2. Assumptions, Methodology, and Scenarios

This analysis of S.139 is based on comparisons with an updated version of the Annual Energy Outlook 2003 (AEO2003) reference case. The AEO2003 reference case was updated to reflect changes in electric generating capacity since the AEO2003 forecast was completed (October 2002), to incorporate revised expectations about near-term trends in natural gas prices, and to reflect recent changes in corporate average fuel economy (CAFE) standards. Senators McCain and Lieberman explicitly requested that EIA update the projections for additions of new electricity generating capacity (see Appendix A).

S.139 proposes a detailed program for greenhouse gas emissions monitoring and control and contains provisions that are either subject to varying interpretation or are intended to be defined after enactment. This chapter outlines some of the key assumptions and methodology required to analyze S.139 and defines the various cases analyzed.

The National Energy Modeling System

The AEO2003 projections are generated using EIA’s National Energy Modeling System (NEMS). NEMS is a computer-based, energy-economy modeling system of U.S. energy markets for the mid-term period through 2025. Using a market-based approach to energy analysis, NEMS projects the production, imports, conversion, consumption, and prices of energy, subject to assumptions on macroeconomic and financial factors, world energy markets, resource availability and costs, behavioral and technological choice criteria, cost and performance characteristics of energy technologies, and demographics. For each fuel and consuming sector, NEMS balances energy supply and demand, accounting for economic competition among the various energy fuels and sources. In order to represent the regional differences in energy markets, NEMS functions at the regional level. In addition to its use for this analysis and for production of the Annual Energy Outlook, NEMS is also used in analytical studies requested by the U.S. Congress, other Federal Government agencies, and other offices within the Department of Energy. (See The National Energy Modeling System: An Overview 2003⁴⁷ for further details.)

NEMS calculates carbon dioxide emissions, the principal component of greenhouse gases, as the product of fossil energy use and fuel-specific emissions factors. While emissions of the greenhouse gases other than energy-related carbon dioxide are related to energy activities, estimating those emissions based on economic factors is outside the scope of NEMS. As a result, baseline emissions of gases other than energy-related carbon dioxide were obtained from the U.S. Environmental Protection Agency (EPA), as were estimates of the potential for reducing the emissions, reflected in cost functions known as marginal abatement curves (MACs).

Under S.139, emissions allowances must be submitted by covered entities for their greenhouse gas emissions. Covered entities obtain the allowances through the allocations from the Government or by purchasing allowances from other entities or the Climate Change Credit Corporation (hereafter referred to as the Corporation). The cost of the allowance increases the cost of using energy in the covered sectors, effectively increasing the price of fossil fuels to covered entities, as well as the cost of electricity to all sectors. As the allowance price changes and influences energy costs, the estimated demand for energy changes, as do the corresponding carbon dioxide emissions. For greenhouse gases other than carbon dioxide, emissions reductions in covered sectors are calculated based on the MACs. The emissions abatement at the current market price for allowances is subtracted from the baseline emissions to obtain the resulting emissions for the covered sources.

An emissions accounting structure was used to track allowance banking and the use of allowance offsets to comply with S.139, as well as to perform the marginal abatement calculations for other greenhouse gases. A methodology was also incorporated to estimate allowance and offset prices, given the banking provisions of S.139 and offset limitations. Documentation of these methodology changes, including the derivation and sources for marginal abatement curves, is provided in Appendix B.

As part of analyzing S.139, NEMS was updated to reflect changes in electric generating capacity since AEO2003 was completed, to adopt recent changes in the CAFE standards, and to incorporate revised expectations about near-term natural gas price trends. The following summarizes these key updates.

Electricity Generating Capacity Updates

Within NEMS, only planned units that are reported as “under construction” are automatically included as being built during the forecast horizon. NEMS then forecasts the construction of additional unplanned capacity by type as needed to meet future demand.

For AEO2003, the information on planned generating units was based predominantly on 2001 data from industry filings on Form EIA-860, “Annual Electric Generator Report,” which provides information from both utility and nonutility generators. The EIA-860 data were supplemented by a second data source, the NewGen database developed by Platts Database,⁴⁸ which is updated on a monthly basis. The NewGen database was used to update the EIA-860 information for more recent changes in plant operating status.

Based on new information available as of the end of March 2003, planned electric generating capacity included in the revised reference case used to analyze S.139 was updated from what was included in AEO2003. Additional units are represented as planned capacity in the S.139 reference case if they are reported as under construction in the NewGen database and as planned in the EIA inventory.

About 24 gigawatts of additional planned capacity was reported as being under construction as of March 2003, including 8.5 gigawatts in 2002, 14.3 gigawatts in 2003, and 1.2 gigawatts in 2004. About 16 gigawatts of the additions are gas-fired combined cycle, 4.6 gigawatts are gas-fired turbines, and 2 gigawatts are dual-fired combined-cycle units. The remaining 1.4 gigawatts consist of dual-fired turbines and internal combustion units, several renewable units, and a relatively small coal-fired unit.

Appendix B provides detailed information on the capacity changes made in the S.139 reference case by region relative to AEO2003.

CAFE Standards Update

On April 1, 2003, the National Highway Traffic Safety Administration announced an increase in the Corporate Average Fuel Economy (CAFE) standard from 20.7 miles per gallon (mpg) for light trucks to 21.0 mpg in 2005, 21.6 mpg in 2006, and 22.2 mpg for 2007 and beyond. These updates were included in NEMS for this analysis.

Near-Term Natural Gas Prices

Each month in the Short-Term Energy Outlook (STEO), EIA publishes 2-year projections of price, demand and supply, and stocks for each of the main energy sources. These projections are revised in response to observed changes in weather conditions, stock levels, and market conditions. For AEO2003, the September 2002 STEO was the basis of the short-term outlook. Since then, the natural gas price forecasts have changed significantly. For example, in the April 2003 STEO, the average natural gas wellhead price for 2003 was projected to be $4.52 (nominal dollars) per thousand cubic feet, 39 percent higher than the projection for 2003 used in AEO2003. To incorporate the more recent views of the market, the natural gas supply and price forecasts for this study were aligned with the April 2003 STEO forecasts. In particular, adjustments were made to natural gas production, imports, supplemental supplies, storage, consumption of lease, plant, and pipeline fuel, and prices at the wellhead and the burner-tip. These adjustments mainly affect the short-term projections; however, because decisions made in later years depend in part on earlier market conditions, the longer term projections are also affected.

Representing S.139

Definition of a Covered Entity

The proposed legislation explicitly defines a “covered sector” as including the electricity generation, transportation, industrial, and commercial sectors. It requires that “covered entities” in these sectors participate in the tradable allowance system and defines a covered entity as a person, company, organization, or agency (including a branch, department, agency, or instrumentality of Federal, State, or local government) that owns or controls facilities that collectively emit more than 10,000 metric tons (carbon dioxide equivalent) of greenhouse gases per year. Because nearly every electricity generating plant using fossil fuels would meet the emissions threshold, 100 percent of the electric sector is assumed to be covered for this analysis. Because no individual transportation vehicle and only the largest of fleets are likely to meet the emissions threshold, the bill covers transportation fuel use through refiners. Refiners and importers of petroleum products that provide fuel to the transportation sector and meet the 10,000 metric tons emissions threshold are covered entities and must obtain and provide allowances sufficient to cover those sales. Based on size limitations, difficulty in measurement, and the intent of the legislation’s authors,⁴⁹ the agricultural sector is not considered to be covered. As discussed below, coverage in the commercial sector and in other portions of the industrial sector is difficult to determine because of insufficient data.

The EIA commercial buildings survey data indicates that less than 0.01 percent of commercial buildings used enough fuel in 1999 to meet the emissions threshold.⁵⁰ While an entity owning or controlling several commercial buildings may exceed the threshold, there are no data sources that provide energy consumption or emissions at the entity level to make that determination. Given that the vast majority of buildings in the commercial sector would not meet the emissions threshold, it is assumed for this analysis that the commercial sector is not covered by the bill. A sensitivity case that treats the entire commercial sector as a covered entity is included to provide an understanding of the impact of treating this sector as covered.

Similar data problems exist for the industrial sector, because there are no data on energy consumption or emissions at the entity level. However, it has been estimated that approximately 7,000 manufacturing facilities would exceed the 10,000 metric ton threshold, accounting for 84 percent of manufacturing sector emissions in 1998.⁵¹ Nearly all facilities in the most energy-intensive manufacturing sectors would exceed the threshold and be covered by S.139. The number of additional facilities required to report due to common ownership or control within each manufacturing sector is not currently known. For example, General Mills owned 95 food-related plants in the United States during 2002.⁵² If any one of those plants, or any combination of plants, exceeded the emissions threshold, all the plants would be covered. Furthermore, conglomerates with holdings across several manufacturing sectors may also exceed the threshold. While it is difficult to estimate the overall industrial sector coverage which would result when these common ownership or control issues are resolved, the proportion of the industrial sector meeting the threshold is likely to be higher than the 84 percent coverage estimate. Therefore, this analysis assumes that the entire industrial sector is covered, with the exception of the agriculture industry.

It is also important to note that the person, company, organization, or agency that must hold a greenhouse gas emission allowance will vary by the covered sector. For example, electricity generators must obtain and provide allowances for their greenhouse gas emissions. A refiner must obtain and provide allowances for petroleum products sold for transportation applications and for the fuel used to refine crude oil to products. However, the refiner does not need to obtain allowances for petroleum products sold to the residential, commercial, or industrial sectors. Covered entities in the commercial and industrial sectors are required to obtain and provide allowances for greenhouse gas emissions resulting from their own energy use. While residential energy users are exempt, they will face higher energy, service, and product prices due to the cost of allowances purchased by electricity generators and industrial energy users, and any increase in prices that may result from the cost of fuel switching or investment in compliance options.

Phase I and II Allowance Caps

S.139 specifies the Phase I and Phase II emission allowance caps based on 2000 and 1990 data, excluding emissions from the residential sector, agriculture sector, and U.S. territories. The reference data cited in the bill are from the EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000.⁵³ The bill specifies the annual allowances for Phase I and Phase II at 5,896 and 5,123 million metric tons carbon dioxide equivalent, respectively, adding the phrase “reduced by the amount of emissions of greenhouse gases . . . from noncovered entities.” Noncovered entities include those not meeting the emissions threshold of 10,000 tons carbon dioxide equivalent, as well as emissions from sources deemed impractical by the EPA to measure. To derive the caps for modeling purposes, several sources of data other than the EPA inventory were used.

To determine the energy-related CO2 portion of the cap, the data sources and accounting conventions for CO2 emissions in EIA’s Emissions of Greenhouse Gases report⁵⁴ were used. EIA sources on carbon dioxide were used because of their consistency in relating energy use by sector as modeled in NEMS to the corresponding historical data on energy use and carbon dioxide emissions. There are several areas of difference between EIA’s emissions accounting and those in the EPA inventory. One is that the EIA energy-related emissions include emissions for military and international bunker fuels. These emissions sources are not separately broken out in NEMS and thus are included as though they were covered under S.139.⁵⁵ A second is that EIA recently revised its energy data accounting for fossil fuels used to generate electricity. A third is that EIA accounts for carbon dioxide emissions from metallurgical coal and coke as part of energy-related CO2 emissions. A comparison of the EIA and EPA energy related CO2 emissions is shown in Table 2.1.

For emissions other than energy-related CO2, the EPA’s Business-As-Usual (BAU) baseline emissions projections were used, along with EPA’s corresponding estimated marginal abatement curves. To use EPA’s projection and abatement curves in a consistent framework, the 1990 and 2000 data accompanying the projections were used to derive the cap. Some of the data (non-energy carbon dioxide, nitrous oxide, and high GWP gases) differs from the more recent data in EPA’s 2002 inventory, due primarily to new accounting conventions in the EPA inventory. The most significant of the accounting changes concerns non-energy carbon dioxide, a category that is assumed not to be covered for the purposes of this report. A comparison of the emissions data available with the baseline projections with the corresponding data in the EPA Inventory is shown in Table 2.2.

To derive the cap, assumptions about what portion of the gases would be covered were made. Non-covered entities include those not meeting the emissions threshold of 10,000 tons carbon dioxide equivalent. In addition, emissions from sources deemed by EPA to be impractical to measure would be considered noncovered. For this analysis, the following assumptions were made about the coverage of several emissions sources, constrained by the level of aggregation of exogenous projections of greenhouse gases other than carbon dioxide (CO2).

• Nitrous Oxide: Emissions from agriculture and mobile sources, accounting for about 87 percent of the nitrous oxide emissions, are assumed to be exempt from coverage based on the measurement and size threshold provisions. An “Other” category of nitrous oxide emissions, which includes emissions from adipic and nitric acid production, is included in covered emissions. While about 25 percent of the Other category includes potentially noncovered sources—stationary sources, human sewage, and waste combustion—the availability of projections for the category as a whole precluded a finer breakout for this analysis.

• Methane: Most methane emissions are assumed to be exempt based on the measurement and size provisions. The sources assumed to be noncovered are natural gas systems, landfills, and an “Other” category that includes agriculture, mobile, and stationary sources. Emissions from coal mining, treated in aggregate, are assumed to be covered. The ventilation and degasificaton sources would be expected to be measurable and, for the most part, controlled by entities above the size threshold. It is possible that a small share of the coal-related methane emissions, including emissions from surface mining and post-mining, might be excluded based on the measurement provision. For analysis purposes, the entire category is considered a covered source.

• Non-energy CO2: This category is assumed to be noncovered based on the measurement and size threshold provisions. While some of the emissions is this category, such as those relating to cement manufacture, would probably be covered, a breakout of the projections for this category was unavailable. Since most of the emissions would probably be exempt, the entire category was treated as uncovered for analysis purposes. Note that EIA did not account for some of the new categories of emissions that EPA now accounts for as non-energy CO2 in this category. The largest of these is carbon dioxide from the use of metallurgical coal, which EIA accounts for in the industrial sector as a covered source.

• High Global Warming Potential (GWP) Gases: S.139 specifies that producers and importers of these gases will be required to provide allowances based on the amounts of the gases supplied. However, the emissions data are based on emissions of gases rather than production. For modeling purposes, the emissions, rather than production, of the gases are included in the allowance cap for covered entities.⁵⁶

The allowance caps are derived by summing the CO2 emissions from the affected energy sectors, the covered portions of methane and nitrous oxide emissions, and emissions of the high-GWP gases. Using these definitions, the Phase I and Phase II caps for covered entities are estimated at 5,372 and 4,613 millions metric tons carbon dioxide equivalent. Except where otherwise noted, this report follows EIA’s standard practice of reporting emissions of carbon dioxide and other greenhouse gases in carbon equivalent (rather than carbon dioxide equivalent) units, defined as the weight of the carbon content of carbon dioxide (i.e., just the “C” in CO2). Emissions in carbon equivalent terms are converted to carbon dioxide equivalent terms by multiplying by 3.6667.⁵⁷ Thus, the Phase I and Phase II caps used in this report are 1,465 and 1,258 million metric tons carbon equivalent.

Table 2.3 summarizes the Phase I and Phase II caps as modeled in this analysis. As indicated above, emissions of most methane, nitrous oxide, and non-energy CO2 are assumed to be exempt based on the bill’s exemptions for entity size and measurement feasibility. The exceptions are for methane released in coal mining and nitrous oxide emitted in the production of adipic and nitric acid.

The bill allows each covered entity to obtain a portion of its emission allowances from alternate compliance sources, including purchase of allowances from certified reduction or sequestration programs, both domestically and abroad. These offset limits are 15 percent from 2010 to 2015 (Phase I) and 10 percent thereafter (Phase II). As an incentive for early action, entities reducing their emissions below 1990 levels may be granted a limit of 20 percent of their target reductions from alternate compliance sources in Phase I. To account for those covered entities that would take advantage of this incentive, an offset limit of 16 percent in Phase II was assumed.⁵⁸ Based on these assumptions, the offset limit in Phase I was 234 million metric tons carbon equivalent, and the limit in Phase II was 126 million metric tons.

This analysis also assumes that the greenhouse allowance caps and allowance prices remain at the 2025 levels after 2025. Since capacity expansion decisions in the generating sector are based on capital and non-fuel operating costs and expectations about future fuel and allowance prices over the next 20 years, expected fuel and allowance prices after 2025 are important in influencing power generation capacity additions.

Representation of Non-CO2 Greenhouse Gases

NEMS is used to simulate proposed limits on energy-related CO2 emissions based on either a cap and trade allowance policy for CO2 emissions or a CO2 fee added to the price of fossil fuels. Since S.139 also includes non-CO2 greenhouse gases, and since NEMS does not include economic or behavioral models to estimate potential capture of other greenhouse gases, the international and domestic offsets that would be available to the U.S. market were estimated through an external analysis and used for this study.⁵⁹

An emissions accounting structure was developed to distinguish emissions from covered and noncovered entities. In addition, an exogenous set of curves was developed to reflect the potential for reductions in other greenhouse gases as a function of allowance prices. These cost functions are known as marginal abatement curves (MACs). Along with the associated baseline projections of emissions, the MACs were obtained from the EPA’s Office of Air and Radiation. EPA provided EIA with MACs as developed in several recent studies.^60,61,62 At EIA’s request, EPA also extended its BAU projections and MACs to 2025, the forecast horizon for this study.

The EPA BAU projections and MACs were used in this analysis because they are the only consistent and relatively complete source for such emission estimates.⁶³ EIA made two adjustments to the MACs: the first adjusts the MACs so that the reductions that are economical at zero or “negative” allowance prices are instead priced at $1 per ton. The second change was to reduce the quantities of international and domestic sequestration reductions available to the U.S. market for reasons to be discussed later in this Chapter. Assumptions regarding MACs are also presented in detail in Appendix B.

In this analysis, the exogenous MACs are treated as four classes:

• Emissions from non-CO2 greenhouse gases from domestic covered sectors;
• Emissions of non-CO2 greenhouse gases from domestic noncovered sectors;
• Carbon sequestration⁶⁴ (agriculture and forestry), domestic; and
• International greenhouse gases and sequestration.

The emissions and MACs for the non-CO2 greenhouse gases were used to estimate total covered emissions under the bill. Within this category, there is no limit on reductions specified in the bill, and the allowances for these emissions can be considered along with allowances for CO2 emissions as a single market with unlimited trading.

Reductions in a noncovered entity’s emissions, potential carbon sequestration, and international emission reductions are included to reflect the bill’s alternative compliance provisions. Allowance credits may be obtained from these noncovered entities subject to the restrictions outlined in Chapter 1. The allowance credits from noncovered entities are commonly referred to as offsets. Offsets are capped at 15 percent and 10 percent limits of emissions from covered sectors.⁶⁵ The price at which offsets sell is determined by the intersection of the offset supply curve (or MAC) and the offset limit.

The covered non-CO2 greenhouse gases consist of the high GWP gases, coal-related methane emissions, and a portion of nitrous oxide emissions from adipic and nitric acid production. The assumed MACs for non-CO2 emissions in the noncovered sectors include reduction opportunities in natural gas operations and small landfills. The quantity of offsets from other non-CO2 gases is small.

The carbon sequestration MACs are derived from the Forest and Agricultural Sector Optimization Model (FASOM-GHG), in consultation with the EPA.^66,67 The quantities from domestic agricultural offsets that are available for reduction are adjusted downward by 50 percent, consistent with an EPA study requested by Senators Smith, Voinovich, and Brownback.⁶⁸ The pricing and availability of agricultural offsets are deemed to be more uncertain than those for other domestic non-CO2 offsets because of limited information, an inability to measure or verify the data, and administrative costs.⁶⁹

International Offset Curves

Although NEMS is a detailed energy-economy model of the United States and uses consumer behavior to develop detailed projections of energy consumption, energy prices, macroeconomic activity, and carbon dioxide emissions, it does not include economic or behavioral models to estimate the other greenhouse gases covered in S.139. For this study, the offsets that would be available to the U.S. market were also estimated through an external analysis and used for this study.⁷⁰ (See Appendix B for details.)

S.139 provisions limit the sources and quantities of international offsets that qualify for purchase by U.S. entities. Another country’s allowances may be used as offsets only if the country has a U.S-approved allowance trading program and an enforceable limit on greenhouse gas emissions under which the allowances were issued to implement. To date, only a fraction of the Annex B countries, as defined in the Kyoto Protocol,⁷¹ could qualify as qualified programs. Annex B countries include Annex I⁷² countries plus Lithuania, Slovenia, Croatia, and the Ukraine. This analysis assumes that all international trading will occur through Annex I countries, because they represent approximately 96 percent of all Annex B emissions and because consistent baseline emissions and the associated MACs were only available for Annex I countries. For this analysis, all Annex I countries are assumed to adhere to their Kyoto Protocol targets⁷³ through 2025.⁷⁴The greenhouse gas emission targets of the Kyoto Protocol were used to develop the aggregate baseline and emission targets through 2025 for Annex I countries, excluding the United States (Table 2.4).

For Annex I, the Clean Development Mechanism (CDM) opportunities were assumed to add approximately 130 million metric tons of carbon equivalent. In 2010, sequestration and CDM represent about 50 percent of the required emissions reductions for Annex I. Although there is no good estimate of what proportion CDM will represent for Annex I, recent news from the United Nations (UN) suggest that CDM projects may be difficult to certify.⁷⁵ Reuters reported on June 10, 2003 that of the twelve projects submitted to the UN for certification, all twelve were denied although about half of them will be permitted to reapply. UN spokesperson Christine Zumkeller was quoted as saying:

“We have to answer the question: why would this not have happened anyway? A country with many fast-flowing rivers could, for example, argue it is helping the planet by building hydro-electric plants instead of burning fossil fuels, but regulators say that may not be a legitimate argument if the fossil fuel plant was not a viable alternative in the first place."

The Energy Modeling Forum’s 21 assumptions on the availability of non-CO2 offsets were used to estimate the offset MACs available to Annex I countries excluding the United States. The CO2 MACs and baseline for Annex I were provided by Pacific Northwest National Laboratory and used as a pair to maintain self-consistency.⁷⁶ Annex I minus the U.S. MAC was derived (Table 2.5) and used to identify the portion of the offsets that might be made available for U.S. purchase.

The uncertainty regarding the availability of international offsets is assumed to be equivalent to the uncertainty for domestic offsets from sequestration. Therefore, the offsets available from participating Annex I countries were reduced by 50 percent. That is, the portion of the reductions remaining after Annex I requirements were met was reduced by 50 percent⁷⁷ (Table 2.6). The derivation of the international curves is provided in Appendix B. Table 2.6 implies that the Annex I allowance price would be between $20 and $30 per metric ton carbon equivalent in 2010,⁷⁸ between $40 and $50 in 2015, and between $50 and $75 in 2020 and 2025.

Allocating Emissions Allowances

In order to assess the macroeconomic impacts of S.139, an assumption is needed regarding how emission allowances would be allocated among covered sectors and the Corporation. To assess the sectoral impacts of S.139, an additional assumption is needed regarding how emissions would be allocated among covered entities.

As long as emission allowances are allocated based on historical activities (emissions, production, etc.), the method used to allocate emissions will not affect a firm’s behavior, although alternative methods will likely have some impact on macroeconomic activity. From a firm’s perspective, the allocation of emission allowances is primarily an issue of equity and does not significantly affect energy pricing. However, there are special situations regarding regulated utilities where the allocation of emission allowances can impact energy pricing depending on regulatory decisions about the way in which the value of emissions allowances is apportioned between utility stockholders and ratepayers.

From a macroeconomic perspective with respect to S.139, the extent to which emission allowances are allocated to companies or the Corporation (which will sell them to entities) and the manner in which Corporation revenues are rebated to consumers and businesses are important.⁸³ For the S.139 case and most sensitivity cases,⁸⁶ it is assumed that, in 2010, 80 percent of the allowances are initially allocated directly to the entities and 20 percent to the Corporation. The Corporation is assumed to sell the allowances allocated to it and use the proceeds to reduce the economic impact of the allowance program through transition assistance and other transfer payments. Starting in 2011, the share allocated to entities is decreased each year until it reaches 20 percent in 2025,⁸⁷ with the remainder going to the Corporation.

For those allowances that are allocated at no cost there are numerous options for determining how to distribute them. For example, they could be distributed to existing entities based on some recent year’s emissions (what is often referred as grandfathering) or they could be distributed using some sort of output measure (such as generation in the power sector). In addition, the distribution could be a one-time event at the beginning of the program, or it could be updated annually or on some other schedule. For this analysis, it is assumed that the portion of allowances that are allocated freely is distributed based on an entity’s share of historical emissions.

Rebates for Energy-Efficient Equipment

S.139 allows covered entities to purchase allowances from noncovered entities that register greenhouse gas reductions associated with reductions in their energy use. This implies that any reduction in energy use by a noncovered entity could be used as an offset by a covered entity as long as the reduction was properly registered. Examples of energy-reducing actions include normal replacement of old, less energy efficient appliances and utility demand-side management (DSM) programs. Because the bill is likely to result in higher electricity prices, it is assumed that consumers will have an incentive to pursue demand reduction activities.

In addition, Section 352(b)(1)(A) of S.139 states that the Corporation may use “buy-down, subsidy, negotiation of discounts, consumer rebates, or otherwise,” to reduce the costs of greenhouse gas emission reductions borne by consumers. No specific preference for any of these methods is indicated in S.139. Expenditures on efficient appliances by the Corporation could increase the market penetration of more efficient equipment. As a proxy to assess the potential impact of these options, it is assumed that the Corporation will offer rebates to reduce the cost of higher efficiency equipment and allow consumers to choose that equipment if the reduction in cost makes it economic, regardless of the fuel type of the appliance. In the S.139 case, for example, the price of the most efficient central air conditioner, which is 50 percent more efficient than the standard unit, decreases in price from $3,500 to $2,900, resulting in a $600 cost difference between the least efficient and most efficient unit available for purchase from 2010 to 2025. The approach adopted to reflect these rebates is described further as part of the residential sector discussion in Chapter 4.

Evaluation of CAFE Credits

S.139 includes a provision that allocates greenhouse gas emission allowances to light-duty vehicle manufacturers whose CAFE exceeds the CAFE standard by 20 percent. In order to achieve increases in CAFE, manufacturers can employ new technologies, downsize vehicles, or offer pricing incentives to shift consumers into more efficient vehicles. For this analysis, it is assumed that manufacturers will only adopt new technologies in their efforts to increase vehicle fuel economy, thus preserving vehicle utility, comfort, performance, and occupant safety.

The provision states that the Secretary of Transportation, in consultation with the Administrator of the Environmental Protection Agency, will determine the conversion factor used to translate fuel economy improvements into greenhouse gas emissions. In order to estimate the lifetime greenhouse gas benefit of increased fuel economy one must make assumptions regarding the life of a vehicle and how that vehicle will be used over its lifetime. This study assumes 135,000 average lifetime miles of travel per light-duty vehicle. Assuming that a vehicle manufacturer meets the minimum required improvement in CAFE (20 percent) relative to the currently planned CAFE standards, this equates to approximately 2.0 metric tons of lifetime greenhouse gas savings per car and 2.4 metric tons of lifetime greenhouse gas savings per light truck.

To capture the impact of the CAFE provision, the transportation model was modified so that manufacturers evaluate the opportunity cost associated with meeting the 20 percent fuel economy improvement. As the model evaluates the decision for technology adoption, the opportunity cost associated with the potential fuel economy improvement is included in the cost evaluation, which reduces the cost of supplying fuel economy, shifting the fuel economy supply curve to the right. The structure of the algorithm reflects a gradual participation by vehicle manufacturers over time, accounting for the relative difficulty manufacturers will experience in improving CAFE based on their vehicle sales mix.

Allowance Banking Provisions

The cap and trade system in S.139 allows covered entities to buy and sell allowances and bank excess allowances for future use. Thus, the emissions of individual covered entities is not limited, and entities may over-comply to bank allowances for future use. S.139 also provides for the borrowing of allowances under specific limitations outlined in the bill, including a restriction that an entity may borrow against future emission reductions only if it can show it has a project underway to achieve those reductions, as well as a requirement that borrowed allowances must be returned with interest at 10 percent per year (in terms of allowances).

With allowance banking, the decisions to buy, sell, and hold allowances will depend on both the current and anticipated allowance prices. The allowance price path is assumed to be smoothed through expectations and arbitrage. If allowance prices grew rapidly in the future, high levels of early reductions and banking (or overcompliance) would tend to occur, because the cost of those reductions would be expected to be recoverable in the future. The buildup of high levels of banked allowances would then tend to lower expectations of prospective carbon prices and moderate banking of allowances.

The banking provisions are expected to smooth out the potential price increases that might otherwise occur during the transition from Phase I to Phase II. Details of the banking approach are discussed in Appendix B.

Scenarios Included in This Study

To respond to the requests from Senator Inhofe and Senators McCain and Lieberman, various cases showing the impacts of S.139 under a range of assumptions were analyzed. A short description of each of the cases follows.

• Reference Case: This is an updated reference case based on the assumptions of the Annual Energy Outlook 2003 reference case, with three additions. Because natural gas prices have been highly volatile, the reference case incorporates the near-term (through 2004) projections for natural gas prices from EIA’s April 2003 Short-Term Energy Outlook. This assumption mainly affects the near term but also has a slight effect on natural gas markets in the long term, generally raising prices from the AEO2003 reference case projections.

The second assumption change from the AEO2003 reference case is to supplement the near-term additions to electric generating capacity used in that document with additional capacity now expected to come on line through 2004. With new data available since preparation of the AEO2003 reference case, approximately 24 gigawatts—mainly natural-gas-fired—is now expected to come on line through 2004. The impact of this assumption on the revised S.139 reference case is to increase nearterm generating capacity additions but reduce later additions. Thus, there is little effect on the ultimate level of generating capacity.

Third, the assumptions used for AEO2003 were updated to reflect the increase in CAFE standards announced on April 1, 2003, by the National Highway Traffic Safety Administration.

• S.139 Case: This case simulates enactment of S.139, combined with AEO2003 reference case assumptions for technology. This is the principal case used to represent the overall impacts of the bill.  The other cases in the analysis are designed to test the assumptions incorporated in the S.139 case. The following assumptions are made in the S.139 case and are varied in the sensitivity cases:

o Allowance Banking: Entities can overcomply (e.g., in Phase I) and bank allowances for future use (e.g., in Phase II). Arbitrage in allowance trading and banking is assumed to limit the annual growth rate of the allowance trading price.
o Alternate Compliance Percentage: In aggregate, entities are assumed to obtain 16 percent of covered emissions allowances through the bill’s alternate compliance provisions (“offsets”) in Phase I (2010-2015) and 10 percent in Phase II (from 2016 on). Offsets come from: (1) emission reductions from noncovered entities (domestic); (2) increases in net biological carbon sequestration; and (3) international emissions reductions. The 16 percent reflects the bill’s provision that some entities will be granted a 20 percent offset percentage (instead of 15 percent) in exchange for reducing their emissions to 1990 levels by 2010.
o Commercial and Industrial Sectors: The S.139 case assumes that all entities in the commercial sector are exempt from emissions allowances and that all entities in the industrial sector are covered.
o Auction Percentage: The S.139 case assumes that 20 percent of emissions allowances will be allocated to the Corporation in 2010, increasing linearly each year to 80 percent in 2025.
o Nuclear Power and Geological Sequestration: The S.139 case assumes commercial availability of advanced nuclear plants and of geological carbon sequestration technologies in the electric power industry.

The following sensitivity cases were examined to analyze variations on the S.139 case:

• High Technology Reference Case: This alternate reference case incorporates the high technology case assumptions and is designed for comparison with the S.139 high technology case. The high technology cases incorporate alternative assumptions for the four end-use demand sectors and the electric power sector. Assumptions in the high technology cases vary by sector but generally include earlier availability, lower costs, and higher efficiencies for advanced technologies than in the reference case.

• S.139 High Technology Case: This case incorporates the high technology case assumptions used in the AEO2003 integrated high technology case.⁸⁸

• No New Nuclear/No Sequestration Case: This case shows the impacts of assuming that neither of these two technologies would be commercially available through 2025. There are siting, environmental, political, and public opinion barriers to new nuclear capacity in the United States. Also, no generating facility with carbon capture and geological sequestration has been built, leading to considerable uncertainty over whether it will be technically and economically feasible in this time horizon.

• High Natural Gas Price Reference Case: This case assumes a more pessimistic outlook for domestic natural gas supply than in the reference case, resulting in higher natural gas prices. This case assumes that the natural gas supply assumptions of the reference case are changed to reflect: (1) a 25 percent reduction in Canadian and U.S. resources, (2) a 25 percent reduction in the rate of technological advancement in Canada and the United States, (3) a 3-year increase in the total time required to construct the Alaska Natural Gas Transportation System, and (4) restrictions on new LNG facilities in the Gulf of Mexico, the Bahamas, and Baja, California. These assumptions ultimately lead to higher natural gas prices based on long-term changes in the fundamental drivers of natural gas supply.

• S.139 High Natural Gas Price Case: This case combines the high gas price reference case with enactment of S.139. It is intended to analyze the impact of higher natural gas prices on energy market decisions under S.139.

• Commercial Coverage Case: This case assumes that all entities in the commercial sector are covered. Under the S.139 case, the commercial sector is assumed not to be covered.

• 80 Percent and 20 Percent Allowance Auction Cases: The S.139 case assumes that, initially, 20 percent of the emission allowances issued by the Government will be allocated to the Corporation, increasing to 80 percent by 2025. These cases show the impacts of two fixed percentages, 80 and 20 percent, allocated to the Corporation in each year of the forecast.

• S.139 High Percentage Offset Case: This case examines the sensitivity of the S.139 case to increasing the percentage of allowance requirements that can be met by offsets to 50 percent in all years.

• S.139 International Offset Availability Cases: This pair of cases examines the impact on the S.139 case of variability in international offset availability. The first case assumes no international offsets (low international offset supply case). The second assumes a doubling in the supply of offsets available at each price (high international offset supply case).

• No Banking Case: This case assumes that banking of emissions allowances for later use by covered entities is not a compliance option. It is included to show the impacts of the banking provision in S.139.

Special Topics

2. Assumptions, Methodology, and Scenarios - Tables

Notes