1. Introduction
Background
Request for Analysis
The analysis in this report was undertaken at the request of
Senators James M. Jeffords (I-VT) and Joseph I. Lieberman (D-CT), subsequent
to the report Analysis of Strategies for Reducing Multiple Emissions from
Power Plants: Sulfur Dioxide, Nitrogen Oxides, and Carbon Dioxide, published
by the Energy Information Administration (EIA) in December 2000.1 The analysis in the December 2000 report was expanded in the report Analysis
of Strategies for Reducing Multiple Emissions from Electric Power Plants:
Sulfur Dioxide, Nitrogen Oxides, Carbon Dioxide, and Mercury and a Renewable
Portfolio Standard, published by EIA in July 2001 (see
discussion on "Analysis of Strategies for Reducing Multiple Emissions
from Electric Power Plants: sulfur Dioxide, Nitrogen Oxides, Carbon Dioxide,
and Mercury and a Renewable Portfolio Standard").2 In the July 2001 report, EIA analyzed the impacts of a number of different
limits for sulfur dioxide (SO2), nitrogen oxides (NOx),
carbon dioxide (CO2), and mercury (Hg) emissions from electricity
generators, which varied by level and start year, and a renewable portfolio
standard. The analysis was conducted relative to the reference case of the Annual Energy Outlook 2001 (AEO2001),3 published in December 2000, using EIA’s National Energy Modeling System
(NEMS).4
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For this analysis, Senators Jeffords and Lieberman requested
that EIA consider the impacts of technology improvements and other market-based
opportunities on the costs of emissions reductions from electricity generators.
Using 2002 as a start date for emissions reductions, the request specifies
that by 2007 NOx emissions from electricity generators are to be
reduced to 75 percent below 1997 levels, SO2 emissions to 75 percent
below the full implementation of the Phase II requirements under Title IV
of the Clean Air Act Amendments of 1990 (CAAA90), Hg emissions to 90 percent
below 1999 levels, and CO2 emissions to 1990 levels (Figure
1). These emissions limits are applied to all electricity generators,
excluding cogenerators, which produce both electricity and useful thermal
output and account for less than 10 percent of total generation. (Throughout
this report cogenerators are excluded when reference to electricity generators
is made.)
The impacts of these limits are analyzed against four different
cases with varying levels of energy demand: the reference case from AEO2001,
a case combining the high technology assumptions for end-use demand, supply,
and generating technologies from AEO2001, and the moderate and advanced
policy cases from Scenarios for a Clean Energy Future (CEF),
a publication of an interlaboratory working group, published in November 2000 (Table 1).5 In general, the emissions limits are achieved through a combination of reductions
in energy demand, shifts from coal-fired electricity generation to nuclear,
natural gas, and renewable generation, and additional emissions control equipment.
Within the time frame of the emissions limits, economical technologies to
capture and sequester CO2 are unlikely. Sequestration technologies
are included in the analysis but do not penetrate because they are not economical.
This chapter summarizes EIA’s previous analysis of multi-emission
reduction strategies for electricity generator emissions and the reference
case projections of AEO2001, describes the methodology of NEMS, and
summarizes CEF. Chapter 2 presents the impacts and costs of the emissions
limits for the reference and advanced technology cases. Chapter 3 presents
the impacts and costs for the cases incorporating the moderate and advanced
policies from CEF. The letter of request is provided in Appendix A,
and detailed tables of assumptions incorporated for the industrial sector
are provided in Appendix B. Appendix C presents the energy market results
for the reference and advanced technology cases, and Appendix D presents the
results for the cases based on CEF.
Multi-Emission Reduction Policies
Currently, different environmental issues are being addressed
through separate regulatory programs, many of which are undergoing modification.
To control acid rain formation, CAAA90 required operators of electric power
plants to reduce emissions of SO2 and NOx. Phase II
of the SO2 reduction program—reducing allowable SO2
emissions to an annual national cap of 8.95 million tons—became effective
on January 1, 2000. More stringent NOx emissions reductions are
required under various Federal and State laws taking effect from 1997 through
2004. States are also beginning efforts to address visibility problems (regional
haze) in national parks and wilderness areas throughout the country. Because
electric power plant emissions of SO2 and NOx contribute
to the formation of regional haze, States could require that those emissions
be reduced to improve visibility in some areas. In the near future, it is
expected that new national ambient air quality standards for ground-level
ozone and fine particulates may necessitate additional reductions in NOx
and SO2.
To reduce ozone formation, the U.S. Environmental Protection
Agency (EPA) has promulgated a multi-State summer season cap on power plant
NOx emissions that will take effect in 2004. Emissions of fine
particles (less than 2.5 microns in diameter), their impacts on health, and
the level of reductions that might be required are currently being studied.
Fine particles are associated with power plant emissions of NOx
and SO2, and further reductions in NOx and SO2
emissions could be required by as early as 2007 in order to reduce emissions
of fine particles. In addition, the EPA decided in December 2000 that Hg emissions
must be reduced (see discussion on "Reducing
NOx nd Hg Emissions"). Furthermore, if the United
States decides to reduce its emissions of greenhouse gases, it is likely that
energy-related CO2 emissions will have to be reduced as a part
of that program (see discussion on "Representatin
of New Environmental Rules and Regulations").
Because the timing and levels of emission reduction requirements
being considered are uncertain, compliance planning is complicated. It can
take several years to design, license, and construct new electric power plants
and emission control equipment, which may then be in operation for 30 years
or more. As a result, power plant operators must look into the future to evaluate
the economics of new investment decisions.
The potential for new emissions standards with different timetables
adds considerable uncertainty to investment planning decisions. An option
that looks attractive to meet one set of SO2 and NOx
standards may not be attractive if further reductions are required in a few
years. Similarly, economical options for reducing SO2 and NOx
today may not be the optimal choice in the future if Hg and CO2
emissions must also be reduced. Further complicating planning, some investments
capture multiple emissions simultaneously, such as advanced flue gas desulfurization
equipment that reduces SO2 and Hg, making such investments more
attractive under some circumstances. As a result, power plant owners currently
are wary of making investments that may prove unwise a few years hence.
In both the previous and current Congresses, legislation has
been proposed that would require simultaneous reductions of multiple emissions.
Several bills were introduced in the 106th Congress to address these issues:
S. 1369, the Clean Energy Act of 1999, introduced by Senator Jeffords; S.
1949, the Clean Power Plant and Modernization Act of 1999, introduced by Senator
Leahy; H.R. 2900, the Clean Smokestacks Act of 1999, introduced by Congressman
Waxman; H.R. 2645, the Consumer, Worker, and Environmental Protection Act
of 1999, introduced by Congressman Kucinich; and H.R. 2980, the Clean Power
Plant Act of 1999, introduced by Congressman Allen.
Additional bills introduced in the 107th Congress with similar
goals include S. 556, the Clean Power Act of 2001, introduced by Senator Jeffords;
H.R. 1256, the Clean Smokestacks Act of 2001, introduced by Congressman Waxman;
and H.R. 1335, the Clean Power Plant Act of 2001, introduced by Congressman
Allen. Each of the bills introduced in the 106th and 107th Congresses contains
provisions to reduce power plant emissions of NOx, SO2,
CO2, and Hg over the next decade. The bills use different approaches—traditional
technology-specific emission standards, generation performance standards,
explicit emission caps with trading programs, or combinations of the three—but
all call for significant reductions. In addition, the Bush Administration’s
National Energy Policy recommends the establishment of “mandatory reduction
targets for emissions of three main pollutants: sulfur dioxide, nitrogen oxides
and mercury.”6 While
differences exist on what the appropriate emissions limits should be and how
the program should be implemented, it is generally agreed that a more coordinated
emission reduction policy is worth pursuing.
The analysis presented in this report is an examination of
the impacts on energy markets that might result from steps taken by power
suppliers to meet the emission limits specified in the request, given varying
levels of energy demand. The potential benefits of reduced emissions—such
as those that might be associated with reduced health care costs—are
not addressed, because EIA does not have expertise in this area. It is important
to realize that there are numerous policy instruments available for reducing
emissions, i.e., technology standards, percentage reduction requirements,
emission taxes, no-cost emission allowance allocation with cap and trade,
emission allowance auction with cap and trade, and annual generation performance
standard emission allowance allocation with cap and trade. Each of these approaches
has different implications for the resource cost, price, and economic impacts
of the emission reduction program. In general, an efficient cap and trade
program is expected to lead to the lowest resource cost of compliance.7
The specific design of the cases, in terms of the timing, emissions
limits, and technology assumptions, is important and should be kept in mind
when the results are reviewed. Unlike the previous EIA reports on multi-emissions
limits, all the cases specified in this request require the same timing and
levels for the four emissions. The differences among the cases are additional
assumptions, policies, and programs that encourage more rapid technology development
and the adoption and penetration of more energy-efficient and renewable energy
technologies. All the analysis cases assume that market participants—power
suppliers, consumers, and coal, natural gas, and renewable fuel suppliers—would
become aware of impending emission limits before their start dates and would
begin to take action accordingly. If it had been assumed that market participants
would not anticipate the emission limits, the results would be different.
In an earlier EIA study that looked at alternative program start dates for
imposing a CO2 emissions limit, an earlier start date and longer
phase-in period were found to smooth the transition of the economy.8
This study is not intended to be an analysis of any of the
specific congressional bills that have been proposed, and the impacts estimated
here should not be considered as representing the consequences of specific
legislative proposals. All the congressional proposals include provisions
other than the emissions limits studied in this analysis, and several would
use different policy instruments to meet the emissions limits. Moreover, some
of the actions projected to be taken to meet the emissions limits in this
analysis may eventually be required as a result of ongoing environmental programs
whose requirements currently are not fully specified. The purpose of this
report is to respond to the specific request by Senators Jeffords and Lieberman.
The
National Energy Modeling System and the Annual Energy Outlook
2001
The National Energy Modeling System
The projections in this report were developed using NEMS, an
energy-economy modeling system of U.S. energy markets, which is designed,
implemented, and maintained by EIA and used annually to produce the projections
in EIA’s Annual Energy Outlook. NEMS is also used to analyze the
effects of existing and proposed laws, regulations, and standards related
to energy production and use; the impacts of new and advanced energy technologies;
the savings from higher energy efficiency; the impacts of energy tax policy
on the U.S. economy and energy system; and the impacts of environmental policies.
Special analyses of these and other topics are performed at the request of
the U.S. Congress, other offices in the U.S. Department of Energy (DOE), and
other government agencies.
In NEMS, the production, imports, conversion, consumption,
and prices of energy are projected for each year through 2020, 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.
NEMS is a fully integrated framework, capturing the interactions of energy
supply, demand, and prices across all fuels and all sectors of U.S. energy
markets.
Within NEMS, four end-use demand modules represent energy consumption
in the residential, commercial, industrial, and transportation sectors, subject
to fuel prices, macroeconomic factors, and the characteristics of energy-using
technologies in those sectors. The fuel supply and conversion modules represent
the domestic production, imports, transportation, and conversion processes
to meet the domestic and export demand for coal, petroleum products, natural
gas, and electricity, accounting for resource base characteristics, industry
infrastructure and technology, and world market conditions. The modules of
NEMS interact to solve for the economic supply and demand balance for each
fuel.
In order to capture regional differences in energy consumption
patterns and resource availability, NEMS is a regional model. The end-use
demand for energy is represented for each of the nine Census divisions. The
supply and conversion modules use the North American Electric Reliability
Council regions and subregions for electricity generation; aggregations of
the Petroleum Administration for Defense Districts for refineries; and production
regions specific to oil, natural gas, and coal supply and distribution.
NEMS incorporates interactions between the energy system and
the economy and between domestic and world oil markets. Key macroeconomic
variables, including the gross domestic product (GDP), disposable personal
income, industrial output, housing starts, employment, and interest rates,
drive energy consumption and investment decisions. In turn, changes in energy
prices and energy activity affect economic activity, a feedback captured within
NEMS. Also, an international energy module in NEMS represents world oil prices,
production, and demand and the interactions between the domestic and world
oil markets. Within this module, world oil prices and supplies respond to
changes in U.S. demand and production.
A key feature of NEMS is the representation of technology and
its improvement over time. The residential, commercial, transportation, electricity
generation, and refining sectors of NEMS include explicit treatments of individual
technologies and their characteristics, such as capital cost, operating cost,
date of commercial availability, efficiency, and other characteristics specific
to the sector. In each of these sectors, equipment choices are made for individual
technologies as new equipment is needed to meet growing demand for energy
services or to replace retired equipment. In addition, in the electricity
generation sector, fossil-fired and nuclear generating units can be retired
before the end of their useful lives if it is more economical to bring on
a replacement unit than to continue to operate the existing unit. Also, for
new generating technologies, the electricity sector accounts for technological
optimism in the capital costs of first-of-a-kind plants and for a decline
in the costs as experience with the technologies is gained both domestically
and internationally. Similar cost declines occur for the new end-use technologies.
In the other sectors—industrial, oil and gas supply, and
coal supply—the treatment of technologies is somewhat more limited due
to limitations on the availability of data for individual technologies. In
the industrial sector, technology improvement for the major processing steps
of the energy-intensive industries is represented by technology possibility
curves of efficiency improvements over time. In the oil and gas supply sector,
technology progress for exploration and production activities is represented
by trend-based improvements in success rates, finding rates, and costs. Productivity
improvements over time represent technological progress in coal production.
Because of the detailed representation of capital stock vintaging
and technology characteristics, NEMS captures the most significant factors
that influence the turnover of energy-using and producing equipment and the
choice of new technologies. New, more advanced technologies for buildings
and equipment are generally characterized by the technology costs, performance,
and availability, existing standards, and energy prices. Equipment that does
not meet efficiency standards is not available as a choice. In all sectors,
technology improvement occurs even in a reference case, because new, more
efficient technology will be adopted as the demand for energy services increases
and existing buildings and equipment are replaced. The characteristics of
the technologies include initial dates of commercial availability of more
advanced technologies as well as changes in efficiencies and costs that are
assumed to occur in the future.
Past improvements in energy efficiency have resulted in part
from efficiency standards that are included in the analysis; future efficiency
standards assumed are those approved standards with specified efficiency levels.
New or tightened efficiency standards could reduce the demand for energy,
but stock turnover would still limit the speed of penetration. Standards have
also been suggested to encourage the use of renewable fuels for electricity
generation; however, proposed and possible future standards, legislation,
and programs are not included in the analysis.
Although more efficient technologies may reduce energy consumption
and energy expenditures, they are typically more expensive to purchase. Even
if the full life-cycle cost of purchasing and operating a new, more efficient
appliance is less than the life-cycle cost of a less efficient appliance,
many consumers appear to be more concerned with the initial cost of an appliance
when making the purchase. Higher energy prices may accelerate the adoption
of more efficient technologies; however, higher purchase costs for more efficient
technologies tend to slow their adoption. Hurdle rates represent this tendency
of consumers to consider the first costs of new equipment.
Although prices play a role in consumers’ decisions on
energy-consuming equipment, there are other factors that come into play. Consumers
tend to make decisions based on a number of personal preferences and lifestyle
choices, in which energy prices may be only a part of the decisionmaking process.
Preferences for larger televisions or higher horsepower vehicles are examples
of factors that may outweigh energy costs. As another example, in the residential
sector, home rental instead of purchase and frequent moving tend to lower
the incentive to invest in more energy-efficient equipment. Information also
has a major role in consumer decisions and will likely continue to do so in
the adoption of new, more advanced technologies. Particularly when a more
efficient or alternatively fueled technology carries a significantly higher
cost or has different operational characteristics than more conventional technologies,
information on the benefits of the new technology will be key to its adoption
and penetration. Ultimately, the success of a given technology will depend
not on the behavior of the marginal consumer, who may be particularly cost-conscious
or innovative, but on the behavior of the average consumer, whose decision
rests on a number of considerations.
Technology improvements, even when adopted in the market, may
not necessarily lead to reductions in energy demand. In the transportation
sector, for example, the use of more advanced technologies that could improve
vehicle efficiency has been offset by increasing demand for larger and higher
horsepower vehicles. To the extent that energy prices are a factor in consumer
decisions, efficiency improvements may also increase energy demand. Efficiency
gains may lower the cost of driving or operating other equipment, perhaps
encouraging more travel, larger homes, and purchases of more equipment and
increasing the demand for energy services.
Annual Energy Outlook 2001
In accordance with the request from Senators Jeffords and Lieberman,
this study is based on the reference case of AEO2001. Because EIA’s
reference case projections are required to be policy-neutral, the AEO2001 projections generally assume that all Federal, State, and local law, regulations,
policies, and standards in effect as of July 1, 2000, will remain unchanged
through 2020. Potential impacts of pending or proposed legislation, proposed
standards, legislation or regulations for which all specifics were not yet
defined, or sections of existing legislation for which funds had not been
appropriated prior to the preparation of AEO2001 are not included in
the projections. As a result, new regulations for diesel fuel and the new
equipment efficiency standards announced in January 2001 are not included
in the AEO2001 projections. AEO2001 assumes the continuation
of the ethanol tax incentive through 2020. AEO2001 also assumes that
State taxes on gasoline, diesel, jet fuel, methanol, and ethanol will increase
with inflation and that Federal taxes on those fuels will continue at 1999
levels in nominal terms. Although these taxes and tax incentives include clauses
that limit their duration, they have been extended historically, and AEO2001 assumes their continuation throughout the forecast. In general, the AEO2001 projections include the most current data available as of July 31, 2000.
In the electricity generation sector, AEO2001 includes
the requirements of the CAAA90 to reduce SO2 emissions to 8.95
million tons by 2010 and to meet new boiler standards for NOx. AEO2001 also represents the provisions of the NOx State
Implementation Plan call in the 19 States where NOx caps have been
finalized. Those NOx constraints begin in 2004 and are for the
summer season only. Regulations that are not in place or are without specific
guidelines are not included in AEO2001. In the electricity sector,
these include new regulations for regional haze, which may affect electricity
generators, but for which the State implementation plans are not required
until 2004 or later, and new National Ambient Air Quality Standards for particulates,
which are still being reviewed by the EPA and the courts. In addition, Hg
emission reductions that may be required in the future by the EPA, which has
announced that regulations will be issued by 2004, are not incorporated because
they have not been finalized.
AEO2001 projects that the U.S. economy, measured by
real GDP, will grow at an average annual rate of 3.0 percent from 1999 through
2020. In AEO2001, both world oil prices and domestic natural gas prices
are projected to decline over the next several years from their current high
levels before gradually increasing in response to rising demand. Due to continued
technological improvement in the production of oil and the expansion of production
capability worldwide, the world oil price is expected to reach $22.41 per
barrel in 2020 in real, inflation-adjusted 1999 dollars. With technological
advances in the exploration and production of natural gas, the average wellhead
price is projected to be $3.13 per thousand cubic feet in 2020. The average
price of coal declines throughout the projection period due to increasing
productivity in coal production and the expansion of production from lower-cost
western sources.
The AEO2001 projections assume a transition to full
competitive pricing of electricity in States with specific deregulation plans—California,
New York, New England, the Mid-Atlantic States, Illinois, Texas, Oklahoma,
Michigan, Ohio, Arizona, New Mexico, and West Virginia. Other States are assumed
to continue cost-of-service electricity pricing. A transition from regulated
to competitive prices over a 10-year period from the beginning of restructuring
in each region, and implementation of the provisions of California legislation
regarding price caps, are assumed. Increased competition in electricity markets
is also represented through assumed changes in the financial structure of
the industry and efficiency and operating improvements that reduce operating
and maintenance, administrative, and other costs. With these assumptions and
declining coal prices, real average delivered electricity prices are projected
to decline generally at an average annual rate of 0.5 percent between 1999
and 2020.
Electricity demand is projected to increase at an average annual
rate of 1.8 percent between 1999 and 2020, most rapidly in the residential
and commercial sectors due to growth for computers, office equipment, and
other electrical equipment and appliances. Electricity generation fueled by
natural gas and coal is projected to increase through 2020 to meet growing
demand for electricity and to offset the projected retirement of existing
nuclear and fossil units. Excluding cogeneration, the share of natural gas
generation is projected to increase from 11 percent in 1999 to 33 percent
in 2020, and the coal share is projected to decline from 54 percent to 47
percent, because electricity industry restructuring favors the less capital-intensive
and more efficient natural gas generation technologies. Retirements of nuclear
plants in the forecast are based on the costs of continuing to operate existing
plants compared with the cost of new generating capacity. Of the 97 gigawatts
of nuclear capacity available in 1999, 26 gigawatts is projected to be retired
by 2020, and no new plants are expected to be constructed by 2020. The use
of renewable energy technologies for electricity generation is projected to
grow slowly because of the relatively low costs of fossil-fired generation
and because electricity restructuring favors less capital-intensive natural
gas technologies over coal and baseload renewable technologies.
With decreases or moderate increases in the prices of energy
and continued economic growth, total energy consumption in AEO2001 is projected to increase at an average rate of 1.3 percent per year through
2020, reaching 127 quadrillion British thermal units (Btu). Consumption in
all end-use sectors grows in the projections; however, demand in the transportation
sector increases most rapidly, reflecting increased travel and slow improvement
in vehicle efficiency. Primary energy intensity, measured as energy use per
dollar of real GDP, declines in the projections at an average annual rate
of 1.6 percent. This rate is less than the 2.3-percent decline in energy intensity
experienced between 1970 and 1986, when rapid price increases and a shift
to less energy-intensive industries led to rapid improvements in energy intensity.
However, the intensity decline is more rapid than the average decline in the
late 1980s and 1990s, reflecting efficiency improvements and continued structural
shifts in the economy, which reduce the role of energy-intensive manufacturing
industries.
CO2 emissions from energy combustion are projected
to increase at an average rate of 1.4 percent per year in AEO2001,
growing from 1,511 to 2,041 million metric tons carbon equivalent between
1999 and 2020. Continuing economic growth and increasing demand for energy
services lead to the continued projected growth in emissions. The slow growth
of renewable technologies and the decline of electricity generation from nuclear
power plants also contribute to emissions increases.
Revisions
to the AEO2001 Reference Case
In accordance with the request, this study is based on the
version of NEMS used in AEO2001; however, a few updates have been incorporated
for this study.
Short-Term
Energy Price Updates
In addition to the Annual Energy Outlook, EIA also publishes
the Short-Term Energy Outlook (STEO), a national-level, quarterly
projection of U.S. energy supply, demand, and prices. The short-term forecast,
which projects energy markets through the end of the following calendar year,
is updated monthly. At the time the projections for AEO2001 were finalized,
the short-term results from AEO2001 were calibrated to the September
2000 STEO. World crude oil prices for 2000 are currently estimated
at $27.72 per barrel, compared to $28.17 per barrel in AEO2001, converted
to 2000 dollars. At this time, crude oil prices in 2001 are projected to be
similar to those projected in AEO2001.
A more significant change has occurred in the projections for
natural gas. Converting to nominal dollars, natural gas wellhead prices in AEO2001 are projected to be about $3.40 and $3.50 per thousand cubic
feet in 2000 and 2001, respectively. Natural gas prices have been revised
in the version of NEMS used in this study, to about $3.60 and $4.75 per thousand
cubic feet in 2000 and 2001, respectively. Natural gas consumption projections
in AEO2001 are 22.0 and 22.7 trillion cubic feet for 2000 and 2001,
respectively. Consumption is now estimated at higher levels and is calibrated
to the April 2001 STEO, resulting in natural gas consumption estimates
of 23.0 and 23.3 trillion cubic feet in 2000 and 2001. In the longer term,
natural gas wellhead prices are now projected to decline at a slower rate
through the next decade than in AEO2001 and are projected in this study
to rise to $3.10 per thousand cubic feet in 2020, similar to the projection
of $3.13 per thousand cubic feet in AEO2001 (both in real 1999 dollars).
Total natural gas consumption is projected to be slightly higher, reaching
35.0 trillion cubic feet in 2020, as compared with 34.7 trillion cubic feet
in AEO2001.
New Equipment Standards
New equipment standards were issued by DOE in January 2001
and revised by the Bush Administration. Because the standards were not finalized
when the projections for AEO2001 were completed, they are not incorporated
in the AEO2001 projections. The new standards have been incorporated
in all of the cases in this study, as shown in Table
2. Incorporating these standards reduces the projected demand for electricity
and natural gas after 2004, particularly in the residential sector. Projected
impacts on commercial energy consumption are small.
Electricity Revisions for Emissions Modeling and Data
Updates
AEO2001 incorporates current regulations for emissions
of SO2 and NOx by electricity generators. However, in
order to examine multi-emissions reduction strategies, the electricity market
module (EMM) of NEMS has been revised to evaluate the impacts of limits on
Hg emissions. Potential strategies for reducing Hg emissions include reducing
electricity demand, switching to coal types with lower Hg content, installing
control equipment, and switching to other fuels, such as natural gas, with
little or no Hg content. Changes in electricity demand due to limits on Hg
emissions could occur as the costs of compliance result in higher electricity
prices. The coal market module (CMM) of NEMS evaluates switching to different
coal types in order to reduce Hg emissions. EMM evaluates options to retrofit
pollution control equipment and switch fuels in order to achieve Hg emissions
limits.
Planning decisions to reduce Hg emission rates at coal-fired
plants involve a variety of pollution control equipment. Control devices for
SO2 and NOx can also affect Hg emissions. Therefore,
EMM has been revised since AEO2001 to specify coal-fired plants according
to the type of scrubber (wet, dry, or none) and NOx controls (low-NOx
burners, selective catalytic reduction, selective noncatalytic reduction,
or none). Also, EMM now represents additional equipment, such as spray cooling
and fabric filters, that can also reduce Hg emissions with activated carbon
injection. This expanded representation of coal-fired plant types considers
planning decisions to use control devices for individual or combinations of
pollutants.
In addition to constructing plants with emissions control equipment,
Hg emissions can also be limited by switching from coal to other fuels with
lower emission rates. Within EMM, available plants are dispatched according
to their variable costs, which include fuel, operating and maintenance, and
emissions costs. The emissions component has been revised to include the Hg
allowance cost, i.e., the product of the resulting Hg emissions and the allowance
price, in addition to the SO2 and NOx allowance costs.
Imposing a limit on Hg emissions could revise the dispatch order if a plant
with lower fuel costs but higher emissions costs, such as coal, becomes less
economic than a plant with higher fuel costs but lower emissions costs, such
as natural gas.
CAAA90 currently provides limits on NOx emission
rates for generating units, which depend on the type of boiler. Additional
restrictions on NOx emissions are specified for selected eastern
States during the summer months. Since AEO2001, EMM has been revised
to consider simultaneously a national, annual limit on NOx emissions
that is similar to the “cap and trade” system that limits SO2
emissions under CAAA90. Because it is assumed that proposed regulations to
reduce SO2 emissions further would incorporate the current trading
system, no additional modifications were required.
Updates to available generating capacity have also been incorporated
since AEO2001. Units previously unreported to EIA that began operation
in 1999 and 2000 are now included in the existing capacity. Most of these
units use natural gas, which produces fewer emissions than coal- or petroleum-fired
capacity. Expected additions of renewable generating capacity in 2000 and
2001 have also been increased, primarily as a result of State mandates, as
noted below. Finally, the projected capacity mix incorporates future installations
of pollution control equipment and conversions of plants resulting from the
settlement of lawsuits between some electricity generators and the EPA.
Revisions
to Renewables Data and Assumptions
AEO2001 incorporates near-term projections for known
new renewable energy capacity resulting from State mandates and voluntary
programs, totaling 5.4 gigawatts by 2020, 3.1 gigawatts of which were from
wind power. For this study, estimates of geothermal and wind power have been
updated to account for additional announced units and accelerated completions
for units that are expected after 2001 in AEO2001. As a result, 7.5
gigawatts of additional planned capacity is now included by 2020, 5.1 gigawatts
of which is wind capacity.
AEO2001 assumptions include estimates of geothermal
resource supply from 51 known geothermal resource areas in the United States;
however, it is unlikely that most of the geothermal resources at many new
untested sites would be used before 2020. Instead, much smaller installations
would be built first, with expansion moving more slowly as additional units
prove successful. Furthermore, the AEO2001 estimates do not account
for environmental, market, and other limitations likely to constrain development
at many sites. Therefore, for this study, estimates of geothermal resources
have been reduced from nearly 47 gigawatts in AEO2001 to about 28 gigawatts,
to provide a more accurate representation of likely development opportunities
through 2020. As a result, the cost of geothermal energy is generally higher,
and the total quantity of geothermal supply is lower than in AEO2001.
Because wind and solar power are intermittent sources of electricity
generation, AEO2001 assumes that no more than 12 percent of the annual
generation in any region could be provided by these sources in order to avoid
electric power system disturbances. However, based on research done by the
National Renewable Energy Laboratory and more recent experience, this assumed
limit has been raised to 15 percent for the reference and advanced technology
cases but is not a binding limit.9
As assumed in the CEF analysis, the limit is removed
in the cases that incorporate the CEF policies. The limit would not
have been a constraint in the case with the moderate CEF policies.
In the case incorporating the advanced CEF policies, the limit would
have been binding for the Upper Great Plains and Rocky Mountain/Southwest
regions.
In order to account for short-term supply bottlenecks, the AEO2001 version of NEMS assumes that, if the national capacity of any
renewable generating technology increases by more than 30 percent in one year,
the overnight capital cost for that technology would increase by 0.5 percent
for each 1-percent capacity increase over 30 percent. Recognizing large worldwide
growth for major renewable energy technologies and increased ability to meet
demand growth in any country, the threshold has been increased from 30 percent
to 50 percent in this study.
Modifications to Coal Production Data and Assumptions
Similar to EMM, revisions have been made to CMM following the AEO2001 in order to add the capability to evaluate the impacts of Hg
emissions limits at U.S. coal-fired power plants. An annual constraint on
Hg emissions within CMM and the assignment of an average Hg content for each
of the 35 coal supply sources represented in CMM have both been incorporated.
The Hg emissions factors in CMM range from a low of 2.04 pounds Hg per trillion
Btu for low-sulfur subbituminous coal originating from mines in the Rocky
Mountain supply region (Colorado and Utah) to 63.90 pounds Hg per trillion
Btu for waste coal originating from sites in Northern Appalachia (Pennsylvania,
Ohio, northern West Virginia, and Maryland).10
An additional revision made to CMM concerns the size and duration
of existing contracts between coal suppliers and electricity generators. In
the cases with emissions limits in this analysis, all coal supply contracts
are assumed to be phased out by 2003, reflecting the assumption that the accelerated
and more stringent emission restrictions would constitute sufficient justification
to end contracts under force majeure measures.
Scenarios
for a Clean Energy Future
Background
CEF was commissioned by DOE’s Office of Energy
Efficiency and Renewable Energy. The report was prepared by an interlaboratory
working group from Argonne National Laboratory, Lawrence Berkeley National
Laboratory, the National Renewable Energy Laboratory, Oak Ridge National Laboratory,
and Pacific Northwest National Laboratory.
The purpose of CEF was to analyze the impacts of various
energy policies and programs that would promote “clean energy technologies,”
which include reducing the energy intensity of the economy, reducing the CO2
intensity of the energy used, and integrating the sequestration of CO2
into energy production and delivery. According to the CEF working group,
the collection of policies was developed to address key energy issues such
as emissions, oil import dependency, and energy and economic efficiency. The
policies, which are listed in Chapter 3 of this report, include fiscal
incentives, voluntary programs, regulations, and research and development.
CEF analyzed business-as-usual, moderate, and advanced
cases. The business-as-usual case assumed current energy policies and programs
as of the time CEF was prepared, as well as continued technological
improvement. It was based on the reference case from the Annual Energy
Outlook 1999 (AEO99), the most recent Annual Energy Outlook available at the time the CEF analysis was initiated.11 As discussed later, a number of significant modifications have been introduced
into NEMS since AEO99, including, for example, higher projections of
economic growth and electricity demand, which lead to higher energy demand
and CO2 emissions.
The moderate and advanced cases in CEF included energy
policies and programs to address the energy issues noted above, which can
include new programs or extensions of existing programs. In general, the advanced
case included additional or extended programs relative to the moderate case.
The advanced case also included a domestic CO2 trading system that
was assumed to equilibrate at a permit value of $50 per metric ton carbon
equivalent. Additional sensitivities were presented in the report, including
cases with higher natural gas and petroleum prices, a shorter life for a proposed
renewable portfolio standard, higher costs for renewable technologies, higher
costs of advanced fossil-fired generating technologies, no diesel penetration
in light-duty vehicles, and a carbon fee of $25 per metric ton carbon equivalent;
however, these sensitivities were not the primary results of the study. Most
of the sensitivities were designed to analyze some key uncertainties in the
analysis as identified by the CEF working group.
The CEF study followed an earlier report, Scenarios
of U.S. Carbon Reductions, published by an interlaboratory working group
in 1997.12 The earlier report
outlined and analyzed technologies to reduce energy consumption and CO2
emissions, looking at the individual energy sectors separately. According
to the CEF authors, CEF differed from the prior study by examining
the policies and programs that would encourage the adoption and penetration
of clean energy technologies. Also, CEF included an integrated analysis
to assess the impacts of certain changes in one energy sector throughout the
energy system—for example, the impact of lower electricity demand on
the requirements for electricity generation or the impact of changes in fuel
demand on prices. In some cases, CEF used a revised version of the AEO99 version of NEMS, referred to as CEF-NEMS, to implement
the CEF policies directly. In many cases, the policies were analyzed
separately, and the results were incorporated in CEF-NEMS, using the
modeling system as an accounting system to capture the intersectoral impacts.
CEF Revisions to the AEO99 Reference Case
The CEF working group developed a revised version of
NEMS, referred to as CEF-NEMS, which was based on the NEMS version
used for AEO99. According to the CEF authors, the following
revisions were made to the AEO99 model and assumptions.
In the industrial demand sector, the baseline energy intensities
were revised in CEF for three of the energy-intensive industries—paper
and pulp, cement, and steel—and the rate of improvement in the energy
intensity of those three industries was accelerated relative to the rate of
improvement assumed in AEO99. Since the version of NEMS used for AEO2001,
as well as AEO99, is calibrated to the 1994 Manufacturing Energy Consumption
Survey, no changes were made to these baseline data for this study. The retirement
rates of equipment in all industries were revised to reflect an assessment
of shorter equipment life. These revisions were typically quite small, and
some revised rates have been incorporated in NEMS since AEO99. As a
result of these modifications, projected primary energy consumption for the
industrial sector in CEF was approximately 1 quadrillion Btu lower
in 2020 than the 42.1 quadrillion Btu projected in AEO99.
Four sets of changes were made to the AEO99 reference
case assumptions in the electricity market module of CEF-NEMS. First,
co-firing of biomass in coal plants was incorporated, which is a feature later
added to NEMS by EIA. Second, modifications were made in CEF-NEMS to
certain costs applied to wind generation. AEO99 assumed decreasing
capital costs for wind generation technology due to learning effects as more
units are built but higher resource costs once low-cost wind resources were
used, to reflect decreasing quality of available resources, transmission network
upgrades, and alternative uses for land. In CEF-NEMS, these costs were
reduced and regional limits on the growth in wind generation in a single year
were removed, omitting some important costs necessary in evaluating wind supply.
Although these modifications had little impact on the CEF business-as-usual
case, they had a much larger impact on the moderate and advanced cases.
Third, CEF-NEMS removed a constraint on the expansion
of geothermal generation. In AEO99, it was assumed that a new geothermal
site was limited to 50 megawatts of capacity, with a 3-year delay before additional
capacity could be built at that site, reflecting the geothermal industry practice
of gradual site testing and phased commercial expansion. Although a 50-megawatt
constraint may have been too restrictive for some sites, particularly in cases
with a high demand for renewable technologies, removing the constraint altogether
could result in unrealistic projections of geothermal builds.
Finally, the revision to the electricity generation assumptions
that had the most impact on the results of the CEF business-as-usual
case was to reduce the cost of nuclear plant refurbishment and relicensing.
In AEO99, it was assumed that a charge of $150 per kilowatt would be
required to operate a nuclear unit beyond 30 years of age for an additional
10 years. An additional charge of $250 per kilowatt would be required to operate
a unit for 20 years past its current license expiration date of 40 years.
These costs were designed to capture age-induced impacts on operating costs
of the unit. At both steps of this cost evaluation, if the total costs of
continuing to operate the unit were less than the costs of building new capacity,
the unit would continue in operation. In CEF-NEMS, the 40-year charge
was reduced to $50 per kilowatt. As a result, fewer nuclear plants were retired
in the CEF business-as-usual case than in the AEO99 reference
case, reducing the need for additional capacity additions, which are largely
fossil fuel fired, and making CO2 emissions reductions easier in
the CEF moderate and advanced cases.
In the AEO99 reference case, nuclear capacity declined
from 99 gigawatts in 1997 to 49 gigawatts in 2020; in the CEF business-as-usual
case, nuclear capacity declined to 72 gigawatts. As a result, nuclear generation,
which declined from 629 to 359 billion kilowatthours between 1997 and 2020
in AEO99, only declined to 520 billion kilowatthours in 2020 in the CEF business-as-usual case. Due to more nuclear and less fossil-fired
generation, electricity generator CO2 emissions in the CEF business- as-usual case reached 709 million metric tons carbon equivalent,
as compared with 746 million metric tons carbon equivalent in AEO99.
Since AEO99, the methodology for projecting nuclear
retirements has been revised and aging-related cost assumptions have been
lowered. In AEO2001, more gradual increases in annual expenditures
due to aging are assumed, rather than a one-time investment, and mainly after
40 years of operation. From 30 to 40 years of age, the aging-related cost
is assumed to increase by $0.25 per kilowatt per year; from age 40 to 50 an
additional annual cost of $13.50 per kilowatt is assumed; and from age 50
to 60 an additional annual cost of $25 per kilowatt is assumed. In AEO2001,
nuclear capacity is projected to be 72 gigawatts in 2020, the same as in CEF.
In 2020, nuclear generation is projected to be 574 billion kilowatthours in AEO2001, with electricity generator CO2 emissions of 772
million metric tons carbon equivalent. The higher projection for emissions
is largely due to higher projected economic growth and electricity demand
in AEO2001.
Total primary energy consumption in the AEO99 reference
case and the CEF business-as-usual case was projected to increase from
94 to 120 quadrillion Btu between 1997 and 2020. Primarily as a result of
more nuclear generation, total projected CO2 emissions in the CEF business-as-usual case reached 1,922 million metric tons carbon equivalent
in 2020, as compared with 1,975 million metric tons carbon equivalent in the AEO99 reference case. In AEO2001, total energy consumption in
2020 is projected to be 127 quadrillion Btu, with CO2 emissions
of 2,041 million metric tons carbon equivalent.
Summary
of Results in CEF
Many of the policies in CEF, which are enumerated in
Chapter 3, were aimed at encouraging the adoption and penetration of more
energy-efficient technologies. These included financial incentives, research
and development, efficiency standards (which are important policies in the
buildings sectors), and voluntary agreements and deployment programs. As requested,
this analysis incorporates the same policies assumed by the CEF analysts
where possible; however, several general issues are noted below that may call
these assumptions into question:
- Many of the CEF policies are based on additional funding for technology
research and development, totaling $1.4 billion (1997 dollars) per year
in the moderate case and $2.8 billion per year in the advanced case, with
the costs shared between the public and private sectors. These included
most of the CEF transportation policies, the CEF policies
for electricity generation technologies, and, to a lesser extent, the policies
for technologies in the other end-use sectors. The impacts of research and
development funding for new technologies, whether ongoing or incremental,
are difficult to quantify. Some of the proposed funding for technology may
achieve benefits only in a long time frame (beyond 2020) or may not achieve
success at all, and predicting which technology development will be successful
is highly speculative. A specific link cannot be established between levels
of funding for research and development and specific improvements in the
characteristics and availability of energy technologies. Because these funding
increases are questionable and the link between funding and technology development
is tenuous, the suggested technology improvements based on these research
and development policies are also questionable. Although the environmental
benefits of the advanced case would be higher than those of the moderate
case, the associated costs would also be higher. The environmental benefits
are not quantified.13
- Many CEF policies, particularly in the industrial sector, relied
on voluntary and information programs. Similar to assessing the impact
of increased research and development funding, it is also difficult to
analyze the impacts of information programs, voluntary initiatives, and
partnerships on realized technology development and deployment. Some voluntary
programs appear to have achieved success. Although the benefits of past
efforts are difficult to quantify, they are generally assumed in the efficiency
trends in the reference case.
- Some of the CEF policies required legislative or regulatory
actions that may not be enacted. These included tax credits for certain
high-efficiency vehicles and renewable generation technologies, new equipment
standards, national electricity industry restructuring, a renewable portfolio
standard (which requires a specified percentage of electricity sales to
be generated from renewable sources other than hydropower), new particulate
standards, and pay-at-the-pump motor vehicle insurance. To the extent
that these are not enacted or are enacted at later dates than assumed
in CEF, the results of the CEF analysis would be altered.
- Certain technology cost reductions in the CEF analysis appear
unrealistic. For example, in the residential sector, the cost of the most
efficient unit for some appliances was reduced to the cost of the least
efficient unit. It seems unlikely that either research and development
or voluntary programs could reduce technology costs to that level. Other
technology assumptions also appear unrealistic—for example, the assumption
that generating plants using CO2 sequestration technology would
achieve the same efficiency as those that do not.
- In the residential and commercial sectors, consumer hurdle rates were
significantly reduced. These hurdle rates represent the willingness of
consumers to invest in energy-efficient equipment. In practice, hurdle
rates are often much higher than the cost of borrowing money, for reasons
including transaction costs, a desire for equipment features other than
efficiency, and builders or building owners who purchase the equipment
but do not pay the energy bills. Although these hurdle rate reductions
in the CEF analysis were attributed to voluntary programs and other
policies, they appear to be optimistic in their valuation of consumer
desire for energy efficiency, resulting in hurdle rates of 15 percent,
which are less than the interest rates charged by many credit cards.
- In the CEF analysis, the growth rates for miscellaneous electricity
uses in both the residential and commercial sectors were significantly reduced.
Miscellaneous electricity uses consist of a variety of smaller end uses
not individually identified in NEMS. Energy used by small heating elements,
motors, and electronic devices comprises miscellaneous uses in the residential
sector. In the commercial sector, miscellaneous electricity uses include
a myriad of devices such as transformers, automated teller machines, traffic
lights, telecommunications equipment, and medical equipment.14 The modifications to miscellaneous electricity growth rates were largely
attributed by the CEF authors to voluntary programs, State market
transformation programs, and, in the advanced case, to a 2004 commercial
transformer standard. The reductions in the growth rates appear unrealistic
given the equipment in these categories, where it is unlikely that the use
of the equipment will be greatly reduced. Although there is the potential
for some efficiency improvements, it is unlikely that efficiencies could
improve enough to reach the consumption levels achieved in CEF. Some
of these small appliances include heating elements that cannot readily incorporate
increased efficiency.
- From a macroeconomic perspective, the crucial assumption underlying the CEF study was that the economy currently is not using its resource
base efficiently—i.e., that the economy is not on the production possibilities
curve. The study assumed that overcoming large-scale market failures can
place the economy on this frontier with less energy use and fewer emissions.
However, many of the presumed market failures are actually rational, efficient
decisions on the part of consumers given current technology, expected prices
for energy and other goods and services, and the value they place on their
time to evaluate options. As Henry Jacoby points out, “The key difference
between market barriers and market failures is that correcting failures
may sometimes produce a net benefit, whereas overcoming barriers always
involves cost.”15
As noted in Table 3, CEF projected lower energy consumption and CO2 emissions
in the business-as-usual case than in the AEO2001 reference case, due
to modifications to the AEO99 reference case in the CEF analysis
and to the changes in the model methodologies and assumptions, particularly
the economic growth rates, in AEO2001 relative to AEO99. CEF projected that the policies in the moderate case and the advanced case
could further reduce total energy consumption by 8 percent and 19 percent,
respectively, in 2020 relative to the business-as-usual case. In the advanced
case, CEF projected that total energy consumption would increase at
an average annual rate of 0.4 percent between 1997 and 2010 then decrease
at an average annual rate of 0.3 percent between 2010 through 2020. Given
growing population and a growing economy, an actual decrease in energy consumption
as projected in CEF would appear unlikely without significant increases
in energy prices. Total energy consumption in the CEF advanced case
was projected to reach 99 quadrillion Btu in 2010, declining to 97 quadrillion
Btu in 2020.
In 2020, the use of renewable energy was projected in
the CEF analysis to be 11 percent higher and 27 percent higher
in the moderate and advanced cases, respectively, than in the business-as-usual
case. In the advanced case, renewable generation was encouraged by policies
such as a renewable portfolio standard, a carbon fee of $50 per metric
ton carbon equivalent, and a proposed extension of the production tax
credit, which was applied only to wind and biomass in the moderate case,
to all nonhydropower renewables. In both cases, CEF projected
lower fossil fuel consumption and fewer nuclear power retirements. In CEF, natural gas consumption was projected to be lower in both
cases than in the business-as-usual case and did not increase in the
advanced case compared to the moderate case despite a sharp reduction
in coal use, due to the greater use of renewables and nuclear power
and projected efficiency improvements that reduce overall energy consumption.
In percentage terms, the projected reductions in CO2
emissions that occurred in the CEF cases were greater than the reductions
in energy consumption due to the shifts to less carbon-intensive fuels. In
the moderate case, projected CO2 emissions were 5 percent and 9
percent lower in 2010 and 2020, respectively, than in the business-as-usual
case. However, emissions remained significantly higher than recent historical
levels. Projected CO2 emissions were reduced by 17 percent and
30 percent in 2010 and 2020, respectively, in the advanced case, compared
to the business-as-usual case. In 2010, CO2 emissions were projected
to reach 1,463 million metric tons carbon equivalent in the advanced case,
which is less than the 1997 level (estimated at 1,480 million metric tons
carbon equivalent in CEF and now estimated at 1,493 million metric
tons carbon equivalent in the U.S. Carbon Dioxide Emissions from Energy
Sources: 2000 Flash Estimate16).
By 2020 in the advanced case, CEF projected that CO2 emissions
would decline further to 1,347 million metric tons carbon equivalent, essentially
the same as the level of 1,349 million metric tons carbon equivalent estimated
for 1990.
Particularly in the advanced case, the largest reductions
in CO2 emissions, in percentage terms, occurred in the residential
and commercial sectors due to increased energy efficiency and the use
of less carbon-intensive fuels to generate the electricity used in those
sectors. As noted above, however, the application of lower hurdle rates
in the CEF analysis implicitly assumed changes in consumer buying
practices that are unsupported by history. The transportation sector
had the smallest percentage reductions in CO2 emissions.
Although efficiencies were assumed to improve for all modes of transportation,
the transportation sector has limited ability to shift from its almost
exclusive reliance on petroleum to other, less carbon-intensive fuels.
Comparing the advanced case to the moderate case, the additional reductions
in CO2 emissions were largely due to policies in the advanced
case that promoted less electricity generation from coal and more from
natural gas, renewables, and nuclear power, including the CO2
trading program, which increased prices for fossil fuels and for electricity
delivered to customers.
Representing the CEF Policies in NEMS
The request for this analysis to EIA specified that two cases
be analyzed “assuming the moderate [advanced] supply and demand-side
policy case of the Clean Energy Futures study.” As noted earlier, however, CEF was based on the AEO99 version of NEMS, and there have been
significant changes to the model and to the assumptions for AEO2000 and particularly AEO2001. Consequently, directly using the energy demands
or the energy demand changes that occurred in CEF is not appropriate
for this analysis.
One of the most significant changes between AEO99 and AEO2001 is the assumed rate of economic growth. In AEO99,
the U.S. economy was projected to grow at an average annual rate of
2.0 percent between 1999 and 2020; however, the growth rate in AEO2001 is projected to be 3.0 percent. Part of the upward revision to the growth
rate that occurred in AEO2001 is due to statistical and definitional
changes in the National Income and Product Accounts; however, the projection
also reflects a more optimistic view of long-run economic growth. The
more rapid projected growth in GDP affects the projected growth in other
key economic drivers—for example: commercial floorspace growth,
1.3 percent per year in AEO2001 vs. 0.8 percent per year in AEO99;
industrial gross output growth, 2.6 percent per year vs. 1.9 percent
per year; and real disposable personal income growth, 3.0 percent per
year vs. 2.3 percent per year.
In general, more rapid projected economic growth leads
to increased demand for energy services and more energy consumption.
In addition, the growth rate for electricity demand is reevaluated in AEO2001, particularly for computers, office and other electrical
equipment and appliances, and miscellaneous energy uses, in accordance
with recent trends. Electricity demand is projected to increase at an
average annual rate of 1.8 percent between 1999 and 2020 in AEO2001,
compared with an average of 1.4 percent projected in AEO99. In
part due to higher economic growth but also as the result of a reestimation
of projected light-duty vehicle travel, travel in AEO2001 increases
at an average annual rate of 1.9 percent from 1999 through 2020, as
compared with 1.7 percent in AEO99. Overall, total energy consumption
in AEO2001 is projected to increase at an average annual rate
of 1.3 percent from 1999 to 2020, as compared with an average annual
rate of 1.0 percent in AEO99.
Partly offsetting the higher projected economic growth
in AEO2001 is more rapid improvement in energy intensity. In
the commercial sector, the effects of Executive Order 13123, signed
by President Clinton in June 1999, mandating reduced energy use in Federal
facilities, and a new fluorescent ballast standard promulgated in September
2000 mitigate some of the previously expected growth in energy consumption.
Improvements in industrial energy intensity are reevaluated in AEO2001.
As a result, primary energy consumption per dollar of output in the
industrial sector is projected to decrease at an average annual rate
of 1.5 percent in AEO2001, compared with 1.1 percent in AEO99.
Primary energy intensity of the U.S. economy is projected to decline
at an average annual rate of 1.6 percent in AEO2001, compared
with 1.0 percent in AEO99. On the other hand, starting with AEO2001,
the size of new houses is projected to increase over time, in accordance
with recent trends, which tends to increase the energy intensity of
households. In 2020, the average home is 2 percent larger in the AEO2001 projections than in AEO99.
Energy price projections have also been revised between AEO99 and AEO2001. The most significant change is for
natural gas prices. Converting the energy prices in AEO99 to
1999 dollars as reported in AEO2001, projected natural gas wellhead
prices in 2020 are higher by 13 percent in AEO2001 and 12 percent
in this study, in part due to higher projected demand for natural gas
in AEO2001. Partly due to higher projected natural gas prices,
the average delivered electricity price in 2020 is projected to be 3
percent higher in AEO2001 than in AEO99. These price changes
affect the economics of technology adoption and penetration. Projected
world oil prices and minemouth coal prices in 2020 in AEO2001 are similar to those in AEO99.
Other assumption changes also affect technology adoption.
As an example, in the transportation demand module of NEMS, the assumed
incremental cost of a hybrid electric vehicle relative to a conventional
vehicle has been reduced from $13,600 in AEO99 to $8,500 in AEO2001.
The introduction date has also been advanced from 2003 to 2000, reflecting
the commercialization of these vehicles.
Overall, these revisions to the reference case projections
indicate that the demand impacts of improved technology assumptions,
as reflected in CEF and based on AEO99, could not simply
be applied to the AEO2001 projections for the purposes of this
analysis.
In some cases, the CEF policies overlap with or
have been overtaken by changes that have occurred over time or within
NEMS. For example, some policies were expected in the CEF analysis
to be instituted in 2000 or 2001, which is no longer plausible. Also,
residential equipment standards proposed in CEF are modified
in this analysis to account for the standards announced in January 2001,
as later modified by the Bush Administration. The January 2001 standards
included a 13 SEER (seasonal energy efficiency ratio, calculated as
Btu of output per watthour of input) for central air conditioners and
heat pumps, which was revised by the current administration to 12 SEER,
as assumed in this analysis. The revision is being challenged in court,
and a final rulemaking is expected in early 2002.
Modeling enhancements have also been made to NEMS since
the AEO99 version, and several have a significant impact on the
results. A few of the more significant examples are noted below:
- The representation of industrial and commercial cogeneration has been
enhanced to include an explicit evaluation of the costs and performance
of various cogeneration technologies.17 In addition, a representation of distributed generation has been added to
the electricity generation, residential, and commercial modules. Both economically
based and program-driven installations are represented, as well as the projected
effects on purchased electricity in the residential and commercial sectors
and, for cogeneration, on fuel to meet space heating and water heating demand.
- In the residential module, the building shell methodology, which
had been based in AEO99 on an assumption of the improvement
in new buildings over time, has been replaced by an explicit evaluation
of the costs of various shell efficiency levels integrated with
the choice of heating and air-conditioning equipment. As a result,
policies aimed at improving residential shell efficiency cannot
be addressed in the same fashion as in the AEO99 version
of NEMS.
- In the transportation module, light-duty vehicles are now
represented by 20 rather than 10 vintages. The methodology
for vehicle choice in AEO2001 competes alternative-fueled
and advanced technology vehicles directly with conventional vehicles.
In AEO99, a generic alternative technology competed with
conventional vehicles. Also, hybrid electric vehicles are no longer
considered to be an advanced technology but, rather, another conventional
technology.
- AEO2001 includes a redesigned component for geothermal
electricity generation with a methodology more similar to those
of the other renewable technologies, providing a comparable evaluation
of the potential penetration of geothermal energy relative to the
other technologies.
- Two modifications have been made in the electricity generation
sector of NEMS since AEO99 that tend to reduce the economic
retirements of existing power plants. First, expectations of electricity
demand growth, which are used internally to determine the requirements
for new generation capacity, tended to be too high. This resulted
in higher reserve margins and capacity additions. The methodology
has been revised so that the initial electricity demand expectations
used for capacity expansion are more in line with resulting forecasted
demands. Also, projected capital costs for new capacity in AEO2001 are generally higher for fossil-fired units than in AEO99,
particularly for natural-gas-fired plants, which are 30 to 50 percent
more costly, reducing retirements because the cost of replacing
existing plants has increased.
In order to represent the CEF programs within
NEMS for this study, each policy and its implementation in CEF were examined. Where possible, policies are explicitly represented,
such as tax credits and efficiency standards. Many policies in CEF,
including research and development and voluntary programs, were analyzed
separately by the CEF analysts, and the results were introduced
into CEF-NEMS through changes in parameters and assumptions,
such as technology costs and performance and hurdle rates. For this
study, EIA analysts generally implemented the same changes, on a percentage
basis, into the current version of NEMS. Where CEF policies
are date-dependent, due to the passage of time, as noted above, they
are adjusted for the year of implementation, which has an impact on
the level of penetration. The specific implementation of the CEF policies is discussed in Chapter 3.
As requested by Senators Jeffords and Lieberman, the
overall goal of the EIA implementation of CEF policies is to
emulate the analysis originally performed by the CEF analysts,
while adjusting for the model enhancements and updated assumptions
in AEO2001. In addition, the analysis is adjusted for any changes
in energy programs and policies that have occurred since the CEF analysis. Therefore, although actual demand projections and demand
reductions in the EIA analysis due to CEF policies may not
match those in the published CEF analysis, the EIA analysis
captures the essence of an updated CEF analysis.
Notes and Sources |
