1. Background and Scope of the Analysis

Background

This report responds to a request from Senators Lieberman and Warner for an analysis of S. 2191, America’s Climate Security Act of 2007 and a subsequent analysis request from Senators Barasso, Inhofe, and Voinovich.¹  S. 2191 is a complex bill regulating emissions of greenhouse gases (GHG) through market-based mechanisms, energy efficiency programs, and economic incentives.  A detailed summary of the bill, obtained from Senator Lieberman’s web site, is included in Appendix C.

Title I of S. 2191 establishes a cap on annual emissions of greenhouse gases beginning in 2012, covering energy-related carbon dioxide (CO2), methane, nitrous oxide, perfluorocarbons, sulfur hexafluoride, and hydrofluorocarbons (HFCs) emitted from production of hydroclorofluorocarbons (HCFCs).  Regulated entities who must submit emission allowances include coal consumers using over 5,000 tons per year, suppliers of oil and natural gas, and producers and importers of covered fluorinated gases.  Sources that are exempt from the Title I cap, but which have other emission reduction incentives under the bill, include most non-CO2 agricultural emission sources, emissions from coal mines and landfills, and the other HFCs.  The emissions covered under Title I represented approximately 87 percent of total GHG emissions in 2006 as reported by the Energy Information Administration (EIA) in its inventory.² 

The Title I caps decline gradually from 5,775 million metric tons (mmt) CO2-equivalent in 2012 (7 percent below 2006 emission levels), to 3,860 mmt in 2030 (39 percent below 2006 levels), and 1,732 mmt in 2050 (72 percent below 2006 levels).  Titles II, III, and IV specify how the caps would be administered and provide details on allowance distribution and the use of auction proceeds to ameliorate impacts and promote emission reductions.  The bill specifies that an increasing share of the allowances would be auctioned, while the remainder would be distributed for transition assistance to covered entities, energy consumers, and manufacturers, as incentives for CO2 sequestration, to States for exceeding Federal targets, and to fund forest protection and research.  Auction proceeds would be used to fund low-carbon energy technology programs.

This report does not address the possible impacts of Titles VI through XI.  Title VI calls for international policies to encourage emissions reductions, Title VII requires program reviews and studies, Title VIII calls for assessment of geological carbon sequestration issues, and Title IX deals with “miscellaneous issues.” 

Title X separately caps the consumption of other HFCs beginning in 2010, chemicals that serve primarily as substitutes for ozone-depleting substances (ODS).  Emissions of these substances accounted for approximately 2 percent of total GHG emissions in 2006.  While Title X caps consumption of the HFCs, the associated emissions occur gradually from leaks or from scrappage of the products in which the chemicals are used, such as refrigerators and air conditioners.  This analysis does not evaluate feasibility or potential economic impacts of Title X, as this requires special expertise and access to proprietary manufacturer data.  

Finally, Title XI imposes a requirement on the supply of transportation fuels requiring a reduction in so called “life-cycle” GHG emissions relative to a baseline.  In the absence of the details on the specific methodologies underpinning such a regulation, EIA did not attempt to model this provision.

Also not addressed are the provisions of Section 3902 that call for the allocation of allowances to new fossil generators as a function of their generation.  It is unclear whether this provision applies to all new fossil-fired generators, including those with CCS, or just to those facilities without CCS.  If it only applied to new fossil plants without CCS it could significantly impact power sector compliance decisions.  The provisions call for allocating new fossil generators allowances at a rate equal to the average rate of all new generators added over the five years preceding the passage of the bill.  These allowances come from the pool of allowances set aside for new generators which starts at 19 percent of allowances in 2012, but falls to 1 percent of allowances by 2030.  Since the vast majority of these new generators were natural gas facilities, new natural gas facilities without CCS would receive enough allowances to cover all of their emissions while new coal plants without CCS would receive about half of the allowances they would need until the pool of allowances set aside for electricity generators was exhausted.  Such a performance-based allocation of allowances to new fossil generators would alter the investment decisions of power plant builders, encouraging them to continue to rely on new GHG-emitting fossil generators and raising the overall costs of compliance with the GHG cap-and-trade program.  While full simulations of the potential impacts of this provision were not prepared, partial tests suggest that new fossil generators would capture a large share of the allowances set aside for electricity generators, natural gas generation would be higher, allowance prices would be higher, electricity prices would be slightly lower in the near term, but higher in the longer term.

Methodology

The analysis of energy sector and energy-related economic impacts of the various GHG emission reduction proposals in this report is based on results from EIA’s National Energy Modeling System (NEMS), used for projections in the Annual Energy Outlook 2008 (AEO2008).³  NEMS projects emissions of energy-related CO2 emissions resulting from the combustion of fossil fuels, representing about 84 percent of total U.S. GHG emissions today. 

The EIA Reference Case is designed to reflect only current laws and policies.  Because analysis of alternative policies at the request of the U.S. Congress and/or the Administration is a core part of the EIA mission and because EIA does not take a position or speculate on potential policy changes, such changes are not included in the Reference Case.  If assumptions about “expected” policy changes such as future fuel economy standards, taxes, caps on GHG emissions, or new regulatory requirements for conventional pollutants, were included in the Reference Case, it could not be used as a baseline in assessing the impacts of alternative policy proposals in these areas.  For this reason, EIA Reference Case projections are not directly comparable with private energy forecasts that include estimates of policy change in their scenarios.  

Although forecasting policy change is beyond EIA’s mandate, a reasonable argument can be made that, all else being equal, public and industry awareness of a major policy issue alone can potentially impact energy investment decisions.  For example, the possibility of future action to control GHG emissions during the expected operating lifetime of new power generation facilities could favor investment in no- and low-GHG-emission technologies relative to high-GHG-emission alternatives, even if no specific policy change actually occurred.  Such an effect might be incorporated in models by penalizing technologies that are perceived to be risky due to policy concerns.  However, applying such adjustments on an ad hoc basis is difficult, since the extent of any future disadvantage borne by new high-GHG emission generators that begin construction prior to the enactment of a new policy will depend heavily on the details of the policy design and implementation.  

NEMS endogenously calculates changes in energy-related CO2 emissions in the analysis cases. The cost of using each fossil fuel includes the costs associated with the GHG allowances needed to cover the emissions produced when they are used.  These adjustments influence energy demand and energy-related CO2 emissions.  The GHG allowance price also determines the reductions in projected baseline emissions of other GHGs based on assumed abatement cost relationships.  With emission allowance banking, NEMS solves for the time path of permit prices such that cumulative emissions match the cumulative emissions target without requiring allowance borrowing and with price escalation consistent with the average cost of capital to the electric power sector.  Assumptions for allowance banking are discussed in a following section.

The NEMS Macroeconomic Activity Module (MAM), which is based on the Global Insight U.S. Model, interacts with the energy supply, demand, and conversion modules of NEMS to solve for an energy-economy equilibrium.  In an iterative process within NEMS, MAM reacts to changes in energy prices, energy consumption, and allowance revenues, solving for the effect on macroeconomic and industry level variables such as real gross domestic product (GDP), the unemployment rate, inflation, and real industrial output. 

Under S. 2191, the allowance obligations are imposed on an “upstream” basis for natural gas and petroleum and on a downstream basis on coal consumers.  This regulatory approach has implications for how allowance costs are reflected in the modeling of delivered energy prices:

• The allowance requirement for coal-related CO2 emissions is an incremental opportunity cost of using coal.  For modeling purposes, we have added the allowance cost to the delivered price of coal to reflect the opportunity cost faced by coal consumers.  For oil and natural gas pricing, we assume that the allowance costs associated with the related CO2 emissions are passed through in the delivered prices, with some exceptions noted below.
• Under Sec. 1204, allowances will be required for all GHG emissions from natural gas, including fugitive methane emissions associated with natural gas production and processing.  Therefore, an adjustment to the delivered cost of fuel was made in NEMS to account for the allowance cost of these natural-gas-related methane emissions, in addition to the adjustment for CO2 emissions from natural gas combustion.

• Methane and nitrous oxide emissions associated with stationary and mobile fuel combustion would be subject to the allowance requirement.  However, the cost of these allowances is not reflected in the allowance cost adjustments in delivered fuel prices, as these emissions are not disaggregated in the model by fuel source.
• CO2 emissions from refineries’ direct fuel combustion of petroleum-based fuels would be subject to the allowance requirement.  However, the incremental cost of these allowances is not explicitly reflected in delivered petroleum prices, as the Petroleum Market Module of NEMS is not structured to represent such costs explicitly.

• The Title III credit would be available to any CCS project, including natural gas CCS.  For this analysis, it was assumed that the natural gas and coal would be eligible for both the Sec. 1202 CCS credit and the Title III bonus allowances.

Non-CO2 Emission Coverage and Abatement Assumptions

To represent nonenergy-related GHG emissions abatement and increases in biogenic carbon sequestration, EIA applied the same methodologies and data sources described in its evaluation of S. 280, the Climate Stewardship and Innovation Act of 2007.⁴  However, the number of source classifications was disaggregated to better match regulatory coverage provisions under S. 2191.  The level of detail in these baselines and any corresponding abatement supply assumptions are specified by the categories presented in Table 1.  Table 1 also indicates whether the source was considered as covered or uncovered under the S. 2191 Title I cap, with a comparison to the corresponding assumptions under S. 1766, the Low Carbon Economy Act of 2007.

The economic abatement potential assumed for the domestic non-CO2 gases is relatively small compared to the potential for domestic biosequestration and international sources (Figure 1).   The cost and availability of international sources is highly uncertain and depends on widespread adoption of limits on GHGs and the establishment of global international allowance trading.  S. 2191 limits the use of international allowances to those from countries with mandatory, absolute caps on GHG emissions of comparable degrees of stringency and enforcement.  Countries without comparable allowance programs could, however, potentially supply offsets to the international market and free up qualifying allowances for sale to the United States.  Therefore, no change in assumed cost and availability of international allowances was made to represent the strict comparability provisions for international offsets under S. 2191.   However, the issue of availability of international offsets is addressed in a sensitivity case that excludes them.

Furthermore, the possibility that the United States could be a net supplier of allowances or offsets internationally was not considered.  With international trading in allowances, the S. 2191 allowances could be sold abroad, ultimately raising the domestic allowance price to international levels. 

Under S. 2191, certified increases in biosequestration can be used as either offsets or qualify under the Sec. 3701 incentive program, but not both.  Under Sec. 3701, up to 5 percent of allowances are available as incentives for increases in biosequestration or reductions in agricultural GHG emissions.  This analysis assumes that the Sec. 3701 allowance incentives are exchanged for increases in biogenic sequestration.  In addition, the supply of biosequestration available at a given allowance price is assumed to be used first for the Sec. 3701 program based on the allowance price.  Any excess supply that would exceed the 5-percent limit under Sec. 3701 limit is assumed to be sold on the offset market.

Allowance Banking and Borrowing

To reflect banking incentives and trading arbitrage, allowance prices escalate at a rate no higher than 7.4 percent per year in real terms during intervals when allowance balances are held.  This rate reflects the average cost of capital in the electric power sector, where a significant share of emissions reduction investments is expected to occur.  S. 2191 permits up to 15 percent of the allowance obligation to be borrowed from future allowance supplies, subject to a 10-percent allowance increase per year borrowed.⁵  The 10-percent real rate of interest would presumably preclude such borrowing, except in situations involving shocks or surprises that are not considered in this analysis.  As a result, allowances prices are estimated such that borrowing does not occur. 

S. 2191 calls for increasingly stringent emissions caps beyond 2030, the forecast horizon for NEMS.  Meeting these post-2030 caps will require significant emission reductions outside the electricity sector, the predominant source of early emissions reductions and increasing price pressure, absent significant technological breakthrough in transportation and other uses dependent on fossil fuels.  As a result, we assume there will be an allowance bank balance at the end of 2030.  To roughly estimate the magnitude of the 2030 allowance balance, trial simulations that accelerated the emissions targets for various post-2030 dates to 2030 were made to observe the variation in banking levels in the period before 2030.  Based on these trial runs, the bank balance assumption for 2030 was set at 5 billion metric tons.  This level of allowance banking is consistent with the greater difficulty complying with the post-2030 targets under continued growth in population and the economy, yet balanced by the technological progress likely to help mitigate the economic cost of abatement.  While the level of banking would also depend on other economic assumptions, such as the availability and cost of international offsets, the 5-billion-ton-balance assumption was applied in all the cases analyzed.

Appliance Efficiency and Building Codes

Section 3302 of the S. 2191 allocates a portion of the allowances distributed to States to promote energy efficiency and mitigate the impact on low-income consumers.  To reflect the impact of these programs, the incremental cost of the most energy-efficient appliances in each residential end-use category was reduced by half.  In most cases, the relevant technologies represented the two most efficient options in each class.  For example, if the cost difference between the least and most efficient air conditioners was $1000, the cost differential was reduced to $500, in effect simulating a rebate for buying the more efficient appliance.

Section 5201 provides incentives for meeting and strengthening building codes.  To represent these incentives, the residential building codes were tightened by 30 percent in 2015 and 50 percent in 2025, relative to the building codes assumed in the Reference Case.

Allowances to Load-Serving Entities and Fossil-Fired Powerplant Owners

Under Section 3401, 9 percent of allowances are distributed to electric load-serving entities (LSE) where the proceeds can be used to reduce the cost impact of the program or promote energy efficiency programs.  Under Section 3901, 1 percent of allowances are allocated to rural electric cooperatives for transition assistance.  In this analysis it was assumed that all of the allowance proceeds from this 10-percent allocation are used to reduce electricity prices by lowering the distribution markups.

Under Section 3901, a share of allowances are allocated to fossil-fuel-fired electric powerplant owners, beginning with 19 percent from 2012 to 2017, then declining gradually each year to 1 percent in 2030.  It was assumed that the impact of this free allocation depends on how the powerplants are regulated within each region.  For unregulated producers, the benefits of the free allocation of allowances are not passed on to consumers.  However, for regulated providers, where electricity prices are set under cost of service procedures, the cost benefits of the free allowances are assumed to be passed on to electricity consumers. 

Analysis Cases

There is significant uncertainty regarding the potential impacts of S. 2191.  A set of five cases simulating the S.2191 policy were prepared, varying assumptions regarding the cost and availability of various technologies and compliance offset options (Table 2).  While the cases do not span the full range of possibilities, they provide some indication of the impact of the more important analytical assumptions:

• The S. 2191 Core Case represents an environment where key low-emissions technologies, including nuclear, fossil with carbon capture and sequestration (CCS), and various renewables, are developed and deployed in a timeframe consistent with the emissions reduction requirements without encountering any major obstacles, even with rapidly growing use on a very large scale, and the use of offsets, both domestic and international, is not significantly limited by cost or regulation. 
• The S. 2191 No International Offsets Case, is similar to the S. 2191 Core Case, but represents an environment where the use of international offsets is severely limited by cost or regulation.  The regulations that will govern the use of offsets have yet to be developed and their availability will depend on actions taken in the United States and around the world.
• The S. 2191 High Cost Case is also similar to the S.2191 Core Case except that the costs of nuclear, coal with CCS, and biomass generating technologies are assumed to be 50 percent higher than in the Core Case.  There is great uncertainty about the costs of these technologies, as well as the feasibility of introducing them rapidly on a large scale.  While the costs assumed in the High Cost Case are more closely aligned with recent cost estimates than those in the Core Case, it is unclear if the recent cost increases are a short- or long-run phenomenon.   The High Cost Case, which raises the cost of key low- and no carbon electric generation technologies, falls between the Core Case and the Limited Alternative Case discussed below.
• The S. 2191 Limited Alternatives Case represents an environment where the deployment of key technologies, including nuclear, fossil with CCS, and various renewables, is held to their Reference Case level through 2030, as are imports of liquefied natural gas (LNG).  The inability to increase their use of these technologies causes covered entities to turn to other options in response to S.2191. 
• The S. 2191 Limited/No International Case combines the assumptions from the S. 2191 Limited Alternatives and S. 2191 No International Offset Cases.

Notes