U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Analysis & Projections
Appendix A-Summary Table
Appendix B-Estimating Price Impacts of the BCES12 Small Retailer Exemption
Appendix C-Map of NEMS Electricity Market Module Regions
Appendix D-Request Letter and Bill
Scenario Case Data
Analysis of the Clean Energy Standard Act of 2012
Release date: May 2, 2012
This report responds to a request from Senator Jeff Bingaman, Chairman of the Senate Committee on Energy and Natural Resources, for an analysis of the Clean Energy Standard (CES) Act of 2012. The request letter and the text of the proposed legislation are provided in Appendix D. The request follows a previous study1 performed by the U.S. Energy Information Administration (EIA) in November of 2011, also at the request of Chairman Bingaman. In the current study, the policy is compared to EIA's early-release Reference case scenario from the Annual Energy Outlook 2012.
A CES is a policy that requires covered electricity retailers to supply a specified share of their electricity sales from qualifying clean energy resources. The impacts of a CES can vary substantially based on specification of policy details, and this analysis applies only to the specification designated in Chairman Bingaman's 2012 request and the associated bill, the Clean Energy Standard Act of 20122 (BCES12), as described below:
- All generation from existing and new wind, solar, geothermal, biomass, municipal solid waste, and landfill gas plants earns full credits. Hydroelectric and nuclear generation from capacity and uprates placed in service after 1991 earns full credits.
- Generation from nuclear and hydroelectric capacity placed in service prior to 1992 does not receive any credits, but the total generation from these two sources is deducted from the overall requirement for credits and deducted from the sales baseline of those owning them or purchasing their power.
- Partial credits are earned for generation using specific technologies fueled by natural gas or coal based on a calculated crediting factor that reflects the carbon intensity of each technology. More details on this crediting scheme can be found in the original BCES report1. In addition, generation from combined heat and power (CHP) facilities that have an overall system efficiency of greater than 50 percent qualify for credits on a similar basis. However, CHP facilities that trade credits must also hold credits for any CHP generation used on-site.
- The Secretary of Energy will also establish additional credits for CHP facilities based on the greenhouse gas reductions from the facility compared to a stand-alone thermal system. This provision requires discretionary input not specified in the bill, and is not analyzed in this report.
- The carbon intensity of biomass generation will be determined by the Secretary of Energy based on a National Academy of Sciences (NAS) study specified in the legislation. For purposes of this report, EIA assumes that biomass generation is carbon-neutral, and biomass is thus assumed to earn full credit for its generation. While this assumption is consistent with assumptions made in the Reference case and current EIA reporting conventions, the resulting NAS report may result in some biomass facilities earning less-than-full CES credit for their generation.
- The BCES12 target for the share of retail electricity sales from clean energy sources starts at 24 percent in 2015 and ultimately reaches 84 percent in 2035. Based on discussion with Chairman Bingaman's staff, the analysis in this report assumes that the target remains constant after 2035, and that the policy does not expire.
- Small electricity retailers are exempt from BCES12 compliance. This exemption applies to all retailers with sales less than 2,000,000 megawatthours (MWh) in 2015, with the exemption level linearly decreasing to its terminal level of 1,000,000 MWh in annual sales for 2025 and beyond.
- Covered electricity retailers may also comply by making an alternative compliance payment that is 3 cents per kilowatthour in 2015, increasing at an inflation-adjusted rate of 5 percent per year.
- CES credits can be banked for use in a subsequent year.
The BCES12 alters the projected generation mix, significantly reducing the role of coal-fired generation, while increasing the role of nuclear, natural gas, and non-hydropower renewable technologies. Coal-fired generation decreases significantly under the BCES12, falling to 25 percent below the Reference case level in 2025 and 54 percent below the Reference case level in 2035. Conversely, natural gas-fired generation increases under the BCES12, with the greatest impact relatively early in the projection period, prior to significant new renewable or nuclear capacity coming online. In 2020, natural gas-fired generation is 13 percent above the Reference case. By 2025, this differential has fallen to 10 percent, and by 2035, natural gas-fired generation under the BCES12 is only 8 percent higher than in the Reference case. In absolute terms, most additional natural gas-fired generation occurs in the electric power sector; however, total combined heat and power (CHP) generation fired by natural gas does increase substantially due to the BCES12 provision that allows some CHP generators, to a limited extent, to sell BCES12 credits (see the Policy Description section). BCES12 CHP generation fired by natural gas exceeds the Reference case by 8 percent in 2025, and by 21 percent in 2035.
Nuclear generation increases substantially under the BCES12 policy. More than 80 gigawatts of capacity is added by 2035, compared to less than 10 gigawatts in the Reference case, resulting in 2025 nuclear generation exceeding the Reference case by 16 percent and 2035 nuclear generation exceeding the Reference case by 62 percent. Although pre-1991 nuclear capacity does not receive credits, its generation is removed from the baseline of required clean energy sales, so there is an incentive not to retire existing units beyond those already retired in the Reference case. Furthermore, due to the significant number of coal-fired plant retirements–97 gigawatts by 2035 versus 33 gigawatts in the Reference case–there is greater need for additional baseload capacity. The relatively high credit price combined with the need for additional baseload capacity and CES-compliant generation all contribute to the significant nuclear capacity additions in the latter part of the forecast. The implications of a scenario in which new nuclear builds are highly constrained are discussed at the conclusion of this section.
As shown in Table A1, there is virtually no generation from plants that use carbon capture and sequestration (CCS) technologies under the BCES12, even though CCS technology is awarded nearly a full credit under the BCES12 specification.
Non-hydroelectric renewable generation increases significantly under the BCES12, exceeding the Reference case by 42 percent in 2025, and 34 percent in 2035, with wind and biomass exhibiting the largest increases. Although the contribution of solar appears to be relatively unchanged, the underlying market structure actually shifts significantly. Projected end-use solar photovoltaic (PV) generation in 2035 exceeds the Reference case by 71 percent under the BCES12, but electric power-sector solar PV falls 68 percent below the Reference case in that same year. Most of the later-term model solar PV capacity builds in the Reference case occur in the CAMX (California) region. Under the BCES12, additional combined-cycle natural gas and end-use PV capacity comes online prior to when PV becomes cost-competitive in the region. This tends to reduce the peak load of the region, and also reduces the cost of fuels potentially displaced by the utility PV, which delays the market-based development of PV in the electric power sector.
Projected annual electricity sector carbon dioxide emissions decrease significantly under the BCES12, to 20 percent below the Reference case level in 2025 and 44 percent below the Reference case level in 2035 (Figure 3, Table A1). For context, total energy-related carbon dioxide emissions in the BCES12 case trail the Reference case by 8 percent in 2025, and are almost 18 percent lower than in the Reference case by 2035. The BCES12 level of energy-related carbon dioxide emissions in 2035 is roughly consistent with a 20-percent decline in emissions from a 2005 baseline.
In the early part of the forecast, average delivered natural gas prices under the BCES12 are higher than in the Reference case, as natural gas-fired generation plays an important role in BCES12 compliance during the first decade of the program. Increased electric power consumption of natural gas results in upward pressure on prices. However, this effect attenuates toward the latter part of the forecast as additional non-hydro renewable and nuclear capacity comes online.
Electricity prices, generally speaking, do not experience a significant impact until after 2020, as compliance with the BCES12 becomes less a matter of using natural gas and biomass at existing facilities, and more a matter of requiring investment in new combined cycle, renewable, and nuclear capacity. The projected average end-use electricity price under the BCES12 exceeds the Reference case by less than 4 percent in 2025, but that difference grows to 18 percent by 2035.
However, because electricity retailers with sales under a given level are exempt from the BCES12, average price impacts do not capture what may be a considerable divergence in the price impacts on customers of exempt and non-exempt electricity providers. Price impacts will also vary depending on the State-level regulatory structure in place, and on regulator discretion. These regulatory factors will affect or determine how credit revenues and expenditures are realized in retail electricity prices. If the BCES12 credits from these generators generally flow with the electricity to the small utilities they serve, the electricity prices to the customers of the exempt providers could actually fall because of revenue they earn selling the credits to non-exempt providers. Using an estimation described in Appendix B, results suggest that there is minimal divergence between covered and exempt utilities in the early years of the BCES12, but that the potential for large divergence increases as the BCES12 target increases. By 2030, depending on the region, providers covered by the BCES12 program may pay from 3 percent to 30 percent more than providers exempt from the BCES12 in the same region3.
The BCES12 does not lead to large use of the alternative compliance payment (ACP) option; a relatively small amount of ACP payments are made in the last few years of the projections, but these may arise as an artifact of the modeling approach.
Constrained New Nuclear Capacity ScenarioAs explained above, increased nuclear generation is a key compliance option in the BCES12 case. However, there is uncertainty about the ability of the nuclear industry to ramp up quickly even with the incentives that will be provided by the CES. While new nuclear capacity is once again under construction in the United States, it will be some time before a broad expansion could be expected. With these uncertainties in mind, EIA also looked at a case that assumed that no new nuclear capacity is built, aside from planned additions in the Reference case. Compared to the BCES12 case, natural gas generation in 2035 is about 11 percent higher and renewable generation is about 32 percent higher in an effort to meet the requirement with other qualifying sources. Most of the growth in renewable generation is projected to come from wind and solar generators. The price for clean energy credits and electricity prices are projected to be higher in this case, while the reduction in energy-related carbon dioxide emissions is smaller. With nuclear power builds limited to plants already in the pipeline, ACP payments are more widely used than the BCES12 case by 2035.
3This assumes that baseline prices for both exempt and covered retailers are equal to regional average prices. Prices can range significantly from provider to provider within a region, based on a number of factors, including the size of the utility.