1. Background and Methodology
Introduction
Over the next decade, U.S. electric power plant operators may
face significant requirements to reduce emissions of sulfur dioxide (SO2)
and nitrogen oxides (NOx) beyond the levels called for in the Clean
Air Act Amendments of 1990 (CAAA90). They could also face requirements to
reduce carbon dioxide (CO2) and mercury (Hg) emissions. At present
neither the future reduction requirement nor the timetable is known for any
of these airborne emissions; thus, compliance planning is difficult.
Currently, different environmental issues are being addressed
through separate regulatory programs, many of which are undergoing modification.
To control acidification, the CAAA90 required operators of electric power
plants to reduce emissions of SO2 and NOx. Phase II
of the SO2 reduction programreducing allowable SO2
emissions to an annual national cap of 8.95 million tonsbecame 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 these 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 that lead to 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 emitted
directly from electric power plants and are also associated with power plant
emissions of NOx and SO2. Thus, 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; proposed regulations are to be finalized by 2004. Further,
if the United States decides to reduce its emissions of greenhouse gases,
energy-related CO2 emissions may have to be reduced as part of
that program.
Analysis Request
In both the previous and current Congresses, legislation has
been proposed that would require simultaneous reductions of multiple emissions.1 This analysis responds to a request from Senators Smith, Voinovich, and Brownback
to examine the costs of specific multi-emission reduction strategies (see
Appendix A for the requesting letter). In their request, Senators Smith, Voinovich,
and Brownback asked the Energy Information Administration (EIA) to analyze
the impacts of three scenarios with alternative power sector emission caps
on NOx, SO2 and Hg. They also asked for an analysis
of the potential costs of requiring power suppliers to acquire offsets for
any increase in CO2 emissions that occur beyond the level expected
in 2008.
Specifically, EIA was asked to analyze the following three
scenarios for reducing power sector emissions:
- Scenario 1: Reduce NOx emissions by 75 percent below
1997 levels, SO2 emissions by 75 percent below full implementation
of Title IV of the CAAA90, and Hg emissions by 75 percent below 1999 levels
by 2012, with half the reductions for each of the emissions occurring by
2007.
- Scenario 2: Reduce NOx emissions by 65 percent below
1997 levels, SO2 emissions 65 percent below full implementation
of Title IV of the CAAA90, and Hg emissions by 65 percent below 1999 levels
by 2012, with half the reductions occurring by 2007.
- Scenario 3: Reduce NOx emissions by 50 percent below
1997 levels, SO2 emissions by 50 percent below full implementation
of Title IV of the CAAA90, and Hg emissions by 50 percent below 1999 levels
by 2012, with half the reductions occurring by 2007.
The emission reduction programs are assumed to cover all electricity
generators other than industrial cogenerators,2 and to operate as cap and trade programs patterned after the SO2
control program created in the CAAA90. It was requested that the analysis
should assume that the programs would begin in 2002, achieving half the required
reductions by 2007 and full compliance by 2012. At the request of the Senators
the existing summer season NOx cap and trade program is assumed
to be replaced by the annual programs established in each of the cases.
For Hg, half of the required reductions were to come from
actual reductions at each unit; the rest could be achieved through allowance
trading among units. In all cases, power suppliers would be able to bank
emissions for future use. In other words, power suppliers could choose to
reduce their emissions below the number of allowances they have in some
years and hold (bank) them for use in other years. Typically a power supplier
would be expected to do this in the early phase of the emission reduction
programs, when relatively inexpensive compliance options are available,
so that they could minimize the amount of reduction they might have to make
or the number of allowances they might have to buy in the later phases,
when compliance might be more expensive.
This analysis examines the steps that power suppliers might
take to meet the specified caps on NOx, SO2, and Hg
emissions with and without CO2 emissions capped at the 2008 reference
case level. The potential benefits of reduced emissionssuch as might
be associated with reduced health care costsare not addressed, because
EIA does not have expertise in this area.3 The specific design of the casestiming, emission cap levels, policy
instruments usedis important and should be kept in mind when the results
are reviewed.
This study is not intended to be an analysis of any of the
specific congressional bills that have been proposed in this area, 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 emission caps studied in this analysis, and several
would use different policy instruments to meet the emission targets. Moreover,
some of the actions projected to be taken to meet the emission caps in this
analysis may eventually be required as a result of ongoing environmental
programs whose requirements currently are not fully specified.
Representation
in the National Energy Modeling System
Each of the cases analyzed was prepared using EIAs
National Energy Modeling System (NEMS). NEMS is a computer-based, energy-economic
model of the U.S. energy system for the mid-term forecast horizon, through
2020. NEMS projects production, imports, conversion, consumption, and prices
of energy, subject to assumptions about 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. Using econometric, heuristic, and linear programming techniques,
NEMS consists of 13 submodules that represent the demand (residential, commercial,
industrial, and transportation sectors), supply (coal, renewables, domestic
oil and natural gas supply, natural gas transmission and distribution, and
international oil), and conversion (refinery and electricity sectors) of
energy, together with a macroeconomic module that links energy prices to
economic activity. An integrating module controls the flow of information
among the submodules, from which it receives the supply, price, and quantity
demanded for each fuel until convergence is achieved.
Domestic energy markets are modeled by representing the economic
decisionmaking involved in the production, conversion, and consumption of
energy products. For most sectors, NEMS includes explicit representation of
energy technologies and their characteristics (Table 1). In each sector of NEMS, economic agentsfor example, representative households
in the residential demand sector and producers in the industrial sector
are assumed to evaluate the cost and performance of various energy-consuming
technologies when making their investment and utilization decisions. The costs
of making capital and operating changes to comply with laws and regulations
governing power plant and other emissions are included in the decisionmaking
process.
The rich detail in NEMS makes it useful for evaluating various
energy policy options. Policies aimed at a particular sector of the energy
market often have collateral effects on other areas that can be important,
and the detail of NEMS makes the analysis of such impacts possible. For example,
a policy that leads to higher prices for a particular fuel would be expected
to cause residential, commercial, industrial, and transportation customers
to reduce their consumption of that fuel by shifting to other fuels and/or
investing in more efficient energy-using equipment. NEMS explicitly represents
these choices by consumers.4
NEMS represents numerous options for reducing power sector
emissions of NOx, SO2, and Hg. Technological options
include installing combustion controls, selective noncatalytic reduction equipment
(SNCR), or selective catalytic reduction equipment (SCR) to reduce NOx;
flue gas desulfurization equipment to reduce SO2; and activated
carbon injection equipment with or without a supplemental fabric filter or
spray cooler to reduce Hg. With respect to Hg and, to a lesser extent, NOx
there is some uncertainty about the cost and performance of these technologies (see discussion on Reducing NOx and Hg
Emissions"). NEMS can also choose to switch fuels or retire plants
and replace them with new plants using different technologies or fuels. Finally,
NEMS allows consumers to choose to reduce their electricity consumption if
electricity prices rise when emission caps are imposed.
Reference
Case
The reference case for this analysis is based on the reference
case for EIAs Annual Energy Outlook 2001 (AEO2001). As
a result, it incorporates the laws and regulations that were in place as of
the end of July 2000. It includes the CAAA90 SO2 emission cap and
NOx boiler standards. It also includes the 19-State summer season
NOx emission cap programreferred to as the State Implementation
Plan (SIP) Call.5 The settlement agreement between the Tampa Electric Company and the U.S. Department
of Justice (acting for the EPA) requiring the addition of emissions control
equipment at the Big Bend power plant and the conversion of the F.J. Gannon
plant to natural gas was also incorporated in the AEO2001 reference
case. Rules and regulations that have not been fully promulgated are not included
in the reference case (see discussion on
"Respresentation of New Environmental Rules and Regulations").
Because of the recent agreements between the EPA and Cinergy
and Virginia Power with respect to the New Source Review (NSR) compliance
action, the AEO2001 reference case has been modified for this study
to incorporate the emissions control equipment that those companies have
announced they will add. However, these actions could change as a result
of the remaining NSR cases. The historical data used for this analysis were
also updated to reflect more recent information on natural gas prices, electricity
sales, and generating capability additions in 2000 that were not available
when the AEO2001 reference case was prepared. In addition, natural
gas prices and electricity demands have been recalibrated to EIAs
July 2001 Short-Term Energy Outlook (STEO). This recalibration
resulted in higher gas prices and electricity demand than those used in
the AEO2001.
Analysis
Cases
As requested by the Senators, the emission reduction programs
are assumed to be patterned after the SO2 emissions trading program
created in the CAAA90. In other words, emissions allowances totaling to the
specified limit for each emission are assumed to be allocated at no cost to
power suppliers. Power suppliers are free to reduce their emissions to the
level of allowances they hold or to purchase additional allowances from others
who take action to reduce their emissions below the number of allowances they
have. Power suppliers are assumed to behave competitively, incorporating the
costs6 of holding
allowances in the operating costs of plants that produce the targeted emissions.
Assuming that efficient competitive allowance markets develop, the market
price of allowances that evolves should provide both power producers and consumers
with the information needed to minimize the costs of reducing the targeted
emissions.
It is important to note that there are numerous policy instruments
available for reducing emissions. They include 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
costs of compliance.7 In competitive markets, electricity prices will reflect the change in variable
operating costs of plants setting market prices brought about by emission
reduction efforts. On the other hand, in cost-of-service markets, all generation
costsincluding the total costs of reducing emissionswill be reflected
in the prices that consumers pay for electricity.
Table 2 and Figures
1, 2, and 3 show the emission targets in each of the three cases prepared50-Percent,
65-Percent and 75-Percent Reduction cases. In each case it is assumed that
half the required reduction must occur by 2007, and that full compliance is
required by 2012. Thus, the emission limits in 2007 are set to the mid-point
between the base level and the emission target level shown for each case in
Table 2. In 2012 and beyond, the emission caps are set to the levels shown
in Table 2.
At the request of the Senators, an additional requirement is
imposed for Hg: one-half of the required reductions in each case must come
from reductions at each facility, and the other half can be accomplished through
trading with other facilities that have allowances to sell. To represent this
requirement an estimate was made of the minimum percentage Hg removal (from
the amount of Hg in the coal used) required from all units to achieve half
the overall required reduction by 2007. For example, in the 65-Percent Reduction
case, 28 tons of reduction (43 - 15) is required. It was estimated
that if all units were required to add equipment that allowed them to achieve
a minimum 55 percent removal rate (units that already removed more than 55
percent were not required to make any additional investment), approximately
half the 28 tons of total reductions required would be achieved. The same
procedures were used in the 50- and 75-Percent Reduction cases, but the minimum
removal rates were 50 percent and 60 percent, respectively.
Power sector banking decisions were simulated by setting the
emissions caps slightly below those called for in the early years of the programs
and slightly higher in the later years. In all cases, it is assumed that emissions
will reach the final target caps by 2020.8
In addition, for each of the three analysis cases an estimate
is provided of the cost of purchasing carbon offsets for increases in CO2
emissions beyond the 2008 level projected in the reference case. NEMS represents
only U.S. energy markets and can only provide cost estimates for reducing
emissions in the U.S. energy sector. Lower cost carbon reduction opportunities
that might be available in other countries and/or outside the energy sector
(inside and outside the United States) are not represented in NEMS.
To estimate the potential price that U.S. power suppliers might
be willing to pay for carbon offsets, each of the three analysis cases was
rerun with CO2 emissions capped at the reference case 2008 level.
The resulting CO2 allowance price, which represents the projected
maximum price U.S. power suppliers would be willing to pay, was then compared
with an estimate of the international price for carbon offsets from world
energy markets. This estimate was developed using carbon reduction (abatement)
curves from the Pacific Northwest Laboratory Second Generation Model (SGM),
matched against the quantity of offsets projected to be needed in each of
the analysis cases,9 to provide a rough estimate of the costs power suppliers would incur to purchase
the offsets they would require in each case. No explicit reductions in U.S.
power sector CO2 emissions were modeled. It is likely that the
U.S. power sector would have some relatively inexpensive options available.
Notes
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