Executive Summary

Background

This report responds to a request from Senators Bingaman and Specter for an analysis of S. 1766, the Low Carbon Economy Act of 2007¹ S. 1766 establishes a mandatory greenhouse gas (GHG) allowance program to maintain covered emissions at approximately 2006 levels in 2020, 1990 levels in 2030, and at least 60 percent below 1990 levels by 2050.  Gases subject to allowance requirements include carbon dioxide (CO2) from fossil fuels, the fluorinated gases reported under United Nations’ conventions (hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride), and nitrous oxide from adipic and nitric acid production.  Other gases, including other sources of nitrous oxide and emissions of methane, are not subject to the allowance requirement directly, but reductions can be credited and applied as emissions offsets.

Initially, about three-fourths of the tradable emissions allowances are distributed for free to covered entities, carbon-intensive manufacturing industries, State governments, and as incentives for agricultural carbon sequestration, power plants with carbon capture and storage (CCS), and early actions.  The remaining allowances are auctioned, with proceeds used to fund technology programs, climate adaptation programs, and low-income assistance. 

A particularly important incentive under S. 1766 is the supplemental, or “bonus,” incentive for CCS which provides additional allowances for sequestered CO2 emissions at plants over their first 10 years of operation.  The CCS bonus rate, a multiple of allowances given for each ton sequestered, ranges from 3.5 in 2012 to 0.9 in 2030 and is made available in addition to the standard offset credit for emissions reduced through CCS. 

To control compliance costs, regulated entities may meet any portion of their allowance obligation with a “Technology Accelerator Payment” (TAP).  The TAP price would effectively provide a ceiling on the allowance trading price.  The TAP price is set at $12 per metric ton of CO2 equivalent in 2012 and grows at 5 percent per year after accounting for inflation.  Expressed in constant 2005 dollars–the price units used in this report–the TAP price would start at $10.42 in 2012 and rise to $25.07 in 2030.

As requested, this report analyzes S. 1766 under alternative technology assumptions and in combination with several other energy policies including a fuel economy standard for light-duty vehicles of 35 miles per gallon by 2020 and a 15-percent renewable portfolio standard (RPS) for electricity sellers (Table ES1).  The impacts of alternative CCS bonus rates and assumptions about the potential limited availability of key carbon reduction technologies, including CCS, nuclear, biomass, and liquefied natural gas (LNG), are also examined. This analysis is based upon the Reference case from the Annual Energy Outlook 20007 (AEO2007)², as requested by Senators Bingaman and Specter.

Key Findings

S. 1766 significantly reduces projected GHG emissions compared to the AEO 2007 Reference case, but the use of the TAP provision results in emissions exceeding the 2030 target.   While the timing varies, the projected allowance price eventually reaches the TAP price in all of the cases examined, triggering an alternative to allowance submission that enables emissions to exceed the cap.  The TAP is triggered between 2017 and 2020 under Reference case technology assumptions, and between 2026 and 2027 under advanced technology assumptions. 

Relative to the respective reference cases, projected covered emissions, net of offsets, are 28 percent lower in 2030 in the S.1766 core case and 22 percent lower in the S.1766 High Technology case.  To meet the covered emissions target in 2030, a reduction of 38 to 43 percent from the High Technology and Reference case baselines, respectively, would be required.  In the S. 1766 Core case, projected covered emissions, net of offsets, in 2030 are slightly below the 2005 level or about 26 percent above the 1990 level target of 4,818 million metric tons CO2 equivalent (Table ES2).

The electric power sector accounts for the vast majority of the emissions reductions, with CCS serving as the key compliance technology in most cases.  The electric power sector is projected to account for between 79 and 91 percent of the 2030 reduction in energy-related CO2 emissions in the cases examined.  The reductions are achieved through the deployment of new coal plants equipped with CCS, together with nuclear and renewable generating plants.  Many existing coal plants without CCS are projected to be retired early because retrofitting with CCS technology is generally impractical.  The projected reliance on new coal plants with CCS stems from the bonus incentive, but the modeling result is sensitive to the bonus rate assumed and technology improvements. In the S. 1766 Core case, nearly 300 gigawatts of coal-fired plants with CCS are added by 2030, almost as much coal capacity as exists currently.  However, building this much of a yet-to-be-commercialized technology by 2030 would be extremely challenging.

In the Half CCS Bonus case, which reduces the CCS bonus to 50 percent of the levels specified in S.1766, 49 gigawatts of plants with CCS are added, while in the S. 1766 High Technology case, 128 gigawatts of CCS-equipped capacity is projected.  In these cases, nuclear and renewable technologies play a bigger role in reducing power sector emissions.  Projected nuclear capacity additions range from 24 to 107 gigawatts.  In the Limited Alternatives case, where coal with CCS technology is assumed not to be available until after 2030, the power sector would instead turn to increased use of natural gas to replace coal generation while making even greater use of the TAP provision to comply.

Only modest emissions reductions are achieved in the residential, commercial, industrial, and transportation sectors without additional policies.  Although some emissions reductions occur in the residential, commercial, industrial, and transportation sectors under S. 1766, the reductions in these sectors are small when compared to those in the electric power sector.  The energy price increases resulting from the allowance program are generally not large enough to induce consumers to make large changes in their energy use.  For example, motor gasoline prices in the S. 1766 Core case are only 19 cents per gallon, or 8 percent, higher than in the Reference case in 2030.

The S. 1766 High Technology Plus Policies case considered S. 1766 together with a 35-miles-per-gallon fuel economy standard for light-duty vehicles by 2020 and a 15-percent RPS for electricity sellers.  Under these assumptions, the transportation and other end-use sectors make greater emissions reductions, but the electric power sector still provides the vast majority of the emissions reductions.  The RPS has little incremental effect because the GHG allowance program in S. 1766 encourages an increase in renewable generation similar to what would be needed to comply with the RPS.  The fuel economy standard leads to lower petroleum use and a reduction in the emissions associated with it.  For example, 2030 transportation sector CO2 emissions are 3 percent lower when only the provisions of S. 1766 are included, but they are 6 percent lower in the S. 1766 High Technology Plus Policies case.

The impact on coal use depends on the success of new coal plants with CCS.  Projected coal use is lower in all of the policy cases examined, relative to the Reference and High Technology case baselines.  In the Reference and High Technology cases without S. 1766, a large number of new coal plants without CCS are expected to be added to meet the growing demand for electricity while new coal-to-liquids plants are added to supply the transportation sector.  However, S. 1766 makes it economically unattractive to continue to add these types of plants and a combination of new coal with CCS, nuclear, and renewable plants is generally added to supply electricity, and no new coal-to-liquids plants are added.  When the availability of new coal with CCS, nuclear, and renewable generating technologies is limited, new natural-gas–fired combined-cycle plants are added instead of the coal plants without CCS.

If new coal plants with CCS can be successfully deployed rapidly enough to replace most of the generation expected from existing and projected new coal plants without CCS, total coal consumption would be expected to grow rapidly through 2030.  In the Reference case, total coal use, on a Btu basis, is projected to increase 49 percent between 2005 and 2030.  When the provisions of S. 1766, including the offset credits and full bonus allowances for CCS, are imposed, total coal consumption increases 37 percent between 2005 and 2030.  However, this would require the addition of nearly 300 gigawatts of new coal plants with CCS by 2030, a difficult challenge.

In contrast, when the CCS bonus rate is cut in half or when the advanced technology assumptions are incorporated, the addition of new coal plants with CCS is reduced to between 49 and 128 gigawatts.  As a result, projected coal use remains at approximately current levels (22 to 23 quadrillion Btu) through 2030 in these scenarios (Tables ES2 and ES3).  In the S. 1766 Limited Alternatives case, coal use is projected to grow 16 percent between 2005 and 2030, compared to 49 percent in the Reference case.

The energy price impacts of S. 1766 are tempered by the TAP provision.  The cost of using energy is increased by the requirement to submit allowances or pay the TAP price.  Under S. 1766, most coal consumers and suppliers of natural gas and petroleum products must submit allowances, and the allowance costs will be reflected in their product prices.  Relative to the Reference case, projected energy prices for petroleum, natural gas, coal, and electricity all increase, with the effect growing from 2010 through 2030 as the TAP increases (Tables ES-2 and ES-3).  Across the primary cases examined (excluding the Limited Alternatives case), the increases in average delivered prices projected for 2030 range from 12 to 13 percent for natural gas, 7 to 10 percent for petroleum, 132 to 149 percent for coal, and 8 to 10 percent for electricity.³ 

The key uncertainties involve the potential for and the timing of the development, commercialization, and deployment of low-carbon electricity generating technologies.  This analysis finds that energy providers, particularly electricity producers, will increasingly turn to technologies that play a relatively small role today or have not been built in the United States in many years, including coal with CCS, nuclear power, and renewable energy.  However, new coal plants with CCS have not yet been commercially deployed and concerns about costs, feasibility, availability of reservoirs and pipelines, and other project risks could deter development.  Similar concerns apply to nuclear power, as well as concerns about siting and waste disposal.  Furthermore, the use of biomass for electric power could be affected if a biofuel mandate for transportation fuels larger than what currently exists were enacted. 

The TAP provision in S. 1766 also limits the economic and energy price risks associated with technology development and deployment uncertainties. If carbon-free and low-carbon electricity technologies other than natural-gas-fired plants are not available for widespread deployment in a timeframe consistent with the provisions of S. 1766, use of the TAP would increase, and the level of emissions would rise above the level attained in the S.1766 cases where these technologies are available, tempering the economic consequences and energy price impacts that would otherwise occur under these circumstances.  This is illustrated by the Limited Alternatives case, which holds deployment of nuclear and biomass generation and the availability of LNG to the Reference case level and further assumes that CCS is not available until after 2030.  In this case, the electric power industry opts to rely more heavily on the TAP compliance option rather than reducing emissions.  It also relies more heavily on natural gas, which leads to larger electricity price and economic impacts.  For example, 2030 electricity sector CO2 emissions in the Limited Alternatives case are roughly double the level seen in the S. 1766 Core case (Table ES-4).  Electricity prices in 2030 in the Limited Alternatives case are 20 percent higher than in the Reference case, again, approximately double the impact seen in the S. 1766 Core case. 

S.1766 increases the cost of using energy, which reduces real economic output, reduces purchasing power, and lowers aggregate demand for goods and services. The result is that projected real Gross Domestic Product (GDP) generally falls relative to the reference case.  The overall economic impacts as measured by changes in gross domestic product (GDP) and aggregate personal consumption are also tempered by the TAP provision.  For example, total discounted GDP losses over the 2009 to 2030 time period range from $52 billion (-0.02 percent) to $163 billion (-0.07 percent) in the main S. 1766 cases.  Similarly, the cumulative losses for personal consumption range from $157 billion (-0.09 percent) to $287 billion (-0.17 percent), in the same cases.  The impacts are larger in the S. 1766 Limited Alternatives case, with cumulative GDP loses of $330 billion (-0.13 percent) and consumption loses of $344 billion (0.21 percent).  The TAP provision plays an important role in mitigating the effects of the Limited Alternatives case assumptions on projected economic impacts.

Auction revenues and TAP payments are projected to provide a significant revenue flow to the Federal government. Government revenue from allowance auction revenues and TAP payments range from $37 to $55 billion in 2020 and from $81 to $120 billion in 2030, across the four main policy cases considered in this analysis. The Limited Alternatives case provides somewhat higher revenues to the Federal government, projected at $59 billion in 2020 and $145 billion in 2030, reflecting additional use of the TAP mechanism.

Executive Summary-Tables

Notes