Analysis of Multi-Emissions Proposals for the U.S. Electricity Sector

Analysis of Multi-Emissions Proposals for the U.S. Electricity Sector
Requested by Senators Smith, Voinovich, and Brownback
Prepared by: U.S. Environmental Protection Agency

This analysis provides the Environmental Protection Agency's response to a June 8, 2001 letter
to EPA Administrator Whitman from Senators Smith, Voinovich, and Brownback. The letter
requested that EPA analyze the environmental and economic impacts of several different policy
options related to multi-emissions control strategies in the nation's electricity sector.

1. Executive Summary

This section briefly outlines the scenarios, methods, and results, first presenting the multi-
emissions analysis followed by the greenhouse gas (GHG) analysis.

1.1. Policy Scenarios

The Senators requested that EPA conduct two related analyses. The first analysis focuses on the
cost of reducing emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), and mercury (Hg)
from the electricity sector, under three scenarios of varying stringency. According to the request,
these reductions would be phased in over time. Emissions allowance caps representing half the
required reductions would be implemented in 2007 with caps representing the full reductions
implemented in 2012. However, banking of emissions allowances would begin in 2002. The
analysis assumes a cap-and-trade program for both SO2 and NOx in a manner consistent with the
existing SO2 trading program under Title IV of the Clean Air Act. Cap-and-trade for mercury
emissions is limited in the analysis, such that half of the mercury reductions are available for
trading and half of the reductions in each compliance period represent facility-specific
reductions.

The second analysis examines greenhouse gas reductions and the additional costs of offsetting
carbon dioxide (CO2) emissions growth over 2008 levels in the U.S. electricity sector. The
Senators requested that the analysis allow the emissions growth to be offset by carbon
sequestration or reductions from any greenhouse gas from any source anywhere in the world. In
conducting this analysis, EPA considers the possible limits on offset availability as a result of
institutional barriers, transaction costs, and/or demand for GHG offsets from other countries.

1.2. Three-Pollutant Analysis

The analysis of the three multi-emission policy scenarios estimates the electricity sector's costs
of production, compliance choices, fuel use, plant dispatch, emissions, new capacity, and
wholesale electricity prices. To accomplish this, EPA used the IPM® model, an integrated
planning model that EPA has also used in rulemakings affecting the electricity sector.

The actual emissions reductions under the three scenarios for 2020 are significantly less than the
targeted reductions because of the substantial availability of banked allowances for withdrawal.
For example, under Scenario 1 (75% reductions), the actual emissions reductions in 2020 are

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only 59% for SO2, 60% for NOx, and 63% for mercury. Likewise, under Scenario 2 (65%
reductions), the actual reductions in 2020 are 52% for SO2, 51% for NOx, and 54% for mercury.
EPA estimates that the annual cost to the electricity sector of complying with the 3-pollutant
scenarios in 2020 varies between 3.1 and 6.9 billion dollars ($1999). The cost of complying with
Scenario 3 (50% reductions) is the lowest and Scenario 1 (75% reductions) is the highest. Costs
for Scenario 2 (65% reductions) fall between this range at 4.8 billion dollars in 2020.

The predominant compliance strategy for reducing emissions in 2012 and later is a combination
of selective catalytic reduction (SCR) and flue gas scrubbers. In addition to investments in
emission control technologies, the modeled power plants are expected to modify their operations.
Some of the changes in power plant operations result in an increase in natural gas use of 4.4% to
7.3%) and a decrease in projected coal use by 3.4% to 6.2%, relative to the Base Case, by 2020.
However, coal use for electricity generation remains above 1999 levels under all three scenarios.

The model predicts that a portion of the costs borne by electricity generators in reducing the
three pollutants would lead to an increase in wholesale electricity prices of between 1.9% and
2.4%. The effective impact on the retail price is expected to be lower because the wholesale
price is only one component of the retail price.

1.3. Greenhouse Gas (GHG) Analysis

EPA analyzed the emissions reductions and additional cost of offsetting U.S. electricity sector
CO2 emissions growth after 2008. EPA's analyses project CO2 emissions under Scenario 2 of the
3-emission analysis (65 percent reductions) using two alternative baseline forecasts: one using
the IPM® and the other by the Energy Information Administration (EIA). The two baselines
provide varying results: the IPM analysis requires offsets of six and 58 MMTCE in 2010 and
2020, respectively; while the EIA analysis requires zero offsets in 2010 and 75 MMTCE in 2020.
To put these quantities in context, the required offsets represent approximately one percent of
U.S. electricity sector CO2 emissions in 2010, and approximately nine percent by 2020.

The results would likely vary for Scenario 1 and Scenario 3, which have different reduction
requirements for SO2, NOx, and mercury. Actions taken to reduce emissions of these gases have
the additional effect of reducing CO2 emissions. CO2 growth slows more under stringent controls
for the other gases, meaning that fewer offsets are needed. The multi-emission controls (75%
reductions of SO2, NOx, and Hg) in Scenario 1 would lead to slightly reduced requirements for
offsets, while Scenario 3 (50% reductions in of SO2, NOx, and Hg) would likely mean slightly
higher CO2 emissions, and, therefore, a greater requirement for offsets.

To estimate the cost of GHG offsets, EPA used several global-scale economic models including
the Second Generation Model (a widely used general equilibrium model) and economic analyses
for sinks and non-CC>2 gases. EPA also conducted a number of alternative sensitivity analyses to
account for varying program effectiveness and to reflect different levels of international demand
for GHG offsets based on possible implementation of the Kyoto Protocol by the countries that
reached agreement in Bonn.

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In most cases, EPA estimates that abatement costs of a GHG offset program would be negligible
through 2020. For these cases, the allowance price associated with the offset program would be
equal to the transactions costs of securing the offsets. Estimates of transactions costs, which
include private deal-making activities, and government program costs, have not been calculated
because of a lack of adequate data. For these cases, only when offset availability is limited to
3% in 2010 or 24% in 2020 do higher allowance prices appear.

EPA also examined cases in which other countries comply with the Kyoto Protocol. With the
implementation of the Kyoto Protocol agreement reached in Bonn, there is likely to be no change
in U.S. allowance prices or abatement costs through 2010. However, by 2020, U.S. allowance
prices could rise to $1-9 (plus transactions costs) per ton of carbon equivalent, and total annual
abatement costs in the U.S. could range from negligible to $190 million. EPA has also
considered possible cases in which allowance prices could be higher. For example,
implementation of the Kyoto Protocol agreement coupled with significant allowance banking in
the former Soviet Union and Eastern Europe could raise offset prices to $17 (plus transactions
costs) per ton and abatement costs to nearly $500 million by 2020.

Several factors contribute to low abatement costs. First, the Senators requested that the EPA
analyze only modest GHG emissions reductions, requiring offsets only in the U.S. electricity
sector and only after 2008. Second, the Senators' provision that verifiable GHG reductions or
sinks be available anywhere in the global market affords abundant low-cost mitigation
opportunities. Limiting the source categories that provide offset credits, either geographically or
by type, higher demand for GHG offsets worldwide, or institutional barriers that limit the
availability of offsets would raise allowance prices and abatement costs.

The results provided in this analysis should not be construed as forecasts of actual scenario
outcomes. The results are assessments of how the future might unfold using a number of well-
established economic and emissions analytical modeling tools. The models provide useful
insights about the interaction and interrelationships between policy options and resulting
environmental and economic outcomes. All models have certain simplifying assumptions, and,
though the models produce credible results and have been reviewed by government and private
sector experts, they can only be interpreted as representing "reasoned estimates" of the potential
outcomes.

1.4. Organization of Document

The remainder of this document presents a detailed explanation of the approach EPA used to
obtain these results as well as an elaboration of the results. Section 2 describes the multi-
emissions analysis in greater depth. Section 3 provides more information on the approach and
results of the GHG offsets analysis. These sections are followed by an Appendix that presents
more information on the models and data used in both analyses, as well as a list of references.

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2. Multi-Emissions Analysis

This section describes in more detail the multi-emissions scenarios, EPA's analytical
methodology, and the results of the Agency's analysis. Note that details about the model used in
the analysis can be found in the Appendix.

2.1. Summary of Three Scenarios

The following section describes the important provisions of the multi-emissions scenarios
elaborated in the letter from Senators Smith, Voinovich, and Brownback.

• The multi-emissions policies include three scenarios that simultaneously reduce NOx, SO2,
and mercury emissions from the electricity sector. The three scenarios are similar in program
structure, but vary in levels of reduction expected from each of the three pollutants, as shown
in Table 1.

Table 1. Emission Scenario Specifications

I-" 111 issiiui

Tr;i(lin;im-

so2

Yes

2002

2007

Title IV

37.5%

32.5%

25%

2012

75%

65%

50%

NOx

Yes

2002

2007

1997 Level

37.5%

32.5%

25%

2012

75%

65%

50%

Hg:
National

Yes

2002

2007

1999 Level

37.5%

32.5%

25%

2012

75%

65%

50%

Hg: Plant-
Specific

No
Banking

2007

1999 Level

18.75%

16.25%

12.5%

2012

37.5%

32.5%

25%

• As described in the letter, each of the three scenarios allows for full trading for NOx and SO2,
and partial trading for mercury. In addition, banking of emissions allowances begins in
2002, with the first half of reductions required by 2007 (reductions of 37.5%, 32.5%, and
25% respectively for the three scenarios) and full reductions by 2012 (reductions of 75%,
65%), and 50%>). For mercury, the scenarios require that half of the reductions made in each
of the compliance periods be at the facility level.

• For SO2, the percentage reductions are from the 1990 Clean Air Act Amendments (CAAA)
Title IV levels. For NOx, the percentage reductions are from the 1997 annual NOx emissions
levels. For mercury, the percentage reductions are from the 1999 levels.

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2.2. Methodology

EPA used ICF's Integrated Planning Model (IPM) to model the impacts of the multi-emissions
scenarios on electricity sector costs and emissions. IPM® is a dynamic linear programming
model that develops least-cost capacity expansion plans while meeting various power market and
environmental constraints. This model has been used to support numerous rulemakings that the
Agency has undertaken to address emissions from the electricity sector. (See the Appendix for
further detail.)

The Agency modeled as closely as possible the provisions indicated in the letter. However,
several changes were made to conform to the capabilities and structure of the IPM® modeling
framework. Further, certain assumptions related to the definition of the affected units and the
spatial scope of this analysis were not specified in the letter and hence were made by the Agency.
This section describes the important provisions of the EPA analysis.

• To estimate the impacts of the policies proposed in the three three-pollutant scenarios, EPA
ran a Base Case as part of this analysis (i.e., existing requirements without the proposed
multi-emissions scenarios). This Base Case incorporated Title IV requirements for SO2 and
NOx, as well as the summer regional SIP call NOx program. The Base Case did not include
possible future regulations, such as mercury MACT (maximum achievable control
technology) standards or state plans to achieve the fine particle ambient air quality standards.
The differences (in costs and operations) between each scenario and the Base Case — which
is consistent for all scenarios — represent the impact of that policy. Thus, the costs of the
policies shown in this analysis do not include the costs of these existing programs. Note also
that the expected summertime reductions accomplished due to the SIP call program were not
available for banking in the three-pollutant scenarios. The possible implications of such an
assumption are discussed in Section 2.3.

• The costs presented in this analysis assume that a trading program is available for SO2, NOx
and mercury within the U.S. electricity sector. EPA expects that the model will accurately
anticipate the compliance decisions by sources, provided that an efficient cap-and-trade
system is available to those sources subject to the environmental constraints. Based on the
experience implementing the existing SO2 and NOx cap-and-trade programs, EPA believes
that a relatively efficient market can develop for each of these three pollutants.

• The analysis examines the impacts of annual nationwide caps on emissions of NOx, SO2, and
mercury that are consistent with the specifications described in the letter. The caps on
emissions in the analysis are placed on fossil fuel-fired electric generating units for NOx and
SO2, and all large coal-fired boilers for mercury. Units in the continental United States that
are connected to the electric grid are included in this analysis.1

• Consistent with the request, EPA modeled all three scenarios with half of the reductions
going into effect starting in 2007 and full reductions starting in 2012. In addition, banking is
allowed starting in 2002.

• The request based the required NOx reductions on the 1997 emissions level, the mercury

1 Virtually all of the large units are connected to the grid.

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reductions on the 1999 level, and the SO2 reductions on the CAAA Title IV caps. EPA
assumed that the electricity sector emitted 6.04 million tons of NOx in 1997 and 48 tons of
mercury in 1999.2 The SO2 emissions under the Hill implementation of Title IV of the
CAAA are assumed to result in 8.95 million tons.

• The request requires that each affected plant achieve at least half of their expected mercury
reductions in any given year at the plant site. The amount of actual reductions is based on
their actual mercury emissions in 1999. EPA modeled the individual plant-level mercury
caps at half of their expected reductions based on the individual plant mercury emissions in
the Base Case in 2005.3

• EPA ran IPM® for four representative years with at least one snapshot for each distinctly
different regulatory period. The years 2005, 2007, 2012, and 2020 represent the pre-cap
period when banking is allowed, the partial cap period, the beginning of the fully
implemented caps, and the out-year in which the bank is being depleted, respectively.

2.3. Multi-Emissions Results

IPM®-based analysis provides forecasts of the impacts of the three emission reduction scenarios
on the electricity sector's emissions, costs of production, compliance choices, fuel use, plant
dispatch, new construction, and wholesale energy prices. The primary results from EPA's
analysis are summarized below.

2.3.1. Emission Impacts

All three scenarios entail progressive reductions in SO2, NOx, and mercury, as well as the
banking of allowances starting in 2002. While banking provides flexibility in complying with
the specified emission targets and reduces compliance costs, the emission targets may not be met
exactly in a given year. This results from sources either reducing emissions beyond what is
required (in order to bank allowances) or reducing emissions less than is required (by
withdrawing allowances from the bank)4

Figures 1 through 4 show the projections of SO2, NOx, mercury, and CO2 in the different
scenarios for four representative years. Emissions of SO2, NOx, and mercury generally decrease
over time for all three scenarios. The more stringent the scenario, the lower the emissions. Note
that the CO2 emissions decrease in the three-pollutant scenarios relative to the Base Case despite
the fact that CO2 is uncontrolled.5 This occurs because natural gas use increases somewhat with
the percentage reduction required.

2 The base level for NOx is 1997 emissions from all Title IV affected units. The mercury emission level in 1999
was based on the EPA's recent Information Collection Request on mercury.

3 EPA modeled the plant level mercury reductions at the IPM® model plant level. IPM® model plants are
aggregations of individual boilers with similar characteristics.

4 Allowances in a given year are banked for withdrawal in future years if the present value of the price of the
allowances in the future years is higher than the current price of allowances. The banking of allowances
continues until the current price of allowances equals the present value of the allowances in the future years.

5 The projected decline in CO2 emissions reflects the operating penalty associated with increased use of scrubbers
but not SCR, as described in Table A. 1.3. The conservative estimate scrubbers (2.1% capacity penalty) is

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Figure 1. NOx Emissions (million tons)

Figure 2. S02 Emissions (million tons)

The analysis estimates that banked NOx and mercury allowances would be withdrawn starting in
2012.6 Banked SO2 allowances would be withdrawn starting in 2007. Banking occurs when the
marginal cost of reducing emissions in a given year is lower than the marginal cost of reducing
emissions in a future year, adjusted for the time value of money. The model — as well as
experience — show that power plants would over-control in the early years and under-control in
the later years in order to minimize compliance costs over the period of the analysis.

Figures 5, 6, and 7 show the actual reductions of the three pollutants relative to their respective
caps. The actual reductions under the three scenarios are significantly less than the targeted
reductions for 2020 because of the substantial use of banked allowances.

assumed to overcompensate for the minimal penalty arising from SCR.

6 This analysis used the Base Case level of 43.14 tons to calculate banking of mercury allowances during the 2002-
2006 period. Alternatively, if the mercury cap was maintained at the 1999 level of 48 tons, increased banking
opportunities would have reduced the overall cost of the program. However, this would have increased the
effective mercury emissions in later years due to the greater number of allowances that would have been available
for withdrawal from the bank.

• Base Case —¦—Scenario3 —a—Scenario2 —*—Scenario 1

2,700

2,600

2,500

t/> 2,400

-------
Figure 5. S02 Cap and Projected Emissions under Scenario 1

—«—Scenario 1 502 Emtswoni - -m .Scefiarta f SO? t»p

Figure 6. NOx Cap and Projected Emissions under Scenario 1

- —]

1. ™

——

3002 2005. 300i 2011 2014 501? 2020

Figure 7. Hg Cap and Projected Emissions under Scenario 1

—Sr«r.ano 1 Hg Cmnnor,i S r inario 5 Mg Cap

Note: For NOx and mercury, the "cap" between 2002-2006 is included
for purposes of calculating the size of the respective allowance banks.

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As stated in Section 2.2, this analysis assumed that the SIP call program would be implemented
beginning in 2003. If the SIP call were not implemented in the period 2003-2006, the affected
power plants in the three-pollutant scenarios would have greater opportunities for banking NOx
emission allowances for the future. Based on a simplified analysis, not implementing the SIP
call could increase the NOx bank up to a maximum of 3.75 million allowances. (For comparative
purposes, electricity sector NOx emissions were 6.04 million tons in 1997.) Such an increase in
banked allowances would reduce the overall cost of the policy, but increase the NOx emissions in
the future over what has been shown here. Even without these extra allowances, the NOx
reductions under the three scenarios will probably not achieve emissions levels equivalent to
those required by the NOx SIP call within the 19-state NOx SIP call region until sometime after
2020.

2.3.2. Cost Impacts

The model calculates operation and maintenance costs, fuel costs, and capital investment costs.
The incremental costs for complying with the three-pollutant scenarios over the Base Case are
summarized in Figure 8.

Figure 8. Incremental Cost Impacts under the EPA Analysis (Billions of 1999$)

—~—Scenario 1 Scenario 2 a Scenario 3

The incremental costs exhibited in Figure 8 reflect the range of decisions made by the electricity
sector to comply with the three scenarios. Note that costs are incurred as early as 2005 in all
three scenarios, even though explicit emissions reductions beyond Base Case levels are not yet
required. These costs are incurred to generate early reductions that can be banked for use in
2007 and beyond when the emission limits for SO2, NOx, and mercury come into effect. Costs of
compliance increase with time for at least three reasons: (1) the progressive tightening of the
caps in 2007 (half reductions required) and 2012 (full reductions required); (2) the increase in
demand for electricity over time, resulting in an increase in reduction requirements; and, (3) the
gradual reduction in the banked allowances available for withdrawal necessitating additional
actions to reduce emissions.

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2.3.3. Marginal Costs

The marginal costs of SO2 and N0X reductions through 2020 are less than $l,500/ton in all three
multi-emissions reduction scenarios. The marginal cost of mercury reductions by 2020 ranges
from $5,000 - $10,000/lb. Figures 9, 10 and 11 show the marginal costs for each pollutant.

Figure 9. Projected Marginal Cost of S02 Reductions ($/Ton)

1,400
1,200
1,000

I® 800

w 600

400
200
0

1,263

476

2005

2007 2012

2020

• Scenario 1

¦ Scenario 2

A Scenario 3

Figure 10. Projected Marginal Cost of NOx Reductions ($/Ton)

1,400
1,200
1,000
800

W 600

400
200
0

2005

2007

1,145

2012

2020

"Scenario 1

-Scenario 2

-Scenario 3

Figure 11. Projected Marginal Cost of Mercury Reductions ($/lb)

,000

ooo •

000
000
000
000
000
000
000
000
0

4,36?

k 2.650

3,269

9,234
^

"o,614

_ ^-^610

2005

2007

2012

2020

-Scenarios 1 and 2

¦Scenario 3

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2.3.4. Fuel Use Impacts

SO2 and mercury are fuel-based pollutants, while N0X emissions are generated largely as a result
of the combustion process. Coal-fired power plants emit SO2, NOx, and mercury. Gas-fired
power plants, in contrast, emit NOx, but no mercury and virtually no SO2. Hence, in those
scenarios that call for reductions of SO2, NOx, and mercury, the replacement of coal-fired
generation by gas-fired generation is an effective compliance option. Figure 12 shows the fossil
fuel consumption in 2012 in the Base Case and the three three-pollutant scenarios. As the
emission reduction requirement increases from left to right, coal use decreases slightly and gas
use increases slightly. Under all scenarios, coal consumption is greater than the amount
consumed in 1999.

Figure 12. Fossil Fuel Consumption in 2012 (Trillion Btu)

25,000

20,000

= 15,000
+¦»
m

H 10,000
5,000
0

1 2

B1999 Fuel Consumption dBase Case ¦ Scenario 3 ~ Scenario 2 ~ Scenario 1

2.3.5. Power Plant Generation

As in competitive wholesale power markets, the model dispatches power plants based on their
variable costs, with the lowest variable cost plants dispatched first. In general, coal and nuclear
units have the lowest variable costs followed by combined cycle and oil/gas steam units.
Combustion turbines have the highest variable costs. Because the variable costs of a power plant
include variable operation and maintenance costs, fuel costs, and pollution control costs, these
costs increase as emissions limits are imposed or tightened, resulting in changes in plant
dispatch.

Figure 13 summarizes the generation from power plants by plant type in 2012 for the Base Case
and the three scenarios. In Scenario 3, coal-fired generation in 2012 is 3% lower than in the
Base Case, and in Scenario 1 it is 7% lower than in the Base Case. At the same time, in Scenario
3, combined cycle generation in 2012 is 13% higher than in the Base Case, and in Scenario 1 it is
27% higher than in the Base Case. Nuclear generation remains constant throughout the
scenarios.

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Figure 13. Power Plant Generation in 2012 (Millions of GWh)

Note: 1999 Electric Generation: 3.7 million GWh. Source: EI A

2.3.6. Technology Retrofits

In each scenario, the model forecasts the optimal compliance strategy from an array of options.
SO2 compliance options include dispatch changes, scrubber installation, repowering, and fuel
switching. NOx compliance options include dispatch changes, selective catalytic reduction
(SCR), selective non-catalytic reduction (SNCR), and gas reburning equipment. Mercury
compliance options include fuel switching, dispatch changes, and installation of activated carbon
injection (ACI) controls. The installation of both SO2 scrubbers and NOx SCRs has an additional
co-benefit of reducing mercury emissions. The replacement of coal generation with combined
cycle generation and the early retirement of fossil fuel plants are also available compliance
options for achieving the proposed reductions. As with cos^he optimal strategaUfiT the
electricity sector varies with the level of targeted emissioi^aua^s.

Figure 14 summarizes the optimal retrofit plan forecasted by
three scenarios in 2020. The cumulative investments in
with the tightening of the emission reduction requiremenl
choices are scrubbers for SO? removal: SCR/SNCR fc
and mercury removal. S,
pollutant scenarios, the i

most significant relal
reduction requiremei
choices forecast by
oil/gas steam units i
expensive compliance opti
combined cycle is I
existing coal plant,
significant increase in repo

Note that Figure 14 |
investing in new scrub
scrubbers and new

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for the B
h control tec!

|d the _

ase

oirm^nt <^Krol^»nology
•x, emu scilBbers^^^r for SO2, NOx,
x, and mercury reductions are required for the three-
in the combination of scrubbers + SCR/SNCR retrofits is the

it combinations. This increase gets larger as the emission
|ent. Some of the other technology-based compliance
jel include ACI for mercury removal and repowering of coal and
units. Generally, repowering is one of the more
the capital cost of repowering an oil/gas steam unit to
Capital cost of installing a scrubber + SCR option on an
lg price of gas is more expensive compared to coal. Hence, a
teions is not anticipated.

T5s an increase in total SO2 scrubbers (the summation of power plants

ew scrubbers and new
os get progressive!

lewJMRs or SNCRs,^M^Bw

stringent. SiiMarly, the total

| ^ Jj

-------
amount of SCRs (summation of power plants investing in new SCRs, and in new SCRs plus
scrubbers) increases with increasing emission reductions.

Figure 14. Incremental Retrofit Decisions in 2020

G
W

Base Case Scenario 3 Scenario 2 Scenario 1

¦ SNCR or Gas Reburn

¦ SCR/SNCR and Scrubber

~ SCR/SNCR and ACI

¦ SCR only

~ Scrubber only

~ Re powering

2.3.7. New Unit Impacts

The model forecasts the addition of new capacity to meet increased demand growth and to
replace retired capacity. Figure 15 summarizes the cumulative new capacity additions (not
including repowered capacity) by 2020. Note that as the emission reduction requirements
increase, cumulative new combined cycle capacity increases while new combustion turbine
capacity decreases. This occurs because the scenarios favor natural gas, which makes combined
cycle plants (with relatively high fixed costs and low variable costs) more economic compared to
combustion turbines (which have relatively low fixed costs and high variable costs).

Figure 15. Cumulative New Capacity by 2020 (GW)

140

120

100

G 80
W

60
40
20

Combined Cycle

Combustion Turbine

~ Base Case ¦ Scenario 3 ~ Scenario 2 ~ Scenario 1

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2.3.8. Energy Price Impacts

The price of firm power in wholesale markets is based on the variable cost of the marginal unit
and the price of capacity.7 A scenario requiring emissions reductions could influence the
variable cost of the marginal unit due to changes in power plants' compliance cost. The impact
of the policies on wholesale power price is small, ranging from 0.5 mills/kWh to 0.7 mills/kWh,
or 1.9% to 2.4%, respectively. The percentage impact on consumers would be less, reflecting the
other components of consumer price not affected by these scenarios.8

2.3.9. Regional Impacts

The impacts of the three scenarios on emissions and coal consumption vary in the different
regions of the contiguous United States. Figure 16 shows the projected impact of Scenario 1 on
power generator's coal consumption by coal production region. Likewise, Figures 17, 18 and 19
show the projected impact of Scenario 1 on regional SO2, NOx, and mercury emissions,
respectively. The regional impacts of Scenarios 2 and 3 would be similar — but less significant —
than those for Scenario 1.

Figure 16. Coal Consumption by Coal Production Region in 1999 and 2020

(Source of 1999 Actual Coal use is EIA Annual Energy Review (DOE/EIA-0384(99)),
Table 7.3, Coal Consumption by Sector.)

Scale: Appalachia Coal, 'Scenario 1"= 361 million tons

National Coal Consumption in 2020

1200

c 900
o

| 600

| 300
0

—

985 g

alachia

ftntral and
Western Gulf

1999 Actual Coal Use

7 The firm power price is estimated under the assumption that the power plant is selling capacity in all hours.

8 This analysis assumed a permanent allocation of emission allowances.

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Figure 17. Regional S02 Emissions from Power Generators in 2020
(Note: graphic includes emissions from all units that are connected to the grid.)

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Figure 18. Regional NOx Emissions from Power Generators in 2020
(Note: graphic includes emissions from all units that are connected to the grid.)

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Figure 19. Regional Mercury Emissions from Power Generators in 2020
(Note: graphic includes emissions from all units that are connected to the grid.)

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3. Greenhouse Gas Analysis

In addition to investigating policies to reduce SO2, NOx, and mercury emissions, the Senators
asked EPA to analyze the impacts of requiring that U.S. electricity sector carbon dioxide (CO2)
emissions increases above 2008 levels be offset. The request specifically allows for offsets "...by
reductions or sinks in any sector of any greenhouse gas in an amount equal to the warming
potential of the emissions to be offset. Assume that verifiable reductions or sinks achieved in
any nation could be available on the domestic emissions market to satisfy this requirement."

This analysis uses two different projections of CO2 emissions in the U.S. electricity sector
through 2020, coupled with three variations of offset program effectiveness and alternative
assumptions about international offset demand. EPA's analysis shows that needed offsets range
from zero to six million metric tons carbon equivalent (MMTCE) in 2010 to between 58 and 75
MMTCE in 2020.9

In most cases, EPA estimates that abatement costs of a GHG offset program would be negligible
through 2020. For these cases, the allowance price associated with the offset program would be
equal to the transactions costs of securing the offsets. Estimates of transactions costs, which
include private deal-making activities, and government program costs, have not been calculated
because of a lack of adequate data. For these cases, only when offset availability is limited to
3% in 2010 or 24% in 2020 do higher allowance prices appear.

EPA also examined cases in which other countries comply with the Kyoto Protocol. With the
implementation of the Kyoto Protocol reached in Bonn, there is likely to be no change in U.S.
allowance prices or abatement costs through 2010. However, by 2020, U.S. allowance prices
could rise to $1-9 (plus transactions costs) per ton of carbon equivalent, and total annual
abatement cost in the U.S. could range from negligible to $190 million. EPA has also considered
possible cases in which allowance prices could be higher. For example, implementation of the
Kyoto Protocol agreement coupled with significant allowance banking in the former Soviet
Union and Eastern Europe could raise offset prices to $17 (plus transactions costs) per ton and
abatement costs to nearly $500 million by 2020.

Unless one of these higher priced scenarios is realized, however, the fuel mix in the electricity
sector is not likely to be affected because reductions are likely to occur outside the sector, given
the low costs of offsets under the scenario requested.

3.1. Emissions Forecast and Required Emissions Offsets

To examine the scenario in which the U.S. electricity sector offsets CO2 emissions above 2008
levels as part of a multi-emissions approach, EPA applied two base cases for electricity sector
CO2 emissions through 2020. One is generated from IPM® and the other is from EIA. Both

9 The models used for this analysis yield output in five- or ten-year increments. Therefore, EPA provides results
for 2010 and 2020. The results provided in 2010 and 2020 are the emissions to be offset in those years alone.

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projections incorporate the CO2 reductions from the application of the multi- emissions control
program.

3.1.1. IPM® Multi-Emissions Base Case

EPA used IPM® to forecast electricity sector emissions in 2008 and emissions growth through
2020. The IPM® projection is based on EIA data, but is adjusted to account for emissions
reductions resulting from the government's energy-efficiency programs, such as Energy Star®. It
assumes that the sector is also reducing SO2, NOx, and mercury emissions under Scenario 2 of
the Senators' request. The SO2, NOx, and Hg emissions control measures result in the ancillary
benefit of CO2 emissions reductions within the electricity sector. Consequently, CO2 emissions
under Scenario 2 are lower than those of the IPM® Base Case. The IPM® three-emissions
forecast for CO2 emissions in 2008 is approximately 640 million metric tons of carbon
equivalent (MMTCE) (about 2,350 million metric tons of CO2 equivalent). The projected
emission offset requirement is six MMTCE in 2010 and 58 MMTCE in 2020.

3.1.2. EIA Base Case

EPA used CO2 emissions projections from EIA's analysis entitled "Reducing Emissions of
Sulfur Dioxide, Nitrogen Oxides and Mercury Emissions from Electric Power Plants"10 to
develop the EIA Base Case. To be consistent with the IPM® Base Case, EPA took the EIA
multi-emissions case that would reduce SO2, NOx and mercury by 65%. The projected offset
requirements under the EIA Base Case are zero MMTCE in 2010 and 75 MMTCE in 2020.

3.2. Methodology

This section provides background on emissions offset programs and describes the approach and
assumptions that EPA used in conducting the analysis.

3.2.1. Background

GHG "offsets" generally refer to emissions reductions or sequestration of GHG emissions
achieved outside of the source categories that have an emissions cap. In the case of an electricity
sector offset program, electricity generators would be able to use offsets created through
emission reductions or sequestration of GHG emissions by sources outside the cap on CO2. (See
the Appendix for a description of offset source categories analyzed in this analysis.)

Allowing for offsets of CO2 emissions from any GHG source in any sectors of the economy,
domestically and internationally, would reduce the cost of achieving emissions reduction targets.
A commonly used index known as the "Global Warming Potential" (GWP) allows for the
comparison of greenhouses gases in terms of their relative contribution to climate change.11 For

10 U.S. Energy Information Administration: "Reducing Emissions of Sulfur Dioxide, Nitrogen Oxides and Mercury
Emissions from Electric Power Plants", September 26, 2001 prepared for Senators Smith, Voinovich and
Brownback.

11 The GWP range for non-CC>2 gases (15 different gases) varies between 21 for methane and 23,900 for sulfur
hexafluoride (SFg). For example, the 100-year GWP of methane is 21, indicating that one ton of methane released

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this report, the 100-year GWP of each greenhouse gas is used to express quantities in millions of
metric tons of carbon equivalent (MMTCE).

Fossil fuel electricity generation is the largest source of domestic anthropogenic CO2 emissions,
accounting for approximately 40 percent of total U.S. CO2 emissions in 1999.12 Numerous
options exist for reducing CO2 emissions within the electricity sector, including generation
efficiency improvements, transmission and distribution system efficiency improvements, and
fuel switching to less carbon intensive fuels. For example, the electricity sector can and
currently does use non-GHG-emitting energy sources, such as wind, solar, hydropower, and
nuclear power.

Though there are many opportunities for CO2 reductions in the electricity sector, there are
potential advantages to an offset program involving other sectors. First, allowing the electricity
sector to purchase reductions from other sources will reduce the cost of achieving the cap. A
number of U.S. and international analyses have shown that some of the most cost-effective
mitigation options are likely to be terrestrial carbon sequestration and reductions of non-CC>2
gases including methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and sulfur hexafluoride (S F6).13 The costs of many carbon
sequestration activities or mitigation projects that reduce non-CC>2 GHGs can be totally or
partially recovered through increased efficiency, recycling of materials, or the capture and sale of
the gas (e.g., methane).

Thus, this analysis incorporates a set of GHG mitigation options called "no-regrets," where the
cost of the project is completely recovered. "No-regrets" mitigation options allow the electricity
sector to purchase offsets from these other sources, thus reducing the cost of, and potentially
providing a net benefit for, achieving the reduction goal. Second, reduction of GHGs from
sources outside the capped electricity sources may provide ancillary environmental benefits (e.g.,
reduced air pollution) that otherwise would not have been realized. Third, financial incentives
resulting from an offset program might accelerate the development and use of new emissions
reduction technologies.

3.2.2. Analytic Approach

A number of important factors affect the potential costs and availability of GHG offsets in a
domestic and world market. Three factors are described here—the strength of economic
incentives, transaction costs, and emission reduction certainty.

Economic Incentives

Most previous economic studies that have sought to examine climate mitigation policy options
have evaluated the impacts of GHG cap-and-trade systems. Under these analyses, a binding
"cap" typically is placed upon total allowable GHG emissions. This cap creates a "scarcity

into the atmosphere has the same climate forcing as 21 tons of CO2. (IPCC, 1996)

12 US EPA, 2001(a).

13 See for example Bailie, et.al, 2001 and Reilly, et.al., 1999 and 2000.

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value" for GHG emissions and, in turn, a price for marketable GHG emission allowances. Faced
with an allowance price, individual sources make decisions about whether to reduce emissions at
their own facilities or buy emissions allowances from other sources. Each source would have an
incentive to control emissions up to the point where its marginal costs of doing so equals the cost
of purchasing another source's allowances, i.e., the allowance price.

As allowance prices rise, sources will have an increasing incentive to reduce emissions. At a
global allowance price of one dollar per metric ton of carbon, EPA estimates that a global cap-
and-trade program (including all greenhouse gases) would result in GHG reductions of
approximately 265 MMTCE in 2010 and 300 MMTCE in 2020. Figure 20 and Figure 21 depict
the U.S. and international marginal GHG abatement costs used to obtain these results.14 (See the
Appendix for a description of the analytical tools used for this analysis and coverage of source
categories.)

A number of factors influence the types of emission reductions and costs of a GHG offset
program compared to a GHG cap-and-trade program confined to one or more regulated sectors.
In an offset program, only a fraction of sources (those within the sector(s) subject to a cap)
would see a direct and immediate economic incentive to participate - an allowance price. In the
case examined here, the electricity sector must offset emissions above 2008 emissions levels and
therefore must seek to reduce its own emissions or purchase offsets from other sources.

The other GHG emitting sectors, however, see a more limited economic incentive to participate
since they are not subject to a mandatory emissions target. While these sectors can potentially
achieve economic advantage by generating and selling offsets, this incentive may not be as
strong as if all sources were subject to an emissions cap. Consequently, sources in sectors
outside of the electricity sector may not participate as actively as if they had to limit their own
emissions. This implies that the sources outside the cap might expend less effort to achieve
emissions reductions, thus creating fewer abatement opportunities.

Transaction Costs

Transaction costs are an additional factor influencing the costs of an offset program. Transaction
costs include "deal making" activities and programmatic compliance activities undertaken by
firms. Specifically, these costs may include project development costs, decision-making costs
internal to firms, search costs, negotiation and brokerage costs, monitoring and verification
(including certification and registration) costs, and insurance costs.

Estimating the transaction costs that would apply to offsets purchased in cases analyzed here
proves difficult, as there have been relatively few comparable programs (at least for GHG
offsets). A literature review of project experience and modeling assumptions, as well as personal
communication with various project development professionals, researchers, and other experts,

14 Estimates of non-CC>2 marginal abatement curves represent about 35% of global non-CC>2 GHG emissions
available for offsets. The forest carbon sequestration supply curves for the countries covered in the analysis
represent only about 35% of the global forest area (including natural forests and plantations).

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suggests a range of transaction cost estimates from $0.04/ton of carbon to well over $10/ton.15
However, most of the high estimates have little or no documentation to support them. The same
literature suggests that transaction costs as a percentage of total GHG abatement cost (for the
GHG pilot projects and GHG trades undertaken so far) have ranged from under 5 percent to over
75 percent. Further, evidence from established non-climate projects at the Global Environmental
Facility (e.g., stratospheric ozone layer protection projects) indicates that moderate program
experience reduces transaction costs from roughly 30 percent to under 10 percent of total costs.16

15 See, variously: Ashford, 2001; Bailie et al., 2001; EPRI, 2000; Free, 2001; ICF, 1998; Ghersi, 2001; Heister,
2001; Hourcade and Ghersi, 2001; Kurosawa, 2001; Mascarella, 2001; Mathur, 2001; Powell et al., 1997;
Shifflet, 2001; UNFCCC, 2001; World Bank PCF, 2000; Youngman, 2001.

16 Mathur, 2001.

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Figure 20. U.S. GHG Abatement Costs in 2010

Figure 21. International (Non-U.S.) GHG Abatement Costs in 2010

Emission Reductions (MMTCE)

^"International
Carbon

¦ International
Sequestration

™ International
Non-C02

^"International
Total

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EPA's experience with the well established SO2 trading program, where government approval of
trades is not necessary, reflects transaction costs of one to two percent of allowance prices.17
However, the SO2 trading program is a streamlined allowance-based cap-and-trade program that
does not include offsets from outside the electricity sector. Therefore, it does not require case-
by-case review of trades. In contrast, the inclusion of offsets and the case-by-case
documentation and review that this necessitates would be expected to increase the transaction
costs associated with the GHG offset program.

Finally, a detailed and current engineering cost analysis prepared on GHG-offset transaction
costs predicts roughly $l/ton carbon for typical coal mine methane recovery projects.18 Of the
literature reviewed, this study appears to be the best-documented estimate of GHG transaction
costs. However, given the overall uncertainties discussed above, EPA is not prepared to predict
transaction costs for the GHG offset program at this time.

Emissions Reduction Certainty

A major distinction between a GHG cap-and-trade and a GHG offset program is the ability to
verify that emissions are actually reduced in the offset producing sectors that are not subject to a
cap on emissions. As long as aggregate emissions under a GHG program are monitored and
verified and compliance is enforced, the emission reduction goals will be achieved. In the case
of the electricity sector, such calculations are relatively straightforward since sources are already
equipped with continuous emissions monitoring systems that measure several emissions,
including CO2.

However, for an offset program covering other sectors of the economy, it becomes difficult to
construct a verification system that ensures emissions reduction certainty for specific projects.
Verification systems designed to ensure emissions reduction certainty for sector-specific offset
programs confront many challenges, two of which are "additionality" and "leakage."

Judgements about additionality involve determining whether actions that are candidates for
earning offsets would have occurred in the absence of an offset program. There are numerous
reasons why a firm's emissions could decrease regardless of whether an offset project is
completed. For example, factors such as reduced production, compliance with other policies, or
changing market conditions could result in emission reductions. In cases where a program
awards offsets for reductions that would have happened in the absence of the program, overall
emissions could increase. The offsets created by projects that are not "additional" are said to be
"anyway" tons, i.e., reductions that would have occurred anyway.

"Leakage," which may increase overall emissions, is another potential problem in an offset
program. Because offset programs do not cover the entire universe of sources within a source
category, an apparent reduction at one source could precipitate an increase in emissions at
another. If offsets are awarded for leaked emissions, then net emissions do not decrease as a
result of the project producing carbon offset credits and may actually increase. For example, a

17 ICF, 1998.

18 Free, 2001.

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conservation project in one forest may lead to increased harvesting elsewhere. The "leakage"
from one forest to the other effectively nullifies the GHG emissions reductions of the
conservation project and, if offset credit is awarded, allows a capped source to increase its
emissions. While methods are available to screen for additionality and leakage, they remain
imperfect. Increasing rigor in the screening and enforcement process also contributes to
increasing transaction costs.

Adjustment of Available Emissions Offsets

To estimate the emissions reductions and costs of an electricity CO2 offset program, EPA has
constructed three cases that could account for the inherent differences between offset and trading
programs (including transaction costs and other factors such as leakage and additionality). Each
case is based on the relationship between the cost and availability of abatement opportunities
across all sectors both domestically and internationally. The three cases are described below.

Case I: In this case, EPA assumes the offset program sends a strong economic signal for
emission reductions to sources outside the electricity sector and all reductions are real and
verifiable. In other words, the offset program is assumed as effective as a cap-and-trade
program. Institutional or informational barriers at the domestic and international level are not
significant. Any potential limitations on program effectiveness such as "anyway" tons and
"leakage" are effectively and inexpensively removed from the system. Case I represents the
ideal offsets program.

Case II: In this case, EPA assumes that abatement opportunities are limited because the offset
program provides weaker incentives for emissions reductions outside the electricity sector
(relative to economy-wide cap-and-trade). In addition, institutional barriers may exist that limit
GHG abatement opportunities. International reductions are affected more than domestic
reductions because greater institutional barriers may exist in securing international offsets, such
as potentially different approval procedures established by foreign governments. EPA assumes
in this case that GHG abatement opportunities can be successfully screened to ensure that
reductions are not "anyway" tons or leaked emissions. As a proxy to estimate these effects, EPA
reduced the domestic availability of emissions offsets by 50 percent and reduced the
international availability of offsets by 75 percent, as compared to Case I.

Case III: In this case, the program monitoring and verification has difficulty distinguishing
between projects in which emission reductions resulted from the offset program and projects
characterized by "anyway" tons and leakage effects. Therefore, emissions reductions certainty
cannot be guaranteed. While this would increase the quantity of available offsets, the existence
of "anyway" tons and leakage in the system undermine the GHG emissions reductions goal. As
a proxy to estimate this, EPA increased the quantity of offsets available from all sources by 20
percent, as compared to Case I.

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3.3. Results

EPA analyzed the impacts of requiring the U.S. electricity sector to offset CO2 emissions by
emissions reductions or sinks from other sources starting in 2008. This analysis is conducted
with the U.S. electricity sector CO2 emissions baseline scenarios listed in section 3.1. The first
scenario uses the IPM Base Case. The second uses EIA's electricity sector CO2 emissions
forecast.

The analysis is presented in the context of different possible interactions with the rest of the
world. The first assumes that there is no demand for CO2 offsets other than from the U.S. The
second assumes that the Kyoto Protocol is implemented by the signatories of the Bonn Accord
and that currently available GHG emissions projections can be used to estimate the resulting
emissions market. The third analysis examines the impacts of different possible outcomes of the
Kyoto Protocol.

3.3.1. U.S. Electricity Sector is the Only Source of Demand for Offsets

Table 2 shows that the price of allowances in all cases is equal to the transaction costs if there is
no demand for offsets other than from the U.S. Total abatement costs, which represent the
resource costs associated with securing GHG emissions reductions, are negligible. Transactions
costs, and government program costs, are uncertain due the lack of previous experience with
GHG offset programs and are not reported below. Further, while the resource costs of
generating GHG offsets may be negligible, electricity generators may face expenses in the
purchase of offsets. Therefore, individual electric utility costs may be positive. As a result of
such low abatement costs, the fuel mix in the electricity sector is not likely to be affected by the
options examined. Although the other two three-pollutant scenarios (1 and 3) were not used as
alternative base cases in this analysis, EPA expects that the results would be similar to those
resulting from Scenario 2.

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Table 2.a. Allowance Prices of Greenhouse Gas Offsets in 2010 (2000 $/TCE)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

transactions cost

IPM*

transactions cost

Table 2.b. Total Abatement Costs in 2010 ($ million)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

negligible

IPM*

negligible

Table 2.c. Allowance Prices of Greenhouse Gas Offsets in 2020 (2000S/TCE)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

transactions cost

IPM®

transactions cost

Table 2.d. Total Abatement Costs in 2020 ($ million)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

negligible

IPM*

negligible

While the price of allowances is generally sensitive to the global availability of offsets, the
modest CO2 reductions required by the Senators' request imply that allowance prices are likely
to equal transactions costs for a wide range of offsets availability. In the case where six
MMTCE are required in 2010 (IPM Base Case), the price rises above transaction costs only if
fewer than three percent of worldwide offsets were available. Likewise, in 2020 (where the
number of required offsets is 58 MMTCE), the allowance price rises above transaction costs only
if availability of worldwide offsets falls below 24 percent. For example, in 2020, if only 20% of
worldwide offsets were available, the allowance price would be one dollar, plus transactions
costs.

Total abatement costs are negligible for all cases and may even result in net economic benefits.
Low or negative costs are possible because the offset program may provide sufficient incentives
to efficiency or other mitigation projects (e.g., methane recovery) that may result in long-term
economic benefits. Ancillary benefits such as the reduction of conventional pollutants from a
CO2 offset program may result, but are not quantified.

The abatement costs of the program are low due to two principal factors. First, the size of the
overall GHG reduction called for in the Senators' request is relatively modest: the Senators'

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requested that EPA analyze a program that offsets the growth in GHG emissions in only one
sector of the U.S. economy—the electricity sector—and offsets are not required until after 2008.
By 2010, the required level of offsets represents less than one percent of U.S. electricity sector
CO2 emissions, and approximately nine percent by 2020. Secondly, there is an abundance of
offset opportunities due to the Senator's specification that verifiable GHG reductions or sinks
from any source achieved in any nation would be available to satisfy the offset requirement. If
the offset requirement were greater, or if the opportunities for obtaining offsets were limited,
abatement costs and allowance prices would be higher.

3.3.2. Interaction with the Kyoto Process

EPA has analyzed how the U.S. policy of offsetting CO2 emissions in the U.S. electricity sector
could be affected by interactions with implementation of the Kyoto Protocol. The recent
agreement on the Kyoto Protocol negotiated in Bonn, if ratified, would require developed
country signatories to reduce their GHG emissions to approximately 4.2% below their 1990
emissions levels by 2008-2012.19 The Kyoto Protocol allows for GHG emissions trading among
developed country signatories, the availability of offsets in developing countries, and country-
specific credit for terrestrial sequestration. (See Appendix A.4. for a description of the Kyoto
Agreement). These countries currently have no commitments after 2012, but EPA has assumed
for this analysis that subsequent agreements maintain the emissions targets through 2020.

This analysis uses CO2 emissions projections from EIA and non-CC>2 emissions projections
developed by EPA.20 The total number of emission reductions required by the Kyoto Protocol is
highly dependent upon emissions in the Former Soviet Union and Eastern Europe, which have
declined since 1990. Factoring in all GHG emissions and the credits allowed for sequestration,
there is no apparent need for reductions or offsets in 2010 as a result of the Protocol, but roughly
280 MMTCE of offsets may be required by 2020.

Adding the Kyoto reductions to the demand to offset U.S. electricity sector CO2 emissions after
2008, the world demand for offsets in 2020 is approximately 340-355 MMTCE. Three cases,
similar to the different assumptions of program effectiveness used previously, are examined.21
For these cases, the allowance price ranges from $1-9 (plus transactions costs). The total
abatement costs for the U.S. would range from negligible to $190 million.

19 For certain high GWP gases, countries may use their emissions from 1990 or 1995 as their baseline. The figure
of 4.2% for the total reduction is determined from country -specific 1990 and 1995 emissions by GHG, and
calculating the respective target emis sion levels specified in the Kyoto Protocol.

20 Energy Information Administration, "International Energy Outlook 2001March 2001. DOE/EIA-0484(2001).

21 These cases are modified from Cases I-III since developed countries are assumed to engage in emissbns trading.

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Table 3.a. Allowance Prices of Greenhouse Gas Offsets in 2010 (2000 $/TCE)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

transactions cost

IPM®

transactions cost

Table 3.b. Total Abatement Costs in 2010 ($ million)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

negligible

IPM®

negligible

Table 3.c. Allowance Prices of Greenhouse Gas Offsets in 2020 with Kyoto Protocol (2000S/TCE)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

2 + transactions cost

9 + transactions cost

1 + transactions cost

IPM®

2 + transactions cost

8 + transactions cost

1 + transactions cost

Table 3.d. Total Abatement Costs in 2020 with Kyoto Protocol ($ million)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

negligible

190

negligible

IPM®

negligible

130

negligible

3.3.3 Alternative Emissions and Offsets Scenarios for Kyoto

The allowance price estimates above could be influenced by the availability of GHG allowances
from the Former Soviet Union and Eastern Europe (FSU/EE). For example, emissions growth in
the region could be higher or lower than predicted by the EIA emissions projections. Similarly,
institutional constraints or government decisions may limit the availability of offsets from those
countries. For example, one or more of the countries in the region may choose to bank some
portion of their available offsets for their own future use, rather than sell them on the
international market.

If the available offsets in FSU/EE were half that predicted by EIA emissions forecasts (roughly
200 MMTCE fewer for both 2010 and 2020), CO2 allowance prices could range from $4-17
(plus transactions costs) in 2020 and abatement costs could be between zero and $483 million.
See Table 4 below. On the other hand, if emissions growth in FSU/EE slowed, so that available
credits increased by 200 MMTCE, allowance prices would range from $0-2 (plus transaction
costs).

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Table 4.a. Allowance Prices of Greenhouse Gas Offsets in 2010 with Kyoto and 200
MMTCE Fewer Allowances Available (2000 $/TCE)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

transactions cost

5 + transactions cost

transactions cost

IPM®

transactions cost

6 + transactions cost

transactions cost

Table 4.b. Total Abatement Costs in 2010 with Kyoto and 200 MMTCE Fewer Allowances
Available ($ million)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

negligible

IPM®

negligible

Table 4.c. Allowance Prices of Greenhouse Gas Offsets in 2020 with Kyoto and 200
MMTCE Fewer Allowances Available (2000S/TCE)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

6 + transactions cost

17 + transactions cost

4 + transactions cost

IPM®

5 + transactions cost

16 + transactions cost

4 + transactions cost

Table 4.d. Total Abatement Costs in 2020 with Kyoto and 200 MMTCE Fewer Allowances
Available ($ million)

Global (All GHG and Sequestration)

Baseline

Case 1

Case 2

Case 3

EIA

483

negligible

IPM®

344

negligible

3.3.3. Banking

Senators Smith, Voinovich, and Brownback also requested that EPA consider the effect of
banking CO2 emissions allowances beginning in 2002. With banking, the electricity sector can
secure allowances starting in 2002, six years before they are required to offset their emissions.
There are two primary motivations for banking emissions allowances in this case. The first
motivation is to avoid increased costs associated with the out-years of the program (i.e., the
2008-2020 period). Second, electricity generators may seek to hedge future emissions reduction
obligations. Banking emissions allowances in earlier periods would act as an insurance policy
against unanticipated events or future policy changes that may raise costs. Since, for the
scenarios requested by the Senators, allowance prices are not anticipated to be high or increase
significantly over the time frame of this analysis, there would seem to be little economic
incentive to bank allowances. Thus, EPA did not model banking of CO2 emissions allowances.
However, electricity generators may prefer to achieve their offset obligations early for business
planning purposes, likely resulting in lower costs later and reduced price volatility.

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Appendix

For this analysis, EPA used several analytic tools to estimate the availability and potential cost of
emissions reductions within and outside the electricity sector. This appendix describes the
various models used by EPA in conducting both the three-pollutant and greenhouse gas analysis.

A.l. Three-Pollutant Analysis

Integrated Planning Model (IPM®)

Much of the analysis presented in this report is based on use of the Integrated Planning Model
(IPM®), by ICF Resources, Inc. For this analysis, EPA populated the model with data from
EIA, ICF, EPA and other public sources. IPM® is a detail-rich, bottom-up linear programming
model of the electricity sector that finds the most efficient (i.e. least cost) approach to operating
the electric power system over a given time period subject to specific constraints (e.g. pollution
caps or transmission limitations). The model selects investment strategies given the cost and
performance characteristics of available options, forecasts of customer demand for electricity,
and reliability criteria. System dispatch, determining the proper and most efficient use of the
existing and new resources available to utilities and their customers, is optimized given the
resource mix, unit operating characteristics, and fuel and other costs. Unit and system operating
constraints provide system-specific realism to the outputs of the model.

The IPM® is dynamic; it has the capability to use forecasts of future conditions, requirements,
and option characteristics to make decisions for the present. This ability replicates, to the extent
possible, the perspective of utility managers, regulatory personnel, and the public in reviewing
important investment options for the utility industry and electricity consumers. Decisions are
made based on minimizing the net present value of capital and operating costs over the full
planning horizon.

Several factors make IPM® particularly well suited to model multi-emissions control programs.
These include its ability to model complex interactions among the electric power, fuel, and
environmental markets and a wide range of compliance options including:

1. Fuel switching (for example, switching from high sulfur to low sulfur coal),

2. Repowering (for example, repowering a coal plant to natural gas combined-cycle),

3. Pollution control retrofits (for example, installing a scrubber to control SO2 emissions),

4. Economic retirement (for example, retiring an oil or gas steam plant), and

5. Dispatch adjustments (for example, running high-NOx cyclone units less often, and low
NOx combined-cycle plants more often.)

IPM® also models a variety of environmental market mechanisms, such as emissions caps,
allowances, trading, and banking. IPM's ability to capture the dynamics of the allowance market
was particularly important for assessing the impact of the multi-emissions environmental policies
evaluated in this report. EPA has recently completed a major update of the model's assumptions
and computational structure. The analyses discussed in this report are products of the updated
model. The following tables summarize many of IPM®' s key assumptions.

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Table A.l.l. Key Assumptions in IPM 2000 EPA Base Case

Factor

Assumption

Electricity Demand Growth Rate

(% per year, 2000-2020, net energy for load)

Before full accounting for CCAP: 1.8% (Based on AEO 2001)
After full accounting for CCAP: 1.2 %

Climate Change Action Plan Reductions (billion

kWh)

97.5 in 2000
468.1 in 2010
585.8 in 2015
733.0 in 2020

Planning Reserve Margins

Based on EIA and NERC Reports

Power Plant Lifet imes

Fossil units: none
Nuclear:

10-year life extension option at age 30
20-year relicensing option at age 40

Fossil Capacity

Existing capacity as reported in NEEDS 1998, 1998 EIA 860a, 1998 EIA 860b, 1999 NERC
ES&D and 1997 EIA 860. Includes both utility and independent power producer units.

Coal and Oil/Gas Steam Power Plant Annual
Availability

Coal Steam: 85%
Oil/Gas Steam: 85%

Power Plant Heat Rates

No change over time

Nuclear Capacity (GW)

2005:88
2010:82
2015:77
2020:73

Nuclear Capacity Factors (%)

2005:85.3%
2010:87.1%
2015:88.2%
2020: 89.4%

Net Imports (billion kWh)

2005:49.0
2010:32.5
2015:33.4
2020: 27.3

Hydroelectric Generation (billion kWh)

269 billion kWh annually, between 2005 and 2020

Renewables Generation (billion kWh)

34 billion kWh annually, between 2005 and 2020

Transmission Losses Between IPM Regions

2 percent

Transmission Capacity

Varies by region

Net Energy for Load

(Electricity load assumptions in Billions of kWh)

2005:3,925
2010:4,120
2015:4,366
2020: 4,574

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Page 32

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Table A.1.2. Emissions Assumptions for Potential (New) Units in IPM 2000 EPA Base Case

I-mission

Conventional
Pulverized
Co ill

Integrated
Gasification
Combined
Cycle

Combined
Cycle

Advanced
Combustion
Turbine

Combustion
Turbine

Biomass
Integrated
Gasification
Combined
Cycle

Geolhermal

Landfill
Gas

Assumed Controls

Scrubber

None

so2

Removal/
Emissions Rate

95% from sulfur
content of coal

100%

None

0.08 lbs/MMBtu

None

100%

Assumed Controls

SCR

None

NOx

Emission Rate

0.05 lb/MMBtu

0.02 lb/MMBtu

0.10
lb/MMBtu

0.02 lb/MMBtu

None

0.246
lb/MMBtu

Assumed Controls

None

co2

Emission Rate

205.3-215.4
lb/MMBtu

117.08
lb/mmBtu

No net emissions

None

No net
emissions

Assumed Controls

Scrubber and

SCR1

None

Removal Rate

95%

100%

None

Emission Rate

Varies with Hg
content of Coal

None

0.00014
lbs/TBTu

0.571bs/TBtu

8 lbs/TBtu

0 lbs/TBtu

Note. All emissions are assumed to be zero for nuclear, advanced nuclear, wind, fuel cells, solar photovoltaic, and solar thermal.

EPA assumes 95% mercury removal for all coal types through a combination ofFGD and SCR. EPA bases its removal on interpretation of Information Collection Request (ICR) data. See U.S. EPA,

Performance and cost of mercurv emission control technology applications on electric utility boilers. National Risk Management Research Laboratory. Office of Research and Development September 2000. See

alsoFahlke. J. and A Bursik. Impact of the state-ofthe-artflue gas cleaning on mercurv species emissions from coal-fired steam generators. Water. Air. Soil Poll.. 80. 209-215. 1995.

-------
Table A.1.3. Summary of Emission Control Performance Assumptions in IPM 2000 EPA Base Case

SO: Scrubbers

N()X Post-Combustion Controls

Mercury 1

Other Controls

Limestone
Forced
(Kidalion

(I si c))

Mauiiesiuni

linlianced

l.ime(Mi:i.)

I .inie Spray
l)ryer(l.si))

snr

S\"CR

Gas Reburn

Activated Carbon
Injection

Combustion
()ptinii/.alion

Biontiss Coin ing

I ,o\\ \( \

High \"(\

Percent
Removal

95%

96%

90%

90% (coal)
80% (gas)
(Down to 0.05
lb/mmBtu)

35% (coal)
50% (gas)

40%

50%

80% (for routine
scenarios)

0.5%heatrate
(BTU/kwh) improvement

20% NOx reduction

Capacity
Penalty

2.1%

Fuel Use
Impacts

16% gas
use

Cyclones
5% Biomass, >200MW
15% Biomass, < 200 MW

Other Coal
2% Biomass, >200MW
15% Biomass, 200 MW

Cost (1999$)

See Table A. 1.3.a

See Tables A. 1.3.b and A. 13.c

See Table A 1.3.d

$250,000 capital cost
$40,000/yr FOM cost

Applicable
Population

Coal
boilers >
100 MW

Coal boilers <
550 MW and>
100 MW

Coal boilers
> 550 MW

Coal boilers >
100 MW

All oil/gas
steam units.

All coal and
oil/gas steam
units

All oil/gas
steam units

All coal units >

25 MW

Coal boilers >
100 MW

All coal units

Note: Activated carbon injection, combustion optimization, and biomass cofiring are not implemented in IPM 2000 EPA Base Case, but are available capabilities that can be implemented, as applicable, in
policy runs built on the Base Case. The capacity penalty implies that a plant's dispatchable capacity is reduced and its heat rate is increased by the percentage shown. EPA estimates that the operating
penalties associated with scrubbers are between 0.7 - 2.0% of capacity. See U.S. EPA. Controlling SO2 emissions: a review of technologies. USEPA, Washington, DC (EPA/600/R-00/093), November 2000);
the 2.1% capacity penalty in the report, then, is consavative. The Agency estimates that the operating penalties associated with SCR are between 0.2- 0.5%, largely due to equipment required to counter the
pressure drop. See U.S. EPA. Cost estimates for selected applications of NOx control technologies in stationary combustion boilers: responses to comments on the draft report. USEPA, Washington, DC, June
1997. Because the operating penalties for SCR were small, they were not included in the modeling.

EPA assumes 80% mercury removal for ACI. See ICF memo from K. Jayaraman, J. Haydel, and B.N. Venkatesh entitled Mercury control cost calculations: assumptions, approach, andresults. September
2000. Specifically, see the attachment entitledMercurv control technology assumptions determined during EPA's meeting with DOE at EPA Washington, DC, August 22-23, 2000.

-------
Table A.1.3.a. Scrubber Costs for Representative MW and Heat Rates (1999$)

I leal Rale

Scrubber Type

9.000

10.000

1 1,000

C osl

LSFO

100

514

528

541

Capital Cost ($/kW)

Minimum Cutoff: >= 100 MW

Fixed O&M ($/kW-yr)

Maximum Cutoff: None

Variable O&M (mills/kWh)

300

252

262

272

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

500

193

201

209

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

700

159

166

173

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

1,000

176

186

194

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

MEL

100

352

364

375

Capital Cost ($/kW)

Minimum Cutoff: >= 100 MW

Fixed O&M ($/kW-yr)

Maximum Cutoff: < 500 MW

Variable O&M (mills/kWh)

200

232

242

251

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

300

233

244

255

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

400

207

218

229

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

500

185

195

204

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

LSD

600

148

156

163

Capital Cost ($/kW)

Minimum Cutoff: >=550 MW

Fixed O&M ($/kW-yr)

Maximum Cutoff: None

Variable O&M (mills/kWh)

700

137

145

152

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

800

134

140

146

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

900

135

142

149

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

1,000

128

135

141

Capital Cost ($/kW)

Fixed O&M ($/kW-yr)

Variable O&M (mills/kWh)

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Page 35

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Table A.1.3.b. Costs of Post-Combustion NOx Controls for Coal Plants (1999 $)

Percent

Post-Combustion

Capital

l-'ixed O&M

Variable ()&M

Percent

Removal

Control Technology

(S/kWi

iN/kW/Yn

(mills/kWh)

Gas Use

SCR2

$80

$0.53

0.37

90°/o

SNCR3

(Low NOx Rate)

$17.1

$0.25

0.84

35%

SNCR4

(High NOx Rate—Cyclone)

$9.9

$0.14

1.31

35%

SNCR5

(High NOx Rate—Other)

$19.5

$0.30

0.90

35%

Natural Gas Reburn6

(Low NOx)

$33.3

$0.50

16%

40%

Natural Gas Reburn6
(High NOx)

$33.3

$0.50

16%

50%

Notes: Low NOx is < 0.5 lbs/mmBtu. High NOx is > 0.5 lbs/mmBtu.

1. Cannot provide reductions beyond 0.05 lbs/mmBtu.

2. SCR Cost Scaline; Factor:

SCR Capital and Fixed O&M Costs: (242.72/MW) 0 35.

For Variable O&M, multiply the VOM value shown in the table by the previous scaling factor. Then, add the constant 0.603212 to the resulting
product.

Scaling factor applies up to 500 MW.

3. LowNOv SNCR Cost Scaling Factor:

Low NOx Coal SNCR Capital and Fixed O&M Costs: (200/MW) 0 577.

Scaling factor applies up to 500 MW.

4. Hish NOv SNCR—Cvclone Cost Scaling Factor:

HighNOx Coal SNCR—Cyclone Capital and Fixed O&M Costs: (100/MW) 0 577

VO&M= 1.27 for MW<300,

VO&M= 1.27- ((MW-300)/100) * 0.015 forMW > 300.

5. Hish NOx Coal SNCR—Other Cost Scaling Factor:

HighNOx Coal SNCR—Other Capital and Fixed O&M Costs: (100/MW)0681

VO&M = 0.88 for MW < 480,

VO&M = 0.89 for MW> 480.

6. Gas Reburn includes $5.2/kW charge for pipeline.

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Page 36

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Table A.I.3.C. Cost of Post-Combustion NOx Controls for Oil/Gas Steam Units (1999 $)

Post-Combustion Control
Technology

Capital
(S/kWi

Fixed O&M
iN/kW/Yn

Variable O&M
(mills/kWh)

Percent Removal

SCR1

28.9

0.89

0.10

80%

SNCR2

9.7

0.15

0.45

50%

Gas Reburn1

20.3

0.31

0.03

50%

Notes:

1. SCR and Gas Reburn Cost Scaling Factor:

SCR and Gas Reburn Capital Cost and fixed O&M: (200/MW)0.35

Scaling factor applies up to 500 MW

2. SNCR Cost Scaling Factor:

SNCR Capital Cost and fixed O&M: (200/MW) 0.577

Scaling factor applies up to 500 MW

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Table A.1.3.d. Cost Components for 80% Mercury Removal Using ACI of Representative 500 MW,
10,000 Btu/kWh Heat Rate Units for Various Control Configurations and Coal Types

Coal Type

Kxisting Pollution
Control Technology

Sulfur
Grade

Capital Cost
(IW)$/kW)

l-'OM
i 1 'mS/kWA n

VOM
(1 yWmills/kWh)

Removal
Efficiency (%)

Bituminous

ESP

13.48

2.21

0.61

ESP/O

13.48

2.21

0.61

ESP+FF

12.50

2.09

0.37

ESP+FGD

3.63

1.03

0.69

ESP+FGD+SCR

ACI not applicable

ESP+SCR

13.48

2.21

0.61

13.48

2.21

0.61

FF+DS

2.34

0.87

0.36

FF+FGD

3.63

1.03

0.69

HESP

3.63

1.03

0.69

HESP+FGD

52.03

6.85

0.31

HESP+SCR

47.00

6.39

0.43

PMSCRUB+FGD

3.63

1.03

0.69

PMSCRUB+FGD+SCR

ACI not applicable

Bituminous

ESP

10.93

1.91

3.54

ESP/O

10.93

1.91

3.54

ESP+FF

6.56

1.38

1.66

ESP+FGD

11.03

1.92

0.11

ESP+FGD+SCR

ACI not applicable

ESP+SCR

10.93

1.91

3.54

10.93

1.91

3.54

FF+DS

2.34

0.87

0.36

FF+FGD

12.98

2.15

0.48

HESP

55.70

1.38

1.75

HESP+FGD

45.28

6.17

0.13

HESP+SCR

55.70

7.45

1.75

PMSCRUB+FGD

11.03

1.92

0.11

PMSCRUB+FGD+SCR

ACI not applicable

Lignite

ESP

16.28

2.61

1.24

ESP+FF

12.09

2.05

0.16

ESP+FGD

14.99

2.39

0.83

FF+DS

1.05

0.72

0.11

FF+FGD

11.34

1.96

0.07

Subbituminous

ESP

16.28

2.61

1.24

ESP+DS

13.47

2.21

0.93

ESP+FGD

12.40

2.08

0.62

ESP+SCR

13.47

2.21

0.93

10.01

1.80

0.12

FF+DS

0.87

0.70

0.08

FF+FGD

9.39

1.72

0.05

HESP

54.44

7.30

0.13

HESP+FGD

54.33

7.28

0.13

HESP+SCR

54.44

7.30

0.13

PMSCRUB

13.47

2.21

0.93

PMSCRUB+FGD

12.40

2.08

0.62

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Table A.1.4. Performance and Unit Cost (1999$) Assumptions for Potential (New) Capacity from
Fossil/Nuclear Technologies in IPM 2000 Base Case

Conventional
Pulverized
Coal

Integrated
Gasification
Combined Cycle

Combined
Cycle

Adv anced
Combustion
Turbine

Combustion
Turbine

Adv anced
Nuclear

Size(MW)

400

428

400

120

160

600

Lead Time (years)

Availability

85%

87.7%

90.4%

92.3%

90.7%

Assumed emission controls

Scrubber, SCR

SCR

None

Vintage #1 (years covered)

2005-2009

Vintage #2 (years covered)

2010 & after

2010-2014

Vintage #3 (years covered)

N/A

2015 & after

Heat Rate (Btu/kWh)

9,253

7,469

6,562

8,567

11,033

10,400

Capital ($/kW)

1,321

1,427

590

438

388

2,465

Fixed 0&M(ykW/yr)

20.08

32.12

12.74

8.93

6.08

50.97

Variable Q&M($/MWh)

3.87

1.10

1.00

2.03

Vinliij;c#2

Heat Rate (Btu/kWh)

9,087

6,968

6,350

8,000

10,600

10,400

Capital ($/kW)

1,305

1,393

563

394

348

2,402

Fixed 0&M(ykW/yr)

20.08

32.12

12.74

8.93

6.08

50.97

Variable Q&M($/MWh)

3.87

1.10

1.00

2.03

Vinliij;c#3

Heat Rate (Btu/kWh)

10,400

Capital ($/kW)

2,276

Fixed 0&M(ykW/yr)

50.97

Variable Q&M($/MWh)

2.03

Note: The capital cost includes both the overnight capital charge rate and the interest during construction.

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Table A. 1.5. Performance and Unit Cost Assumptions for Potential (New) Capacity from
Renewable and Non-Traditional Technologies in IPM 2000 EPA Base Case

Biomass
Gasification
Combined
Cycle

Wind

Fuel
Cells

Solar
Photovoltaic

Solar
Thermal

Cieothermal

Landfill
Cias

Size(MW)

100

First Year Available

2010

2005

Lead Time (years)

Availability

87.7%

90%

87%

85%

Generation capability

Economic
Dispatch

Generation
Profile

Economic
Dispatch

Generation
Profile

Economic
Dispatch

Assumed emission controls

Vintage #1 (years covered)

2010-2030

2005-2030

2005-2014

2005-2030

Vintage #2 (years covered)

2015-2030

Vint sifio #1

Heat Rate (Btu/kWh)

8,219

5,574

32,391

10,000

Capital ($/kW)

1,490

1,031-
2,625*

2,175

2,576

3,187

1,846-6,174z

1,299

Fixed 0&M(ykW/yr)

44.81

26.41

15.00

9.97

47.40

62.40-210.502

78.58

Variable Q&M(yMWh)

5.34

0.00

2.06

0.00

10.48

Vint sifio #2

Heat Rate (Btu/kWh)

5,361

Capital ($/kW)

1,566

Fixed 0&M($/kW/yr)

15.00

Variable Q&M(yMWh)

2.06

Notes:

1. Capital costs for wind plants vary by wind class and cost class.

2. Capital and fixed O&M costs for geothermal plants are site specific.

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Page 40

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Table A.1.6. Capital Charge Rates and Discount Rates by Plant Type in IPM 2000 EPA Base Case

Investment Technology

Capital Charge Rate

Discount Rate

Financing Structure

Environmental Retrofits

12.0%

5.34%

Corporate

Nuclear Retrofits (age 30+10 yrs)

19.0%

5.34%

Corporate

Nuclear Retrofits (age 40+20 yrs)

13.3%

5.34%

Corporate

Repowering of Existing Units

12.9%

6.14%

Project

Coal

12.9%

6.14%

Project

Combined Cycle

12.9%

6.14%

Project

Combustion Turbine

13.4%

6.74%

Project

Renewable Generation Technologies

13.4%

6.74%

Project

Note: The book life of the two nuclear retrofit options is 10 and 20 vears. respectively. All the remaining technologies assume a 30-vear book life.

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A.2. Greenhouse Gas Analysis

While IPM® is a detailed electricity sector model, it cannot assess all GHG emissions and
mitigation opportunities. To develop a more complete picture of GHG emissions and abatement
opportunities, a number of other modeling tools have been utilized. These tools evaluate GHG
abatement opportunities in various sectors both domestically and internationally. This analysis
incorporates the results of the Second Generation Model (SGM), forestry and agricultural models
such as the Forestry and Agriculture Optimization Model (FASOM) and analyses of non-CC>2
GHG emissions and abatement opportunities.

EPA uses emissions reductions and cost data from these models to analyze the total potential for
GHG emission reductions or sequestration achievable and at what cost.22 While the availability
and costs of emissions reductions varies across source categories, this relationship has been
estimated as a broad aggregate for this exercise.

A.2.1. Second Generation Model

DOE's Pacific Northwest National Laboratory's Second Generation Model (SGM) is a 13-
region, 24-sector computable general equilibrium (CGE) model of the world that can be used to
estimate the domestic, and international, economic impact of policies designed to reduce GHG
emissions. Numerous economic analyses have been conducted using the SGM framework both
inside and outside of the government.23

The SGM is a dynamic recursive model. Recursive models are a sequence of static models with
rules for determining the amount of savings and therefore the total amount of new capital
constructed in each time period. SGM uses expectations of future prices to determine savings
and investment. Within the energy sector in SGM, energy-using equipment is "vintaged" to
account for capital turnover and therefore can examine the response of the economy over time to
policy changes.

The SGM is designed specifically to address global climate change issues, with special emphasis
on the following types of analysis:

1. projecting baseline GHG emissions over time for a single country, a group of countries,
or the world;

2. finding the least-cost way to meet any particular GHG emissions reduction target;

3. providing a measure of the carbon price, in dollars per metric ton; and

4. providing a measure of the overall cost of meeting an emissions target.

22 Emission reductions already required by law are accounted for in the baseline emission projections. Potential
emission reductions from voluntary partnership programs are not included in the baseline and therefore are
reflected in future abatement opportunities and the calculation of future abatement costs.

23 Sands etal., 1999.

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For this analysis, EPA used the SGM to obtain estimates of marginal abatement costs for both
the U.S. and international energy sectors (CO2 abatement opportunities from all energy-using
sources). The abatement cost curves are built up from a series of model runs, each of which sets
the carbon price at a fixed level and holds it there for the duration of the run. Abatement costs
are constructed using carbon prices every ten dollars up to fifty dollars.

Outside of the U.S. electricity sector, CO2 offset opportunities exist in the domestic industrial
and transportation sectors, which represent about 60 percent of U.S. energy-related CO2
emissions.24 Industrial energy efficiency projects, fuel switching in industrial boilers, and
emissions improvements in vehicle fleets are examples of possible offset candidates.

Similarly, under the offset scenarios outlined in the letter, the U.S. electricity sector also may
pursue reductions internationally. Given the level of economic growth and associated increase in
CO2 emissions that is predicted in the developing world, the energy sectors in these countries are
anticipated to be a source of inexpensive and abundant offsets. For example, China's energy and
home heating systems are largely dependent on coal. Projects that help shift China away from
coal and towards natural gas, biomass, wind, and other renewables could generate large
quantities of offsets at relatively low cost. Similar opportunities exist in India, Brazil, South
Korea, and the rest of the developing world.

A.2.2. Agricultural and Forestry Models

The models used for the U.S. forestry and agriculture sectors include the Forestry and
Agriculture Optimization Model (FASOM) and the Agricultural Sector Model + Greenhouse
Gases (ASMGHG)25 These models are based on mathematical programming, price endogenous
representations of the forestry and agricultural sectors, modified to include carbon sequestration
and GHG emission accounting. For example, ASMGHG depicts production, consumption, and
international trade in 63 U.S. regions of 22 traditional and three biofuel crops, 29 animal
products, and more than 60 processed agricultural products. FASOM includes carbon production
from forests in the U.S. using data on land diversion, carbon production, and the economic value
of forest products. The data from these models are 30-year average results over the 2000-2029
period.

The international forestry sequestration offsets analysis is based upon a computational model,
Comprehensive Mitigation Assessment Process (COMAP), which estimates "bottom-up"
engineering cost curves for seven key tropical forestry countries—Brazil, China, India,

Indonesia, Mexico, the Philippines and Tanzania—representing about two-thirds of the tropical
forest area in the world. The COMAP model has been developed under the auspices of the F7
Tropical Forestry Climate Change Research Network coordinated by the Lawrence Berkeley
National Laboratory (LBNL) and EPA since 1993. COMAP is a spreadsheet model that runs
from 1990-2100 or as specified, at the national scale, and produces changes in biomass, carbon,

24 USEPA, 2001(a).

25 FASOM was developed by the U. S. Forest Service and Dr. Bruce McCarl. ASMGHG was developed by Bruce
McCarl.

11/02/01

Page 43

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and the net present value for specified forest management practices, forest types, and sub-regions
within countries.

Terrestrial carbon sequestration involves the absorption of atmospheric CO2 and subsequent
storage by trees, plants, and soils. In 1999, terrestrial systems sequestered approximately 270
MMTCE in the U.S. and 1,600 MMTCE worldwide. Below are brief descriptions of
sequestration processes and potential options that were included in this offsets analysis.

However, coverage of forest and agricultural sequestration opportunities in these models is
incomplete. Thus, abatement opportunities may be greater and costs lower than predicted in this
analysis.

Forest Sequestration: As a result of biological processes in forests (e.g., growth and mortality)
and anthropogenic activities (e.g., harvesting, thinning, and replanting), carbon is continuously
cycled within forests ecosystems, as well as between the forest ecosystem and the atmosphere.
As trees age, they continue to accumulate carbon until they reach maturity, at which point they
are relatively constant carbon stores. Offsets from forest-based carbon sequestration can be
stimulated by afforestation of agricultural lands, increasing the rotation length of tree planting
cycles, or changing management intensity through improved silvicultural practices.

The forest carbon sequestration supply curves for the countries covered in the analysis represent
about 35% of the global forest area (including natural forests and plantations). However, this
figure understates the coverage of the analysis since a more accurate comparison would include
the total global potential for forest carbon sequestration. Total global potential is difficult to
estimate at present, but it is likely that if the total global sequestration potential were included in
the analysis, the availability of CO2 offsets would increase, and the allowance prices would
decrease. The countries covered in the analysis include Brazil, Canada (partial), China, India,
Indonesia, Mexico, Philippines, Tanzania, and the United States.

Agricultural Soil Sequestration: In 1999, soils absorbed approximately 71 MMTCE in the U.S.
The amount of organic carbon contained in soils depends on the balance between inputs of
organic matter and the loss of carbon through decomposition. Changing tillage systems from
conventional tillage to minimum and no tillage, as well as reverting cropland back to grassland,
generally increases soil carbon and could provide offsets.

A.3. N011-CO2 GHG Analyses

Non-C02 GHG sources represent about 18 percent of total U.S. GHG emissions and about 32
percent of worldwide emissions.26 Many technologies exist that can reduce emissions of these
gases. In some cases, these technologies are already in use. These technologies may include
recovery of methane emissions for energy, efficiency improvements, end-of-pipe controls
(incineration), leak reduction, and chemical substitution, among others.

Estimates of non-CC>2 marginal abatement curves represent about 35% of global non-CC>2 GHG
emissions. The countries and regions covered in the analysis include Australia, Brazil, Canada,

26 US EPA, 2001(a).

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China, European Union, India, Japan, Mexico, Russia, Ukraine, United States, and New Zealand.
Significant agricultural emissions from rice, livestock, and soils, especially in developing
countries, are not modeled for this exercise give uncertainties regarding GHG abatement
opportunities at this time. The estimates of potential offsets from non-CC>2 GHGs used in this
analysis were derived from extensive bottom-up analyses of the technologies and management
practices that reduce emissions. The sources examined include methane emissions from
landfills, natural gas systems, and coal mines; HFC, PFC, and SF6 emissions from various
industrial sectors; and nitrous oxide emissions from adipic and nitric acid production. In each
analysis, only currently available or close-to-commercial technologies are evaluated. EPA has
assembled these emissions reductions and costs into marginal abatement curves showing the total
emission reductions achievable at increasing monetary values of carbon, for the years 2010 and
2020.27

Two sources provide estimates for international offsets from other gases. First, the European
Commission recently developed data for countries within the European Union.28 Second, EPA
has estimated offset costs in Australia, New Zealand, Brazil, Canada, China, India, Japan,
Mexico, Russia, and Ukraine, based on available information on technologies and country-
specific conditions. The discussion below broadly describes the sources that are included in the
analysis.

Methane: Methane emissions are predicted to offer many low-cost offset opportunities.

Landfills are the largest source of anthropogenic methane emissions in the U.S. Outside of the
U.S., the largest source of recoverable methane is leakage from natural gas systems.

Underground coal mines, livestock waste management, and a diverse group of other sources also
provide potential offsets.

High GWP Gases: High GWP gases include hydrofluorocarbons (HFCs), perfluorocarbons
(PFCs), and sulfur hexafluoride (SFr,), which are important to an array of industrial technologies
and consumer products.29 The sources of high GWP emissions that are examined as carbon
offsets in this analysis include HFCs from refrigeration and air conditioning; PFCs from
semiconductor manufacturing and aluminum smelting; SF6 from magnesium production, parts
casting, and electric power distribution; HFC-23 from HCFC-22 production; and a diverse set of
other source categories.

Nitrous Oxide: The main anthropogenic sources of nitrous oxide are agricultural soil
management, fuel combustion in motor vehicles, and adipic and nitric acid production processes.
However, marginal abatement cost estimates are only available for the adipic and nitric acid
sources, which represent about 7 percent of total U.S. nitrous oxide emissions. Nitrous oxide
emissions are a by-product in the production of adipic acid, which is used in the manufacture of
synthetic fibers, coatings, and lubricants. Nitrous oxide is also a by-product of nitric acid

27 Emission reductions already required by law are accounted for in the baseline emission projections. Potential
emission reductions from voluntary partnership programs are not included in the baseline and therefore are
reflected in future abatement opportunities and the calculation of future abatement costs.

28 Commission of the European Union, 2000.

29 HFCs in particular have become important to the safe and cost-effective phase-out of chlorofluorocarbons
(CFCs), halons, and other ozone-depleting chemicals worldwide.

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production, which is used primarily to make synthetic commercial fertilizer and is a major
component in the production of adipic acid and explosives. Opportunities exist to reduce nitrous
oxides both in the U.S. and internationally.

A.4. The Greenhouse Gas Impacts of the Kyoto Protocol

Other countries reached agreement on the Kyoto Protocol at the meeting of the Conference of
Parties at Bonn on July 23, 2001. If ratified, it would require countries in Western Europe, along
with Canada, Japan, Australia, New Zealand, Russia and Eastern Europe to achieve greenhouse
gas (GHG) emissions reductions of 4.2% below 1990 levels by the time frame of 2008-2012.30
The Accord allows countries to trade GHG emissions reductions amongst themselves, and to
offset their GHG emissions growth by reducing emissions in developing countries. Additionally,
provisions have been made for these countries to receive country-specific credits for forestry and
agricultural carbon sequestration activities. While there is no agreement on actions after 2012,
this analysis assumes that the target of 4.2% below 1990 levels will be maintained through 2020.

Potential GHG Reductions

Calculating potential GHG reductions from the Kyoto Protocol requires estimates of "business as
usual" for emissions of the six GHGs covered by the accord. EPA uses projections for the
emissions of non-C02 greenhouse gases (methane, nitrous oxide, and high GWP gases)
developed by EPA. Emissions projections for CO2 are from the International Energy Outlook
2001 prepared by the U.S. Department of Energy's Energy Information Administration (EIA).

Emissions Growth

For the countries of Western Europe, along with Australia, Canada, Japan, and New Zealand,
CO2 emissions in 2010 are projected by EIA to be 1,666 MMTCE, which represents growth of
approximately 18 percent over 1990 emissions. These countries have proposed to achieve GHG
emissions targets that are approximately 6.7% below their 1990 emissions levels. Factoring in
EPA projections for non-C02 GHG emissions, these countries are projected to be 423 MMTCE
above their agreed targets by 2010. By 2020, CO2 emissions are projected to be 1800 MMTCE,
and factoring in EPA estimates of non-C02 emissions, the countries' emissions are projected to
be 551 MMTCE above their target in 2020.

Former Soviet Union and Eastern Europe

A principal uncertainty in estimating the impact of Kyoto Protocol is GHG emissions trends in
the Former Soviet Union and Eastern Europe. With the collapse of the Soviet Union, economic
activity in the region declined significantly. In the EIA projections, CO2 emissions are projected
to remain low, and when non-C02 emissions are factored in, total GHG emissions are projected
to be below the regional target for by about 377 MMTCE in 2010. The difference in 2020 is
projected to 222 MMTCE.

30 For certain high GWP gases, countries may choose their baseline to be their 1990 or 1995 emissions level.
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Sequestration

The agreement reached at Bonn specifies the number of credits that each country may claim for
forestry and agricultural carbon sequestration activities.31 These credits roughly total 55
MMTCE per year.

Results

Total emissions reductions from the Kyoto Protocol are calculated by adding the negative
emissions growth (some have called this "hot air") in the Former Soviet Union and Eastern
Europe to the emissions growth from the other countries, and subtracting the specified
sequestration credits. Using EIA projections for CO2, the total GHG emissions reduction
required by the Kyoto Protocol is fully offset by FSU and Eastern European "hot air" in 2010.
Thus, the implementing countries may not be required to take additional abatement activity in
2010. However, by 2020, the total emission reduction from the Agreement is roughly 280
MMTCE. (See Tables A.4.1 .a and A.4.1 .b, below.)

Table A.4.1.a. 2010 Emissions Projections using EIA (MMTCE)

AI.I.C.I IC.

1990

2010

Target

GAP

Sinks

Change from Baseline

FSU/EE

1,654

1,251

1,628

-377

-400

Europe/Ja/Can/
AUS/NZ

1,766

2,072

1,649

423

391

All Kyoto Protocol
Countries

3,420

3,323

3,275

.9*

Table A.4.1.b. 2020 Emissions Projections using EIA (MMTCE)

AI.I.C.I IG

1990

2020

Tarucl

GAP

Sinks

Chanuc from Baseline

FSU/EE

1,654

1,405

1,628

-223

-246

Europe/Ja/Can/
AUS/NZ

1,766

2,206

1,649

557

525

All Kyoto Protocol
Countries

3,420

3,611

3,275

336

281

* The -9 MMTCE reduction obtained using EIA CO2 projections implies that no additional
GHG abatement would be required.

Note: Columns may not add due to rounding errors and discrepancies in the source data.

31 See Appendix Z of the Report of the Conference of the Parties on the Second Part of its Sixth Session.
(FCCC/CP/2001/5)

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