity in 2025 is projected to be almost 4 times the Reference case level. Though not broadly competitive in the Reference case, a small number of unsubsidized new wind plants are expected to be built over the course of the projections in response to relatively high natural gas prices. Over the last 10 to 20 years, the cost and performance of new wind plants has improved and they are expected to continue to improve as new plants are built. In the Reference case, the basic capital cost of new wind plants is expected to decline from $1,004 per kilowatt in 2002 to approximately $989 per kilowatt-hour in 2025. When the RPS is imposed, the revenue from credit sales is expected to make more new wind plants competitive and lead to more wind capacity being built. As more wind plants are built their capital costs are expected to decline further as manufacturers and project developers learn more about their construction and operation. For example, with the RPS the cost of new wind plants is projected to decline to $971 per kilowatt by 2025. By 2025 with the RPS, capacity factors for new wind turbines in the best wind resources improve to 44%, compared with 42% in the Reference case. However, at the same time, to reach the quantity of new wind capacity called for in the RPS case – from just over 4 gigawatts in 2001 to 41 gigawatts of wind capacity by 2025 – developers are projected to have to build on less attractive sites, such as those requiring upgrades to existing transmission lines, those with more expensive land, and those having more difficult terrain. After adjusting the $971 per kilowatt to reflect these factors the cost of new wind plants in the RPS case in 2025 is expected to be as high as $1165 per kilowatt in some of the regions with the most windy land. As might be expected, the costs of all new power plants are influenced by these factors. All new plants must incur some site-specific development and transmission interconnection costs and these costs are incorporated in this analysis. However, while wind plants have no choice but to locate where high quality wind resources are available, new natural gas plants are more flexible in their location and their developers will attempt to avoid sites that require above average development expenditures. Further, with the increasing penetration levels seen in some regions, the natural variability of the wind will have an increasingly large impact on grid operations. In these regions, the aggregate of wind turbines will only contribute 20 to 25% of their total nameplate capacity toward meeting regional reliability requirements, with the marginal wind turbine providing essentially no contribution to reliability. This means that additional “back-up” power, such as combustion turbines, will need to be purchased as well, adding to the overall cost of integrating wind into the system.
Significantly increased biomass generation comes from increased use of biomass in existing coal plants rather than in dedicated biomass facilities. Adding small amounts of biomass to coal feedstocks, up to 15% by heat value, is a relatively low investment cost option for increasing renewable fuel usage. Upgrading existing coal-fired plants to cofire biomass fuel requires modest capital expenditure compared with the construction of a dedicated biomass facility – starting at about $200 per kilowatt for a cofiring modification compared with $1764 per kilowatt for an efficient, integrated gasification combined cycle plant fueled with biomass 9. Especially in the latter portion of the projection, the sunset provision limits the period in which renewable energy credits can be used to recover capital investments. This tends to favor the lower investment cost cofiring option over new dedicated facilities, even though cofiring will tend to have lower efficiencies (based on the efficiency of the host facility) and thus higher fuel costs per kilowatt-hour of generation.
Besides wind, only landfill gas facilities are projected to appreciably increase capacity in response to the RPS. New landfill gas facilities are limited by the amount of waste that is expected to be put into relatively large landfills where gas collection facilities are economical.
With the RPS, other non-hydroelectric technologies such as geothermal, solar thermal, solar photovoltaic and ocean technologies are not projected to have net capacity additions beyond those projected in the Reference case. The RPS does result in the acceleration of some geothermal builds relative to the Reference case, but the decreasing real cap and shortening pay-back period before the requirement sunsets reduces the attractiveness of this option in the last 10 years of the projection period. By 2025 in the RPS case, geothermal capacity is 5.7 gigawatts, 100 megawatts less than the 2025 capacity in the Reference case. The relatively high capital costs of solar technologies make them uneconomical when compared to other renewable options such as wind and biomass. The various ocean technologies, either kinetic (including ocean wave, tidal, or ocean current) or thermal (taking advantage of temperature differences between surface and deep water) technologies, are in a very early stage of development and, although a few demonstration projects or other non-economic builds are possible, they are not expected to contribute to meeting the RPS. Ocean thermal efforts in Hawaii over the past 20 years have not lead to commercial development. No commercial ocean wave projects are currently operating in the United States, although a 500-kilowatt project in Britain has been completed, and plans for a 1-megawatt ocean wave demonstration plant some miles off the Washington State coast are ongoing. Current costs appear to be well over $2,000 per kilowatt, making them more expensive then other renewables, such as wind or biomass.
C. Emissions
While the RPS is projected to have little impact on sulfur dioxide (SO2) or nitrogen oxide (NOx) emission levels, it is projected to have a significant impact on the SO2 allowance market. The 9-million ton emission cap established in the Clean Air Act Amendments of 1990 (CAAA) governs the level of power plant SO2 emissions and it is projected to be met with or without an RPS. However, because the RPS is projected to induce biomass co-firing in coal plants thereby reducing coal generation, the incremental costs of complying with this cap are expected to be lower when an RPS is imposed. As a result, in 2025, the cost of SO2 allowances is projected to be 32 percent lower with the RPS than in the Reference case, while SO2 emissions remain at the CAAA cap. However, the increase in co-firing does not have the same impact on NOx emissions, because NOx emissions are mainly determined by a plants’ boiler type and emissions control equipment, rather than the fuel it is using. The RPS is projected to lead to lower carbon dioxide emissions because fossil fuel generation is displaced by carbon free renewable generation (Figure 4). By 2025, carbon dioxide emissions are projected to be 2.3 percent lower with the RPS than in the Reference case.
D. Electricity Price and Costs
The impact of the RPS requirement on retail electricity prices is projected to be small. This occurs because of the relatively low renewable share required – about 5 percentage points higher than is forecast without an RPS - and the impact on other fuel prices with higher cost renewables when the RPS is imposed. Furthermore, the price cap, initially 1.5 cents per kilowatt-hour and declining to less than 0.9 cents per kilowatt-hour by 2025, ensures that the maximum price impact will be less than 0.08 cents per kilowatt-hour.10 As mentioned, this RPS nominally calls for a 10 percent RPS by 2020, but because of the definition of qualifying renewables used and that credits are only required to cover nonrenewable generation, the actual non-hydroelectric renewable share of generation needed to meet the target is 8.8 percent.
Fundamentally, an RPS is a way of subsidizing qualifying facilities (renewables) through a fee on non-qualifying facilities (coal, gas, nuclear, and oil facilities). Without the credit revenue from the non-qualifying facilities, the renewable facilities would require higher electricity prices to be economically viable. The overall cost and price impacts of an RPS program are driven by the combination of the higher costs spent on renewables minus any change in costs for other technologies that occurs because of the RPS. In this analysis, the RPS is projected to lead to a slight decline in natural gas and coal prices that partially offsets the higher costs of the new renewables. The retail price of electricity, shown in Figure 5, is projected to be only slightly above the Reference case in the last few years of the projections when the renewable credit price is expected to reach 1.5 cents per kilowatt-hour (0.8 cents in 2003 dollars). In 2025, the nation’s electricity bill is projected to be $1.5 billion higher in the RPS case than in the Reference case. The nominal 1.5-cent cap is reached in 2016 and beyond because, with decreasing time left when the credit will be available (it sunsets in 2030), and declining real value it provides insufficient subsidy to spur additional investment in renewables.
While retail electricity prices are not expected to be significantly impacted by the imposition of an RPS, the industry is projected to face higher total costs. Over the 2000 to 2025 time period, the cumulative total electricity supplier resource costs that include fuel, non-fuel operating and maintenance costs, the capital, financing, and tax costs for new plant and equipment, and payments to the government for renewable credits, are
projected to be $3.6 billion higher in the RPS than in the Reference case. Relative to the total resource costs of the industry over the 2003 to 2025 time period, this change is small, a 0.6 percent increase from the Reference case.
The market for renewable credits that retail electricity suppliers will have to hold for generation for non-qualifying generators is expected to grow as the RPS share increases over time. Although, as shown in Figure 6, the real cost in year 2001 dollars declines after 2020, as the required share of generation remains constant, and the credit cap price does not keep pace with inflation. In 2025 with the RPS, the renewable credit market together with allowance costs paid by retail electricity suppliers to the government is projected to reach $3.6 billion ($2.5 billion in credits and $1.1 billion in allowance payments to the government). For existing coal, nuclear and oil facilities who are not projected to see significantly lower fuel prices or higher electricity prices with the RPS, the costs of holding renewable credits will reduce their operating profits. On the other hand, for existing natural gas plants, the costs of holding renewable credits are projected to be offset by lower natural gas costs.
The lower natural gas prices stimulated by the RPS does have impacts outside of the electricity sector – leading to lower residential, commercial and industrial sector natural gas bills. Wellhead natural gas prices in the Reference case are $3.95 per thousand cubic feet in 2025 (year 2001 dollars), and $3.89 per thousand cubic feet with the RPS. In 2025 the total residential natural gas bill is projected to be $290 million (0.5 percent) lower with the RPS than in the Reference case. For the commercial and industrial sectors the
bills in 2025 are, respectively, $200 million (0.6 percent) and $200 million (0.4 percent) lower with the RPS than in the Reference case.
In the Reference case, total residential electricity costs were $137.5 billion (year 2001 dollars) in 2025. With the RPS, this increases to $138.1 billion. As a result, total residential expenditures on electricity in 2025 increase by $540 million with the RPS, an increase of 0.4 percent. Electricity costs for the commercial sector in 2025 increase by $700 million (0.5 percent). Electricity costs for the industrial sector increase by $290 million (0.4 percent).
Analysis - Table 
Notes and Sources |
