AIR POLLUTION IMPACTS OF
THE OIL AND GAS REPLACEMENT PROGRAM
IN THE UTILITY AND INDUSTRIAL SECTORS
EXECUTIVE OFFICE OF THE PRESIDENT
ENERGY POLICY AND PLANNING
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TABLE OF CONTENTS
EXECUTIVE SUMMARY
A. Program Description
B. Environmental Protection Measures
C. Summary of Findings
1
1
3
II. DESCRIPTION OF METHODOLOGY
A. Energy Baseline
B. Emission .Control Assumptions
C. Emission Factors
D. Regional Emission Levels
E. Non-Compliance
F. Limits to the Analysis
11
12
14
17
17
17
18
III. FINDINGS
A. National Emission Levels
1. Particulates
2. Sulfur Dioxide
3. Nitorgen Oxides
4. Sensitivity of Results
B. Regional Emission Levels
1. Particulates
2. Sulfur Dioxide
3. Nitrogen Oxides
20
22
22
22
24
24
26
26
29
Appendix 1: Emissions Projections Assuming NSPS
Appendix 2: Methodology for Emissions Calculations in the
Industrial Sector
Appendix 3: Methodology for Emissions Calculations in the
Utility Sector
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AIR POLLUTION IMPACTS OF THE OIL AND GAS
REPLACEMENT PROGRAM IN THE INDUSTRIAL
AND UTILITY SECTORS
I. EXECUTIVE SUMMARY
The purpose of this paper is to present the results of
analyses of air pollutant emission impacts associated with
the oil and gas replacement program.— The paper focuses
on the industrial and utility sectors, identifying air pol-
lutant emissions from these sectors under the oil and gas
replacement program as well as the entire President's
Program. Analyses of the energy and economic impacts of
the National Energy Plan (NEP) policies on these sectors are
contained in a separate document.— The environmental
analysis relies heavily on the results described in this
earlier document. In addition to presentation of
analytical results, this paper details the methodology
used to calculate the air pollutant emission levels.
A. Program Description
The oil and gas replacement program requires, with certain
exceptions, that all new utility plants and large indus-
trial boilers (greater than 10 MW) must burn coal or other
fuels rather than oil and gas. Authority is also granted
to require use of coal by other new industrial facilities
(non-boilers). In addition to these regulatory provisions,
the program includes taxes on the use of oil and gas by
utilities and large industrial facilities and refunds (or
investment tax credits for industry) for investments in
non-oil and gas facilities or retirements of existing oil
and gas facilities.
B. Environmental Protection Measures
The NEP also contains several provisions designed to
mitigate potential adverse environmental effects from the
expanded use of coal. Specifically, the National Energy
V Also referred to as the Coal Program.
_2/ "Replacing Oil and Gas with Coal and Other Fuels in the
Industrial and Utility Sectors," Executive Office of the
President, Energy Policy and Planning, June 2, 1977.
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Plan'calls for the use of best available control technology
(BACT)—' on all new facilities larger thanv25:MW.
In addition to BACT, the President has-announced several
policies specifically designed to minimize adverse environt
mental impacts from increased coal utilization*! The p©lic»es
most closely related to mitigation of air impacts are the
Clean Air Act Amendments supported by the Administration.
The key provisions of these amendments.are listed below:
o the requirement for a policy for prevention of
significant deterioration,
o disallowance of credit for tall stacks to meet
air quality requirements,
o establishment of non-compliance penalties for
sources which do not meet compliance ;dates or>do
not ojperate and maintain pollution control
equipment adequately, and
o continuation of the current EPA emissions offset
policy in non-attainment areas.
The National Energy Plan also recognizes that it may bec
necessary to continue use of oil and gas in areas where
serious air pollution problems currently exist by allowing
exemptions and exceptions on the basis of environmental
constraints. As a part of the NEP the President called
for a Committee to study:
(1) the health effects of increased coal production
and use, and
(2) the environmental constraints on coal mining
and on the construction of new coal-burning
facilities.
The Committee is scheduled to report its findings by
October 1977.
\J See, Section II for assumptions about BACT.
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C. Summary of Findings
The major air pollutants of concern when burning coal rather
than oil or gas are sulfur dioxide (SO-) particulates
(TSP), and nitrogen oxide (NO ). Figure 1 compares the
national emissions of industries and utilities for each of
these pollutants under several scenarios:
o the 1975 actual emissions
o a 1985 baseline which would occur with no energy
plan
o an estimate of the impacts of the oil and gas
replacement (coal) program alone in 1985, and
o an estimate of the impact of the entire President's
Program in 1985.
The incremental effects of the coal program and the
President's program are identified through comparison with
the 1985 baseline which represents a forecast based on
current trends with no NEP. These emission levels are
combined totals for industrial and utility sources. The
1975 emission levels provide a means for comparison with
current emissions.
All of the 1985 cases assume the use of BACT— on new
sources (i.e., as required by the Clean Air Act-Amendments)
and full compliance with emission requirements.— If the
1985 baseline did not include the BACT provision, the com-
parative emission impacts of the NEP would appear even less
significant since BACT contributes to reductions in the 1985
baseline.—
_!/ BACT is applied to all new utilities which begin
operation after 1984 and to new industrial sources, after
1979.
2/ The emissions impacts assuming New Source Performance
Standard (NSPS) control are presented in Appendix 2.
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FIGURE lw
NATIONAL AIR POLLUTANT EMISSIONS FROM INDUSTRIES AND UTILITIES
S02 EMISSIONS
V
ctL 30
LU
S,
O
-0
2 in
IU
n
1975 1985 1985
ACTUAL BASELINE COAL
(NO PLAN) PROGRAM
1985
(NEP)
TSP EMISSIONS
17'
106 TONS/YEAR
O. tn o tr
••
:^v:.;.!^..>
'. -. .-- ; ::;':;i.". ,,,;,:
. ._;._;•.;.;:_•.•:-•
.,;.;: :"":'; 'I1-/'; !-.
. • '- ' v:, !||.; .•!; >:
1975 1985 1985 1985
ACTUAL BASELINE COAL PRESIDENTS
(NO PLAN) PROGRAM PROGRAM
(NEP)
NOX EMISSIONS
V
LU
15
10
—
1975 19S5 1935 1985
ACTUAL BASELINE COAL PRESIDENTS
(NO PLAN) PROGRAM PROGRAM
(NEP)
I/ The 19B5 cnt.irnatcG assume full compliance with
applicable emission limitations and implementation
of bOKt available control technoloqy (BACT)
provisions; of Clean Ail" Act Amendments.
INDUSTRY
UTILITY
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Major Findings
There are four major findings from the air pollution impact
analysis:
o The oil and gas replacement program causes small
increases in national emissions over the 1985 base-
line. (Figure 1) —
o The national emissions impact of total President's
program is not significantly different than the 1985
baseline. (Figure 1)—
o The relative air pollutant emissions contribution of
the industrial and utility sectors are very different.
Under the NEP emissions in the utility sector decline
while emissions increase in the industrial sector.
o The regional emissions impacts are insignificant in
all regions except Region VI.
These findings are discussed in greater detail below.
Moderate Increases in National Emissions from the Oil and Gas
Replacement Program
As shown in Table 1, the national emissions of SO- and NO are
all predicted to increase above the 1985 baseline when the
oil and gas replacement program is considered alone.— Total
national emissions of TSP from these sectors is not changed
by the program. The majority of the S02 increase is attri-
butable to greater industrial use of coal and reflects the
fact that even under the BACT assumption, emissions when
burning coal are slightly larger than emissions when burning
oil and much larger than when burning gas.
Table 1. Percentage Increases in Emissions Over the 1985
Baseline
Coal Program President's Program
S02 5% -3%
TSP 0% -2%
NO.. 5% 2%
V See Tables 4, 5 and 6.
2/ Since the different policies in the NEP are all inter-
dependent, it is difficult to isolate the effects of
individual policies in this manner.
237-773 O - 77 - 2
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Total increases for S02 and NO are approximately 5 percent,
above the 1985 baseline. If tfie 1985 baseline assumes NSPS
rather than BACT emission controls, S0~ emissions would
increase 3 percent and TSP emissions would decrease 3
percent.
Minimal Impact of the Total President's Program
Table 1 shows that the emissions of TSP, NO and SO,,
predicted to occur under the President's Program are very
close to the 1985 baseline levels: TSP, 2 percent decrease;
S02, 3 percent decrease; and NO ,2 percent increase.
While the oil and gas replacement program contributes to
increased emissions, the load management and conservation
policies in the remainder of the Plan cause a decrease in
total fuel consumption and therefore a reduction in combus-
tion related emissions. These reductions effectively
balance the increases from the,oil and gas replacement
program at the national level.— If the NEP emissions are
compared to a" NSPS baseline in 1985 that does not include
the impacts of BACT, the impacts are as follows: TSP, 2
percent decrease;2S02, 5 percent decrease; and NO , 1
percent increase.—
The only significant national emission increases projected i
to occur between 1975 and 1985 are projected for NO .How-
ever, this increase is common to all the 1985 cases? not just
the NEP scenario. NO emission increases are not related
to the use of different fuels but reflect the lack of highly
effective control technology. Since increases in fuel com<-
bustion are projected in the baseline, NO emission increases
are projected for 1985 both with and without the NEP.
Relative Emissions Contribution of Industries and Utilities
The NEP affects both utility and industrial fuel use;
however, the effects in these two sectors are very different.
Utilities are already planning to burn coal rather than oil
and gas in virtually all new baseload units except for those
currently under construction. While the coal program would
tend to increase coal use (with related oil and gas savings),
?
T/As is *discussed later, this balance is not always evident
at the regional level.
2/ See Appendix 1 for full presentation of results under
this assumption.
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conservation measures would reduce coal consumption. The
net effect is that coal use by utilities in 1985 is projected
to be approximately the same both with and without the
President's Program but oil and gas use by utilities would
be reduced substantially. Therefore, the following percent-
age reductions in emissions from utilities in 1985 occur
under the President's Plan as compared to the 1985 baseline:
Particulates, 8 percent; SO,, 9 percent; and NO , 9 percent.
^ A
The effect of the NEP on the industrial sector is much more
pronounced. By 1985 industrial facilities are projected to
consume almost 200 million more tons of coal per year than
they would without the Plan. Without the Plan it is esti-
mated that industry would continue to burn oil and gas,
chiefly because fuel costs for industry are not as large a
fraction of operating expenses as they are for utilities and
because oil and gas is less troublesome to handle at an
industrial site than is coal. However, significant shifting
from gas and oil to coal is expected under the Plan. As a
result of this increase in coal use, emissions from the
industrial sector will increase in 1985.
The percentage increases in particulate emissions are
insignificant under the NEP. Industrial processes rather
than fuel combustion are the major contributors of industrial
TSP emissions. This analysis has focused on changes in TSP
emission from industrial fuel combustion only since these are
the activities in the industrial sector which are impacted
by the NEP policies. S0~ emissions from the industrial
sector increase by 19 percent in the oil and gas replacement
program and 8 percent under the President's Program when
compared to the 1985 baseline. Comparable NO emissions
increases are 12 percent and 17 percent.
Regional Trends
In general, regional emissions estimates reflect the major
trends discussed above. The results are summarized below
for each pollutant under the oil and gas replacement program
and under the entire President's Program. Tables 9, 10 and
11 in Section III provide the background material for this
summary. (See Figure 2, Federal Regions)
Oil and Gas Replacement Program
Emissions of TSP increase in four regions (V, VI, VII,
and IX) under the oil and gas replacement program as
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Figure 2 Federal Regions
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compared to the 1985 baseline. The increases range
from 1 percent (Region V) to 3 percent (Region IX).
TSP emissions either decrease or are unchanged in other
Regions.
SO emissions increase in every region under the oil
anci gas replacement program. The range of increase over
the 1985 baseline is from 2 percent (Region I) to 31
percent (Region VI). Most of the regional emissions
increases are about 3 to 4 percent.
NO emissions also increase in every Region. This
increase ranges from 2 percent (Regions I and II) to
12 percent (Regions VI and IX).
Total President's Plan
Particulate emissions decrease or remain unchanged in
every Region except Region IX (where there is a 1
percent increase) under the President's Program as
compared to the 1985 baseline. This decrease ranges
from 1 percent (Regions IV, VI, and VII) to 4 percent
(Region I).
Only three Regions show increases in SO- emissions
under the President's Program: Region VI, 30 percent;
Region VIII, 6 percent; and Region X, 12 percent. All
other regions exhibit decreases ranging from 1 percent
(Region III) to 16 percent (Region I).
NO emissions also increase in three regions under
the President's Program: Region VI, 22 percent; Region
VIII, 9 percent; and Region X, 38 percent. Decreases
in NO emissions range from 2 pecent (Regions I, III,
and Vy to 10 percent (Region II).
If regional impacts of the oil and gas replacement program
and the NEP are compared to a 1985 baseline which does not
include BACT, comparative impacts are smaller. (See Appendix
1 for regional results under this assumption.)
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10
Qualifications and Assumptions
These national and regional emissions do not indicate
how the coal program is expected to affect attainment -of
air quality standards in specific areas of the country.
There are some areas where additional use of coal
could impair attainment of health standards. However,
the NEP was developed assuming that increased coal use
would not occur, and should not be allowed, in some
areas due to environmental constraints.
Assumptions which are important to interpretation of
the analysis include:
(1) all existing facilities will comply with applicable
emission limitations in the state implementation
plans (SIP) by 1985. The validity of this assump-
tion depends on effective enforcement effort by
both* the State and the Federal Governments.
(2) BACT controls for S02 will require scrubbers on
large boilers (above 25 MW). Scrubbers are assumed
to have 90 percent effective S02 removal and to
be available 90 percent of the time (i.e., 80 per-
cent efficient).
(3) a revised new source performance standard of 1.5
Ibs S02/MMBtu covering boilers between 10 MW and
25 MW will be promulgated.
(4) BACT will apply to new utilities beginning opera-
tion in 1984 and industry beginning operation in
1979.
(5) the NEP will be implemented as proposed. Under
the entire energy plan, the conservation measures
and the programs which free up gas for use in the
residential and industrial sectors are particularly
important for producing the offsetting emission
reductions under the entire plan.
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11
Analysis of the effects of the oil and gas replacement
program and of the entire NEP in 1990 will be issued in
a supplementary document. Most of the effects of the
coal conversion program in the industrial sector are
expected to occur by 1985. However, both the oil and
gas replacement program and the conservation measures
are expected to have a larger impact on the utility
sector in 1990 than in 1985.
The remaining sections of this paper discuss the methodology
used to calculate emissions and present more detailed air
pollutant emission results.
II. DESCRIPTION OF METHODOLOGY
There are four basic steps to the methodology for calculating
emission impacts of SO.,, TSP, and NO :
^ A
(1) Estimate the type and quantity of fuel consumed in
each scenario (e.g. , 1975, 1985 baseline,
President's Program, and Oil and Gas Replacement
Program) by certain categories of industrial and
utility users.
(2) Construct different cases which represent a range
of potential emission control assumptions.
(3) Calculate the emission factors for S0», TSP, and
NO which are applicable to new and existing
facilities under these cases, and
(4) Determine national and regional emission levels.
The approach in each sector differs somewhat. However,
Appendix 2 provides a detailed accounting of the methodology
used in the industrial sector and Appendix 3 describes the
methodology used in the utility sector.
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12
A. Energy Baseline
Construction of the energy baseline was accomplished
primarily through the FEA Project Independence (PIES)
model.— The first step in formulating the baseline was
to forecast the fuel type (oil, gas, coal, other) and
quantity of fuel used in each sector. This is a function of
fuel prices and other economic factors input to PIES as well
as the impacts of specific provisions of the NEP such as
conversions to coal and load management. Table 2 provides
several different energy scenarios for the industrial and
utility sectors:
o actual 1975
o 1985 baseline without the NEP
o 1985 with the oil and gas replacement program alone
o 1985 with the entire President's Program.
These energy scenarios are used consistently throughout the
analysis.
After obtaining the breakout by fuel type and quantity in
each sector it was necessary to apportion these totals to new
as opposed to existing units. It was further necessary to
determine what percentage of fuel is~used in large installa-
tions (greater than 25 MW) and small— installations (from
10-25 MW, industrial only). All of these refinements are
necessary because different emission regulations may apply to
small vs. large, new vs. existing units.—'
_!/ For a detailed explanation of the energy impact numbers
see Appendices A and B to "Replacing Oil and Gas with
Coal and other Fuels in the Industrial and Utility
Sectors." This PIES baseline was adjusted for the
utility sector as described in Appendix 3 of this paper,
2/ Very small installations (less than 10 MW) were not
considered in this analysis.
This methodology is explained in detail in a separate
report "The Replacement of Oil and Gas with Coal and
Other Fuels in The Industrial and Utility Sectors"
Appendix A.
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13
TABLE 2: Energy Used for Fuel Combustion
in the Industrial and Utility
Sectors
INDUSTRIAL SECTOR-/
Oil
(oil
Gas
equivalents
Coal
(ICTtons)
MMB/D)
1975
1985
1985
1985
Baseline
Coal Program
(Savings over
1985 baseline)
President1 s
Program—
1
3
(0
1
.4
.8
• 9)
.6
3
3
(1
3
.8
.9
.3)
.5
63
101
300
278
Increase in
Coal Use over
1985,Baseline;
(10 tons)
199
177
Oil
UTILITY SECTOR
Gas
(oil equivalents
MMB/D)
1975
1985 Baseline-/
1985 Coal Program
(Savings over
1985 baseline)
1985 President's
Program—
1.3
2.3
(0.7)
LSI/
1.6
0.9
(0.4)
0.5
404
763
860
779
Increase in
Coal Use over
1985,Baseline;
(10 tons)
97
16
V This does not include oil and gas feedstock and metallurgical coal,
2/ The President's Program includes the effects of the coal program
and conservation policies.
3/ PIES run A148524C.
V PIES run A158569C. (There was a technical error in the PIES
specifications for this run. The effect of correcting this error
is estimated to be that oil consumption would be 1.2 MMB/D)
237-773 0-77-3
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14
The most important information from the^ standpoint of
emissions impacts is where the increased coal is used. As
shown in Table 2, the majority of increased coal use in 1985
occurs in the industrial sector. When the increase in
industrial coal from the coal program is combined with the
increase in the baseline between 1976 and 1985, the addi-
tional demand is apportioned as follows:
o new energy facilities - 81 percent
o existing facilities with capability to burn coal -
9 percent
o accelerated replacement of existing oil-and-»gas-
fired facilities - 10 percent
Almost all of the increased coal use in the utility sector
occurs in replacement or new coal-fired facilities both of
which are subject to new source emission limitations. As a
result over 9>0 percent of the increased coal use between
1976 and 1985 is subject to either new source performance
standards (NSPS) or best available control technology
(BACT).-7
B. Emission Control Assumptions
There is some uncertainty about emission control require-
ments that will apply to new and replacement facilities
converting to coal in the 1985 time frame. The uncertainty
can be categorized into three areas:
o status of the proposed Clean Air Act Amendments
o_ definition of BACT, and
o emission control requirements for small facilities*
Several cases were developed for this analysis to represent
differing assumptions about each of these variables. Tneie
cases are summarized on Table 3. Different emission control
requirements apply to new vs. existing sources.
I/ Assuming that a revised new source performance standard
is* promulgated for facilities between 10MWeto 25 ipj. In
any case, 90 percent of the facilities would undergo
new source review.
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15
TABLE 3: Range of Emission Control Assumptions
NEW SOURCES
EXISTING
SOURCES
Case 1: S02
TSP
NOx
Case 2: S02
TSP
NOx
Case 3: SO2
TSP
NOx
Case 4:-/S02
TSP
NOx
Large-/
BACT(90%)-/
BACT(0.01
MMBTU )
NSPS
BACT(80%)-/
BACT(0.05 lb/
MMBTU )
NSPS
BACT(80%)
BACT(0.05 lb/
MMBTU )
NSPS
NSPS
NSPS
NSPS
Small-/
1.5 Ib/MMBTU-/ SIP
0.03 Ib/MMBTU SIP
1.5 Ib/MMBTU SIP
0.05 Ib/MMBTU SIP
SIP SIP
SIP SIP
SIP SIP
SIP SIP
* *
Emission factors for these sources of NOx were obtained
from AP-42, "Compilation of Air Pollutant Emission
Factors," and reflect uncontrolled emissions.
V Utilities and industrial boilers greater than 25 MW
(250 MMBtu/D).
2/ Boilers between 10 MW and 25 MW.
V This assumes 90 percent efficiency and 100 percent relia-
ability from scrubber equipment as well as coal cleaning,
V This assumes a revision of current NSPS to cover small
boilers, which are not now regulated by current NSPS.
_5/ This assumes 90 percent efficiency and 90 percent relia-
ablity from scrubber equipment as well as coal cleaning.
6/ This case assumes no change in the current Clean Air Act,
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16
Three of the four cases used in this analysis are described
below. Cases 1 and 4 provide the bounds on the ranges of
emission estimates because of the assumptions about BACT.
Case 2 was chosen as the most probable case so the assump-
tions implicit in Case 2 are described in greatest detail.
Case 1 represents the most stringent environmental
requirements. The BACT level for S02 called for removal
of 90 percent of the sulfur from locally available coals.
The TSP controls assume a 99.8 percent reduction from BACT
for large sources. For small sources (10 to 25 MW), revised
NSP&V Of 1.5 pounds per MMBtu for S02 and 0.03 pounds
per MMBtu for TSP were assumed. All existing sources were
assumed to meet SIP. NO emissions were assumed to meet
NSPS. x
Case 4 represents the least stringent environmental control
requirements. Current NSPS for S02, TSP, and NO were
assumed to apply to all existing sources greater than 25 MW
capacity. All existing sources and smaller facilities (10
to 25 MW) are assumed to meet SIP for TSP, S00 and NO .
^ X
The results of Case 2 are presented throughout this paper.
Case 2 was considered the most realistic case for several
reasons. The BACT level for S02 reflects 80 percent
removal of S0~ from locally available coal. This assumes
90 percent efficiency and 90 percent reliabilty from S02
scrubbers which provides for some possible deterioration of
efficiency or unavailability.
The TSP control level for Case 2 is 99 percent which can be
met by an S02 scrubber or with an electrostatic precipi-
tator or bagnouse where scrubbers are not required. This
case also includes revised NSPS for small new sources.
These levels of control on new and modified sources are
reasonable based on activities already underway in EPA to
revise current NSPS.
The impacts estimated under the assumptions in Cases 1 and 4
described above are used to provide some insight into the
sensitivity of the results. Case 4 estimates are included
in Appendix 1 at a comparable level of detail to the Case 2
impacts.
I/ New source performance standards,
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17
C. Emission Factors
The emission control assumptions cases described above were
structured to determine what emission factors would be
applicable in the analysis. Emission factors are keyed to
fuel use (oil, gas, and coal) and the level of environmental
control required.
Emissions from new sources are regulated at the Federal
level (NSPS or BACT). However, variability in emissions of
SO- when using coal under BACT will occur because of the
varying sulfur content of the coal burned. Therefore, it is
necessary to have a different set of emission factors for
each region which are based on the coal used and the 80
percent BACT control requirement.
Emissions from existing sources must meet SIP requirements.
These requirements vary from state-to-state and often from
county-to-county. In order to calculate regional emissions
for industries, these SIP requirements were weighted to
reflect the percentage of fuel of a certain type which had
to conform to each requirement. These weighted factors
were then aggregated to the regional level.
D. Regional Emission Levels
In general, emission levels are a function of fuel mix and
emission factors for each type of fuel. The energy baseline
and the NEP scenarios must be presented in terms of the mix
of oil, gas, and coal in each region. The percentage of
each of these fuels burned in new versus existing and small
versus large sources also must be identified in every
region. Then the emission factors denoted in Step 3 above
are applied to each of these classes of use to calculate
total emissions on each fuel. The total of emissions on all
fuels consumed by industries added to a similar total for
utilities in each region provides the impact numbers
presented in this document.
E. Non-Compliance
A key assumption in all of the 1985 energy scenarios is that
there will be full compliance with the Clean Air Act, either
current or as amended. This assumption is particularly
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18
important with respect to TSP where the current rate of
non-compliance is very high. If this assumption proves to
be optimistic then the 1985 TSP emission levels would not
show the significant improvements over the 1975 levels
illustrated in Figure 1.
It should also be noted that the proposed amendments to the
Clean Air Act, which are supported by the Administration,
call for non-compliance penalties. The probable enactment
of the Clean Air Act amendments including such penalties
reinforces the full compliance assumption.
F. Limits to the Analysis
There are several important factors which were not included
in this analysis due to time constraints, lack of data, and
other considerations. It is necessary to recognize these
factors so that the results which are presented may be put
into an appropriate context. Four major considerations are
listed below:
o local, site-specific impacts
o new national ambient air quality standards (NAAQS)
o environmental limits to coal supply and use, and
o institutional factors.
These concerns include areas where the program impacts are
not fully identified as well as constraints which may limit
the full potential of the program.
Local impacts: The national and regional emission estimates
provide little insight into local or site-specific prob-
lems. Such problems must be identified on a case-by-case
basis. No analysis of the potential for and severity of
site specific problems has been done to date. However, over
90 percent of the increased coal use is in new facilities
subject to NSPS or BACT and significant deterioration and
non-attainment policies can be used to assure the protection
of public health.
New NAAQS; In the time frame between 1977 and 1985 it is
possible that additional new ambient air quality standards
may be promulgated for sulfates, short term NO , and fine
particulates. This analysis only estimates impacts for par-
ticulates, SO., and NO . The estimation of constraints to
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19
coal use due to the additional pollutants listed above is not
possible because of the uncertainty concerning the timing,
level, and emission control implications of future ambient air
quality standards. Similarly, the effects of this program on
C02 levels has not been addressed.
Environmental Limits to Coal Use. The primary constraints on
increased coal use are expected to arise from non-attainment
and air quality maintenance considerations. This analysis
accounts for such constraints in a rough manner by approxi-
mating the new fuel use that might be eligible for exemptions
or the existing fuel use which might not be capable of con-
verting to coal due to environmental constraints. Further
refinement at the site-specific level is necessary because
air quality problems from coal combustion, particularly SO-
and TSP, are very site-specific problems.
Institutional Factors; Delays may be experienced in the
implementation of the oil and gas replacement program. These
delays may occur as a result of legislative delays, long lead
times for siting of facilities, or time requirements for pur-
chase and installation of equipment. The effect of these
delays would be to spread the conversions over a longer time
period therefore reducing emissions impacts in 1985. In addi-
tion, delays in the implementation of BACT requirements could
occur past the 1984 and 1979 dates assumed for utilities and
industries in this analysis. The impact of a delay in BACT
would be an increase in 1985 emission levels.
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20
III. FINDINGS
This section presents the air pollutant emission impacts
of the coal program and the entire President's Program.
The following estimates are provided for each energy
scenario:
o national emissions from the industrial and
utility sectors for TSP, S0» and NO
£t X
o regional emissions of TSPf S09 and NO , and
^ A
o an indication of sensitivity of the predicted
impacts.
Before presenting the results of the analyses, it is useful
to have some perspective on the proportion of total emis-
sions which -is represented by the industrial and utility
categories in this analysis. Table 4 presents total national
emissions in 1975 as a function of source categories. The
importance of industrial and utility sources to the total
emissions is heavily dependent upon the specific pollutant.
In the case of TSP, combustion sources represent 37 percent
of the total emissions, whereas for S02 they represent 80
percent and for NO approximately 50 percent. It is
important to note £hat this analysis is confined to the
effect of NEP policies on the emissions contribution from
only the industrial and utility sectors.
One additional point of clarification is necessary. All
emissions from industrial sources are included in this
analysis (e.g., total 1975 TSP emissions for the industrial
sector of 11.2 MT/year consist of 2.5 MT/year from industrial
fuel combustion and 8.7 MT/year from industrial process
sources as shown in Table 4). However, only those industrial
emissions due to fuel combustion (boiler and non-boiler) are
affected by the oil and gas replacement program. The
process emissions are assumed to remain the same in each of
the three 1985 scenarios.
Although it is not included in this analysis there is an
important secondary impact of the oil and gas replacement
program. The shifts from gas to coal and the reduction in
gas use due to the gas pricing policy free up gas for use in
the residential/commercial sector. The replacement of oil
with gas in the residential commercial/sector will result in
-------
21
TABLE 4: Nationwide Emission Estimates for,all Source
Categories, 1975 Preliminary—'
(106 tons/year)
Source Category
Transportation
Stationary Fuel Combustion
Electric Utilities
Industrial
Other
Total
Industrial Processes
Solid Waste
Miscellaneous
Total
Particulates— 7
1.3
3.5
2.5
.6
6.6
8.7
0.6
0.8
18.0
%
(7)
(37)
(48)
(3)
(4)
(99)
so2
0.8
21.0
5.0
0.3
26.3
5.7
0.1
0.1
32.9
%_
(2)
(80)
(17)
(-)
(99)
NO
x
10.7
6.8
4.9
0.7
12 .4
0.7
0.2
0.2
24.2
%
(44)
(51)
(3)
(1)
(1)
(99)
V Source: EPA National Emission Data System (NEDS). This is preliminary
data and has been updated by EPA at other places in this analysis.
2/ TSP concentrations can be significantly affected by natural,
agricultural, and other sources of fugitive dust. These sources are
not included in this total.
237-773 O - 77 - 4
-------
22
a decrease in emissibns from this sector. These emissions
benefits are not considered in this analysis.
A. National Emission levels
The national emission levels of TSP, S02 and N0x estimated
for each of the energy scenarios are contained on Tables 5,
6, and 7. The discussions below consider each pollutant
individually-
1. Particulates
As shown in Table 5, the oil and gas replacement program
causes a negligible increase in TSP emissions in 1985 and a
1 percent increase in the industrial sector. The impact of
the entire President's program is a slight decrease in
emissions of TSP; 2 percent as compared to the 1985 baseline.
This decrease occurs because of conservation effects of the
total program which cause an 8 percent decrease in utility
emissions of »TSP. The significant reductions in the 1985
baseline over 1975 reflect the assumption of compliance in
1985 as compared to the high levels of non-compliance in
1975.
2. Sulfur Dioxide
Table 6 presents the national emissions of SO^ from
industries and utilities. The most notable impacts occur in
the industrial sector where emissions increase by 19 percent
over the 1985 baseline in the oil and gas replacement program,
and by 8 percent in the total President's Program. The
emissions reductions in the utility sector are attributable
to reduced fuel combustion because of conservation and load
management. The reduction in SO^ emissions from utilities
(9 percent over the 1985 baseline) causes an overall decrease
of 3 percent in S02 emissions under the President's
Program.
-------
23
TABLE 5: National Emissions of TSP From Industries and
Utilities
Source
Industry
Utility
Total
TABLE
Source
Industry
Utility
Total
1975
Actual
(10 tons)
11.2
3.1
14.3
1985
Baseline
(10b tons)
11.2
1.3
12.5
6: National Emissions of
Utilities
1975
Actual
(10° tons)
10.8
18.6
29.4
1985
Baseline
(10b tons)
10.8
20.2
31.1
1985
Coal
Program , /
(10 tons) %=r
11.3 (+1%)
1.2 (-8%)
12.5 (0%)
1985
President
Program
(10b tons)
11.2
1.2
12.3
's
%i/
(0%)
(-8%)
(-2%)
SO- From Industries and
1985
Coal
Program , /
(10 tons) %=*
12.8 (+19%)
19.9 (-1%)
32.7 (+5%)
1985
President
Program
(10 tons)
11.7
18.3
30.1
's
&
(+8%)
(-9%)
(-3%)
V
% change from 1985 Baseline
-------
24
3. Nitrogen Oxides
As shown in Table 7, total national emissions of NO will
increase about 2 percent due to the President's Program as
compared to the 1985 baseline. This alight overall increase
is the result of increases in the industrial sector (17 per-
cent) balanced by decreases in the utility sector (9 per-
cent). Table 7 also shows that significant increases of
NO, emissions are predicted in 1985 as compared to the
actual 1975 levels regardless of whether or not the NEP is
implemented. This increase in NO emission is caused by
general growth, and the lack of highly effective control
technology rather than alternative fuel use.
4. Sensitivity of Results
Table 8 provides estimates of the sensitivity of the
analytical results. The totals represent the range of
emissions impacts calculated for all four of the cases
described in Table 3. (Case 1 provides the lower bound and
Case 4 the upper bound). As Table 8 shows, the range of
estimates for particulates is very small. The range for
S02 is considerably greater especially in the industrial
sector.
TABLE 7: National Emissions of NO From Industries and
Utilities x
1985 1985
1975 1985 Coal President's
Source Actual Baseline Program ,, Program
(10° tons) (10° tons) (10° tons) %i' (105 tons)
Industry 6.0 6.6 7.4 (12%) 7.7 (17%)
Utility 6.6 9.0 9.0 (0%) 8.2 (-9%)
Total 12.6 15.6 16.4 (5%) 15,9 (2%)
I/ percent change from the 1985 baseline.
-------
25
TABLE 8: Range of National Emissions Predicted for
Industries and Utilities —'
(106 Tons)
PARTICULATES
Scenario
1975 Actual
1985 Baseline
1985 Coal Program
1985 President's Program
Industry
11.2
11.2-11.4
11.2-11.8
11.1-11.7
2/
Utility
3.1
1.2-1.2
1.2-1.3
1.2-1.2
SO,
1975 Actual
1985 Baseline
1985 Coal Program
1985 President's Program
10.8
10.7-12.4
12.3-16.6
11.3-15.9
18.6
19.7-20.2
19.3-20.2
17.8-18.3
_!/ This table presents the results of the four cases decribed
in Table 3. Case 1 (stringent BACT) results represent the
lower bound and Case 4 (current NSPS) results, the upper
bound. Only one case was considered for NO .
A
2/ The results for Case 3 are not shown in the above table.
Case 3 assumes that no revised NSPS for small boilers
is promulgated and that small boilers (less than 25 MW)
are subject to SIP. Utility emissions do not vary under
this assumption. The results from Case 3 for industry
are as follows:
1985 Baseline 11.2
1985 Coal Program 14.8
1985 President's Program 14.0
TSP
11.3
11.6
11.8
Only one case was analyzed for NO
-------
26
This range reflects the variation between application of NSPS
and BACT. Even though the case presented in the analysis
(Tables 5, 6, and 7) is not the most stringent BACT case,
the impacts predicted are very close to the low end of the
range.
B. Regional Emission Levels
Regional emissions of particulates, S02, and NO were
calculated for both industries and utilities in each of the
energy scenarios. The results are presented on Tables 9,
10, and 11. These estimates should be considered as interim
projections because work is still underway to refine them
further. Special care should be taken in interpreting small
differences when the totals are small since PIES does not
have the capability to accurately site power plants. The
discussion below addresses each pollutant separately.
The most significant regional impacts occur in Region VI in
the form of increased S02 emissions. These increases occur
for several reasons, all of which are related to the current
reliance of this region on natural gas. First, the 1985
baseline S02 emissions are over two times as large as the
1975 levels for S0_. This occurs because of increased
utility use of coal between 1975 and 1985 in the baseline.
While utility emissions do not increase significantly in
Region VI under the NEP, compared to the 1985 baseline,
industry emissions approximately double due to increased
coal use. As a result, the President's Program shows a 30
percent increase over the 1985 baseline in Region VI.
Emissions of NO also increase in Region VI under the coal
program (12 percent) and the President's Program (22 per-
cent). The increase under the coal program is due to
replacement of oil with coal which has higher NO emissions.
Under the President's Program, conservation measures "free
up" some gas which replaces oil in Region VI. Emissions of
NO on gas are higher than those from oil, thus NO emis-
si&ns increase further with the incremental use ofxgas under
the President's Program.
1. Particulates
As shown in Table 9, the regional emission trends for
particulates conform closely to the national trends in that:
-------
TABLE 9: Projected Particulate Emissions From Utilities and Industries by Region (10 Tons)
1985
Federal 1975 1985 Change: Coal Change: 1985
Region Actual Base Coal Program Program President's Program President's Program
(from 1985 base) (from 1985 base)
I Utility 40 30 0 30 -10 20
Industry 210 210 ^ 210 0 210
Total 250 240 0 240 -10 230
II Utility 120 40 0 40 0 40
Industry 550 550 0_ 550 0, 550
Total 670 590 0 590 0 590
III Utility 500 100 0 100 0 100
Industry 1280 1280 j) 1280 _0 1280
Total 1790 1380 0 1380 0 1380
IV Utility 1050 270 -20 250 -30 240
Industry 2490 2490 10 2500 -10 2480
Total 3540 2760 -10 2750 -40 2720
V Utility 990 400 0 400 -10 390
Industry 3040 3040 ^0 3060 -50 2990
Total 4030 3440 20 3460 -60 3380
VI Utility 130 170 -20 150 -30 140
Industry 1210 1210 30 1240 20 1230
Total 1340 1380 10 1390 -10 1370
-------
TABLE 9: Projected Particulate Emissions From Utilities and Industries by Region (10 Tons) (Cont)
Federal
Region
1975
Actual
VII Utility 190
Industry 1040
Total 1230
1985
Base
Change:
Coal Program
(from 1985 base)
0
1£
10
1985
Coal
Program
110
1050
1160
Change:
President's Program
(from 1985 base)
-10
0
-10
1985
President's Program
VIII Utility 80
Industry 400
Total 480
IX Utility 30
Industry 660
Total 690
X Utility 0
Industry 330
Total 330
90
400
490
30
660
690
10
330
340
-10
10
0
10
10
20
80
410
490
40
670
710
10
330
340
-10
0
-10
0
10
10
0
-10
-10
80
400
480
30
670
700
10
320
330
co
National
Utility 3140 1250
industry 11200 11210
Total 14340 12460
40
90
1210
11300
12510
-100
-40
-140
-------
29
1) there is no significant impact from the President's
Program; and 2) the Coal Program causes small increases
which are usually offset by the entire NEP. This does not
reflect any impact of the NEP but rather the non-compliance
in 1975 and assumed compliance in 1985.
2. Sulfur Dioxide
Table 10 shows that regional emissions of SO^ would increase
slightly under the oil and gas replacement program but would
decrease again under the total President's Program. The most
significant increases in emissions of S0~ occur in Region VI
and are 30 percent over the 1985 baseline under the Coal
Program and the President's Program. These increases occur
for reasons outlined above. Regions IV and V both show
decreases when comparing the President's Program to the 1985
baseline. In general, regional utility emissions of S02 are
less under the President's Program than for the 1985 base-
line. In all but three regions (VI, VII, VIII) this decline
offsets industrial increases in SO- emissions. It should
be noted that increases in S0~ emissions occur in most
regions (I, IV, VI, VII, Vlllf IX, X) in the 1985 baseline
as compared to 1975. This occurs because of increased coal
use by utilities in these areas.
3. Nitrogen Oxides
Table 11 presents the regional estimates of NO emissions
for each energy scenario. It should be recognized that these
results represent NSPS assumptions rather than BACT, since
BACT for NO has not been assumed in this analysis.
H
Every region shows an increase in NO emissions from the
1975 levels, however, this result shows up in the 1985 base-
line as well as the NEP cases. This impact is explained by
the fact that highly effective NO controls are not cur-
rently available so growth in sources translates directly to
growth in emissions.
Region VI experiences the most substantial increases in NO
emissions: 22 percent in the President's Program over thex
1985 baseline. In fact, Regions VI and X are the only
regions in which NO emissions increase under the
President's Program as compared to the 1985 baseline.
-------
30
NO emissions from the utility sector decrease in almost
every region due to conservation and reduced fuel use. The
regional industrial emissions increase in the Coal Program
and either remain the same or decrease under-the President's
Program. Region VI is the most important exception where
industrial NO emissions increase substantially (30%) under
the Presidents Program as compared to the Coal Program
for reasons described in a previous section.
-------
TABLE 10: Projected S0_ Emissions from Utilities and Industries by Region (10 Tons)
Federal
Region
1975
Actual
I Utility 220
Industry 230
Total 450
1985 Change:
Base Coal Program
(from 1985 base)
400 -10
230 20
630 10
1985
Coal
Program
390
250
640
Change:
President's Program
(from 1985 base)
-50
-50
-100
1985
President's Program
350
180
530
II Utility 780
Industry 590
Total 1370
III Utility 3120
Industry 1500
Total 4620
IV Utility 5010
Industry 2060
Total 7070
760
600
1360
2820
1510
,4330
5130
2060
7190
-10
_50
40
-30
160
130
-80
260
180
750
650
1400
2790
1670
4460
5050
2320
7370
-130
50
-80
-170
110
-60
-740
-50
-790
630
650
1280
2650
1620
4270
4390
2010
6400
u>
V Utility 7550 6450
Industry 3730 3740
Total 11280 10190
-240
460
220
6210
4200
10410
-350
-230
-580
6100
3510
9610
VI Utility 160
Industry 690
Total 850
1920
690
2610
80
730
810
2000
1420
3420
0
790
790
1920
1480
3400
-------
TABLE 10: Projected SO, Emissions from Utilities and Industries by Region (10 Tons) (Cont)
Federal
Region
1575
Actual
VII Utility 1300
Industry 660
Total 1960
1800
660
2460
Change:
Coal Program
(from 1985 base)
-10
90
80
1985
Coal
Program
1790
750
2540
Change:
President's Program
(from 1985 base)
-300
80
-220
1985
President's Program
VIII Utility 240
Industry 230
Total 470
400
230
630
IX Utility
Industry
Total
X Utility
Industry
Total
180
980
1160
40
140
180
420
990
1410
110
140
250
Utility 18600 20210
Bidustry 10810 10850
Sfefcal 29410 31060
60
-10
70
~60
0
60
60
400
290
690
110
200
310
19900
12810
32710
-1870
870
-1000
400
270
670
290
1090
1380
110
170
280
18340
11720
30060
U)
-------
TABLE 11: Projected NO Emissions From Utilities and Industries by Region (10 Tons)
1985
Federal 1975 1985 Change: Coal Change: 1985
Region Actual Base Coal Program Program President's Program President's Program
(from 1985 base) (from 1985 base)
I Utility 200 210 0 210 -30 180
Industry 230 250. .10 260 20 270
Total 430 460 10 470 -10 450
II Utility 650 720 -10 710 -160 560
Industry 550 600 30 630 30 630
Total 1200 1320 20 1340 -130 1190
III Utility 1090 1280 -10 1270 -80 1200
Industry 680 760 70 830 40 800
Total 1770 2040 60 2100 -40 2000
IV Utility 1120 1620 0 1620 -170 1450
Industry 910 1000 100 1100 70 1070
Total 2030 2620 100 2720 -100 2520
V Utility 1860 2260 0 2260 -80 2180
Industry 1420 1580 130 1710 20 1600
Total 3280 3840 130 3970 -60 3780
VI Utility 690 1330 50 1380 -110 1220
Industry 930 1030 240 1270 -630 1660
Total 1620 2360 290 2650 520 2880
-------
TABLE 11:
Projected NO Emissions From Utilities and Industries by Region (10"
A
Tons) (Cont)
Federal
Region
1975
Actual
VII Utility 440
Industry 430
Total 870
1985 Change:
Base Coal Program
(from 1985 base)
680 0
470 30
1150 30
1985
Coal
Program
680
500
Change:
President's Program
(from 1985 base)
-30
30
1985
President's Program
650
500
1180
1150
VIII Utility 170
Industry 200
Total 370
IX Utility 300
Industry 460
Total 760
X Utility 40
Industry 190
Total 230
National
450
230
680
380
510
890
50
210
260
0
1P_
30
0
1P_
40
0
iP.
30
450
260
710
380
550
930
50
240
290
-40
20
-20
-50
70
~20
-30
80
50
410
250
660
330
580
910
20
290
310
10
Utility 6560 8980
Industry 6000 6640
Total 12560 15620
30
710
740
9010
7350
16360
-780
1010
230
8200
7650
15850
-------
1-1
Appendix 1; EMISSIONS PROJECTIONS ASSUMING NSPS^'
This Appendix contains the results of Case 4 of the
analysis defined in Section II (See Table 3). This repre-
sents application of NSPS rather than BACT as assumed in
Case 2 for all of the 1985 cases. Both regional and
national results are provided below. Only TSP and S02 are
included because the NO case presented in the paper assumes
NSPS. x
Table A-l. NATIONAL EMISSIONS FROM INDUSTRIES AND UTILITIES - NSPS
(10 Tons)
PARTICULATES
1975
1985 BASELINE
1985 COAL PROGRAM
1985 PRESIDENT'S
PROGRAM
INDUSTRY
UTILITY
TOTAL
11.2
3.1
14.3
11.4
1.2
12.6
11.8
1.3
13.1
(4%)
(8%)
(4%)
11.7
1.2
(3%)
(0%)
12.9 (2%)
SULFUR DIOXIDE
1975
1985 BASELINE
1985 COAL PROGRAM
1985 PRESIDENT'S
PROGRAM
INDUSTRY
UTILITY
TOTAL
10.8
18.6
29.4
12.4
20.2
32.6
16.6
20.2 (0%)
36.8 (13%)
15.9 (28%) -
18.2 (-10%)
34.1 (5%)
NITROGEN OXIDES
1975
1985 BASELINE
1985 COAL PROGRAM
1985 PRESIDENT'S
PROGRAM
INDUSTRY
UTILITY
TOTAL
6.7
9.0
15.7
7.3
9.0
(9%)
(0%)
16.3 (4%)
7.6 (13%)
8.2 (-9%)
15.8 (1%)
—/ New Source Performance Standards for units above 25 MW.
For specific emission limits under NSPS, see Case 4 for
TSP and S09, and case 1 for NO in Appendix 2.
Percentage over 1985 baseline.
-------
TABLE A-2 PROJECTED TSP EMISSIONS FROM INDUSTRIES AND UTILITIES BY REGION - (NSPS)
(10 TONS)
I.
IV.
V.
VI.
FEDERAL
REGION
UTILITY
INDUSTRY
TOTAL
II. UTILITY
INDUSTRY
TOTAL
III. UTILITY
INDUSTRY
TOTAL
UTILITY
INDUSTRY
TOTAL
UTILITY
INDUSTRY
TOTAL
UTILITY
INDUSTRY
TOTAL
VII. UTILITY
INDUSTRY
TOTAL
1975
ACTUAL
40
210
250
120
550
670
510
1280
1790
1050
2490
3540
990
3040
4030
130
1210
1340
190
1040
1230
1985
BASE
30
220
250
50
560
610
100
1300
1400
260
2540
2800
400
3090
3490
150
1230
1380
110
1060
1170
CHANGE
COAL PROGRAM
(from 1985
base)
0
0
0
0
10
10
0
20
20
10
40
50
0
60
60
20
180
200
0
20
20
1985
COAL PROGRAM
30
220
250
50
570
620
100
1320
1420
270
2580
2850
400
3150
3550
170
1410
1580
110
1080
1190
CHANGE
PRESIDENT'S PROGRAM
(from 1985 base)
0
^
0
-10
10
0
0
10
10
-10
10
0
-10
-40
=50
10
260
270
-20
20
0
1985
PRESIDENT'S
PROGRAM
30
220
250
40
570
610
i
to
250
2550
2800
390
3050
3440
90
1080
1170
-------
TABLE A-2 PROJECTED TSP EMISSIONS FROM INDUSTRIES AND UTILITIES BY REGION - (NSPS) (Cont)
(10 TONS)
FEDERAL
REGION
VIII. UTILITY
INDUSTRY
TOTAL
IX.
X.
UTILITY
INDUSTRY
TOTAL
UTILITY
INDUSTRY
TOTAL
NATIONAL
UTILITY
INDUSTRY
TOTAL
1975
ACTUAL
80
400
480
30
660
690
330
330
3140
11200
14340
1985
BASE
90
410
500
40
670
710
10
330
340
1240
11410
12650
CHANGE
COAL PROGRAM
(from 1985
base)
0
10
10
-10
20
10
0
10
10
20
370
390
1985
COAL PROGRAM
90
420
510
30
690
720
10
340
350
1260
11780
13040
CHANGE
PRESIDENT'S PROGRAM
(from 1985 base)
-10
10
0
0
20
20
0
j)
0
-50
300
250
1985
PRESIDENT'S PROGRAM
80
420
500
40
690
730
10
330
340
1190
11710
12900
I
u>
-------
TABLE A-3 PROJECTED SO- EMISSIONS FROM INDUSTRIES AND UTILITIES BY REGION - (NSPS)
(10 TONS)
I.
IV.
V.
VI.
FEDERAL
REGION
UTILITY
INDUSTRY
TOTAL
II. UTILITY
IM3USTRY
TOTAL
III. UTILITY
INDUSTRY
TOTAL
UTILITY
INDUSTRY
TOTAL
UTILITY
INDUSTRY
TOTAL
UTILITY
INDUSTRY
TOTAL
VII. UTILITY
INDUSTRY
TOTAL
1975
ACTUAL
220
230
450
780
590
1370
3120
1500
4620
5010
2060
7070
7550
3730
11280
160
690
850
1300 -
660
1960
1985
BASE
400
260
660
760
680
1440
2810
1720
4530
5200
2360
7560
6410
4280
10690
1970
790
2760
1760
760
2520
CHANGE
COAL PROGRAM
(from 1985
base)
0
50
50
10
60
70
-20
250
230
-60
520
460
-200
500
150
220
2280
2500
0
180
180
1985
COAL PROGRAM
400
310
710
770
740
1510
2790
1970
4760
5140
2880
8020 .
6210
4780
10990
2190
3070
5260
1760
940
2700
CHANGE
PRESIDENT'S PROGRAM
(from 1985 base)
-40
-20
-60
-110
60
-50
-180
130
-50
-730
120
-610'
-40
2990
2950
-290
160
1985
PRESIDENT'S PROGRAM
360
240
600
650
740
1390
2630
1850
4480
4470
2480
6950
6050
4050
10100
1930
3780
5710
-------
TABLE A-3 PROJECTED SO EMISSIONS FROM INDUSTRIES AND UTILITIES BY REGION - (NSPS)
* TONS)
(Cent)
VIII.
FEDERAL
REGION
UTILITY
INDUSTRY
TOTAL
1975
ACTUAL
240
230
470
1985
BASE
400
260
660
CHANGE
COAL PROGRAM
(from 1985
base)
0
100
100
1985
COAL PROGRAM
400
360
760
CHANGE
PRESIDENT'S PROGRAM
(from 1985 base)
-60
80
20
1985
PRESIDENT'S PROGRAM
340
340
680
i
Ul
IX.
X.
UTILITY
INDUSTRY
TOTAL
UTILITY
INDUSTRY
TOTAL
180
980
1160
40
140
180
400
1130
1530
110
160
270
10
110
120
0
120
120
410
1240
1650
110
280
390
100
150
-50
80
30
300
1280
1580
60
240
300
NATIONAL
UTILITY 18600 20220 -40
INDUSTRY 10810 12400 4170
TOTAL 29410 32620 4130
20180
16570
36750
-1960
3520
1560
18260
15920
34180
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2-1
Appendix 2; METHODOLOGY FOR EMISSIONS CALCULATIONS IN THE
INDUSTRIAL SECTOR
The general methodology for industrial emissions
calculations begins with PIES fuel use estimates for
industries under the NEP and a 1975 and 1985 baseline.
The 1985 baseline is then modified to reflect changing
fuel use. This discussion will describe:
(1) Baseline Emissions
(2) Emission Factors, and
(3) Assumptions Used in the Regulation Cases
(1) Baseline Emissions
Industrial baseline air emissions are affected
due to the variable levels of baseline emissions under the
different regulatory assumptions for each case as well as
the direct impacts of coal conversion. The NSPS baseline
emissions for fuel combustion are determined using the
current applicable State Implementation Plan (SIP)
emission limitations for existing sources and new sources
with less than 25 megawattts (MW) heat input capacity.
New Source Performance Standards (NSPS) are applied to
new facilities with greater than 25 MW capacity. The
baseline change is then calculated as the difference in
baseline air emissions which would result when compared
to fuel combustion emissions under the NSPS baseline case.
The total industrial emission baseline, which
includes fuel combustion as an emission source, is cal-
culated for each pollutant by using 1985 projected
national emissions — to derive that portion of the
national figures which originate from industrial sources.
This industrial breakout is obtained by applying the 1975
distribution of emissions for all sources— to the 1985
totals and computing that portion which is projected to
originate in the industrial sector.
— Priorities and Procedures for Development of
Standards of Performance for New Stationary Sources
of Atmospheric Emission, Argonne National Laboratory,
for EPA, EPA-450/3-76-020, May 1976.
2/
—' Data from EPA's National Emissions Data System.
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(2) Emission Factors
The derivation of emission factors to calculate
change in air emissions from conversion of oil and gas to
coal involves:
For the SIP regulations for coal and oil,
regional emission limits were developed
using AQCR-specific regulations which are
aggregated to the regional level by weighting
with the relative industrial fuel combustion
for each AQCR.— The oil emission factors
also assume that distillate oil represents
a minimum of 30 percent of the oil savings
through conversion which decreases the
overall level of air emissions from oil
burning before conversion. Gas emission
factors have been developed using EPA data
for all three pollutants.—
For the NSPS regulations, national standards
were used as promulgated by EPA.—
For coal burning in new facilities three
different assumptions were used to project
potential air impacts under EPA's Best
Available Control Technology (BACT) air
regulations. Various levels of S02 and
TSP control efficiency are explained with
the assumptions for each specific case.
Operating and maintenance practices are
assumed adequate to maintain stated control
efficiencies. Non-compliance with applicable
environmental regulations is not considered a
factor in the air impact analysis.
—/ Laws and Regulations Affecting Coal, for the U.S.
Department of Interior, Energy and Environmental
Analysis, Inc., June 1976.
—/ AP42, Compilation of Air Pollutant Emission Factors,
EPA Second Edition, February 1976.
—/ 40 CFR 60 Standards of Performance, Subpart D,
revised 40 FR 46250.
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2-3
For oil burning in new facilities, a moderate
desulfurization policy and TSP control strategy
were assumed to calculate air emissions. These
emissions are deducted from coal burning emis-
sions to compute the incremental change due to
conversion.
For NO emissions in new facilities with 25 MW
or grelter capacity, boiler design and operating
procedures were applied to reduce flame and
furnace temperatures and increase the amount
of excess air in the flame to attain the NSPS
national emission standards.
Non-boiler fuel combustion is assumed to use the same
air emission factors which have been developed for fuel
combustion in boilers.
(3) Assumptions in the Regulatory Cases
Several different regulatory cases were constructed
to reflect potential variations in the Clean Air Act and
in the definition of BACT. These cases are summarized in
Table 2 of the analysis document. The discussion below
provides more detail on the assumptions for each pollutant.
Sulfur Dioxide
Case No. 1. BACT is applied on new facilities with
greater than 25 MW capacity to achieve a 90 percent reduc-
tion in S02 emissions (this assumes 90 percent efficiency
and 100 percent reliability of scrubber equipment). Also,
a 20 percent reduction through coal cleaning is obtained
in the sulfur content of the most locally abundant coal
available within each FEA region. An emission limit of
1.5 pounds per MMBtu is set for new facilities with 10-
25 MW capacity, assuming 25 percent of the units use FGD
and the remaining burn low sulfur coal. A BACT emission
limit of .53 pounds per MMBtu is used for oil-burning.
In comparing the emissions results for the Coal Conversion
and President's Programs, the decrease in emissions
observed in the President's Program is primarily due to
oil to gas fuel switching which occurs with the conser-
vation policies of the National Energy Plan.
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2-4
Case No. 2. The same assumptions are used as in
Case No. 1, except for new facilities with greater than
25 MW capacity, where an 80 percent reduction in S02
emissions is achieved instead of 90 percent (this
assumes 90 percent reliability instead of 100 percent).
Case No. 3. The same assumptions are used as in
Case No. 2, except for new facilities with 10-25 MW
capacity. Coal burning in these units is assumed to
be regulated by applicable SIP S02 emission limitations
instead of 1.5 pounds per MMBtu.
Case No. 4. This case assumes the attainment of the
NSPS regulation of 1.2 pounds per MMBtu for coal burning
in facilities with greater than 25 MW capacity. All
other assumptions are the same as in Case No. 3. Case
No. 4 in effect assumes attainment of the same environ-
mental standards used to compute the NSPS baseline
emissions from industrial fuel combustion.
Total Suspended Particulates
Case No. 1. BACT is applied to limit TSP emissions
to .01 pounds per MMBtu in new facilities with greater
than 25 MW capacity- This assumes a 99.8 percent reduc-
tion in TSP using a baghouse or electrostatic precipitator
(ESP). For new facilities with 10-25 MW capacity, TSP
emissions are limited to .03 pounds per MMBtu, which
assumes a 99.5 percent reduction. This BACT for small
new facilities requires use of a baghouse or ESP, since
it is unlikely that a scrubber for S02 will achieve this
degree of TSP removal. A BACT regulation of .05 pounds
per MMBtu is used for oil. TSP emissions from gas are
assumed to be .017 pounds per MMBtu (from AP42).
Case No. 2. The same assumptions are used as in
Case No. 1, except for TSP emissions from coal, where
an effective limit of 0.5 pounds per MMBtu is assumed.
This emission regulation achieves a 99.0 percent reduction
in TSP, which can be obtained with an S02 scrubber, or a
baghuse or ESP if no scrubbing is necessary.
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2-5
Case No. 3. The same assumptions are used in Case
No. 3, except for new facilities with 10-25 MW capacity,
where applicable SIP regulations apply for coal combustion
This case assumes 92 to 97 percent TSP reduction under
current SIP's, using either a baghouse or ESP.
Case No. 4. This case assumes attainment of the
NSPS for new facilities greater than 25 MW capacity,
which allows emissions of .1 pounds per MMBtu. In
effect, the emission regulations for this case are
identical to the standards used for the TSP baseline
for industrial fuel combustion.
Nitrogen Dioxide
Case No. 1. This one case for NO uses emission
factors developed from AP42—' for oil t-40 pounds per
MMBtu), gas (.69 pounds per MMBtu), and coal (.75 pounds
per MMBtu) for existing facilities and new facilities
of 10-25 MW capacities. For new facilities greater than
25 MW capacity NSPS regulations apply for oil (.3 pounds
per MMBtu), gas (.2 pounds per MMBtu) and coal (.7
pounds per MMBtu).
—' AP42, Compilation of Air Pollution Emission Factors,
Second Edition, February 1976.
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3-1
Appendix 3; METHODOLOGY FOR EMISSIONS CALCULATIONS IN THE
UTILITY SECTOR
This Apppendix describes the methodology used to
calculate emissions in the utility sector. These estimates
were provided by the Energy Strategies Branch (ESB) of the
Office of Air Quality Planning and Standards of EPA. A
separate report is,under preparation by ESB documenting
their projections.—
I. COMPUTATION OF BASELINE EMISSIONS
Baseline emissions are (1) 1975 emissions of SO-,
particulates, and NO from all sources (total emissions)
and from power plants, and (2) 1985 emissions of SO-,
particulates, and NO from power plants. The 1985 Base-
line emissions are termed "business as usual," which assumes
continuance of the regulatory and legislative environment
prior to the proposed National Energy Plan or other legis-
lation currently being considered for increased coal use.
All emissions were aggregated by State, EPA region, and the
Nation.
A. 1975 Emissions
Emissions of SO- from power plants were obtained from
the Energy Data System (EDS). EDS calculates SO- emissions
based on the type, amount, and sulfur content of fuels actu-
ally burned in each power plant (as reported on the 1975 FPC
Form 67 and assuming 98 percent of input S is emitted as SO-)
Emissions of NO and particulates for power plants were
obtained from tne National Emissions Data System (NEDS),
which reflects 1975 data for about 40 states and somewhat
older data for the remainder of the country. Adjustment was
made for a known error in the NEDS file for the State of
Florida.
Total emissions for SO-, particulates, and NO in 1975
were obtained from NEDS (as of March 21, 1977). Total SO-
emissions were adjusted by replacing the NEDS SO- emissions
for electric generation with SO- emissions from power plants
calculated using the Energy Data System. This adjustment
was made for two reasons:
V "Air Pollution Impacts of Increased Coal Use in the
Utility Sector: An Analysis of Emissions Under the
National Energy Plan."
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3-2
(1) to provide a consistent baseline of power
plant emissions (the estimates of 1985 power
plant emissions were based on EDS); and
(2) because, on a national basis, EDS data is
more current than NEDS.
B.
1985 Emissions
Power plant emissions in 1985 were estimated using the
model depicted in Figure A-l. In general, emissions were
computed assuming that existing sources in 1975 would meet
existing State Implementation Plan (SIP) emission regula-
tions for 1985. Emissions from units which are planned to
Figure A-l. Model for Estimating 1985 Power Plant Emissions
(SO , Particulate, NO )
1985
Power
Plant
Emissions
Maximum
Allowable
Emissions
Existing
Sources
Emissions
From
Retired +
Units
Emissions
From New
Sources +
Emissions
from
Fuel
Switching
Gas
Curtail-
ments
ESECA Other
Dual-
Fired
be retired between 1975 and 1985 were subtracted. Emissions
from planned new units were added along with increased emis-
sions from existing units which are likely to convert from
burning oil or gas. The following paragraphs discuss the
assumptions, data sources, and procedures for computing each
of the elements depicted in Figure A-l.
Maximum Allowable Emissions for Existing Sources
For S02, maximum allowable emissions (MAE) for
existing (in 1975) coal- and oil-fired units were computed
by EDS assuming that each power plant meets the applicable
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3-3
SIP regulation for 1985. SIP regulations in EDS were those
effective as of January 1977. No adjustment was made to
account for the possibility of revised SIPs in the future
since the impact of such revisions (toward either tightening
or loosening regulations) is difficult to predict.
For particulates, MAE for coal-fired power plants were
computed by EDS in the same manner as S02 emissions were
calculated. For oil-firing, however, 1985 emissions were
assumed to be the same as 1975 since most oil burners today
emit particulates at a rate well below that required by
SIPs.—' To have assumed that all oil-burners meet SIP
levels in 1985 would have resulted in a substantial and
unrealistic increase in particulate emissions between 1975
and 1985.
For NO , MAE were assumed to be the same as emissions
in 1975, because only Los Angeles and Chicago have N0x
regulations which limit emissions from existing sources.
Retirements
Power plant retirements (in megawatts) were determined
on a State basis using data from FPC Order 383-3 (April 1,
1976). Retired megawatts were converted to fuel amounts
using national average heat rates (BTU/kw-hr) as computed by
FPC and a 0.60 capacity factor.
For S0» and particulates, emissions from retired coal
and oil units were computed by assuming a drop in 1985 max-
imum allowable emissions proportional to the reduction in
fuel use brought about by retirements.
For NO , 1985 emissions by fuel use were not available.
Therefore, imissions from retired units were computed using
a national weighted average emission factor (#NO /unit fuel
use) for coal, oil, and gas. The average emission factor
for each/fuel type was based on published EPA emission
factors-/ and 1973 capacity of tangentially-fired boilers
versus other types of firing (as reported to FPC).
V Comparison of FPC fuel quality data with SIP emission
regulations in EDS.
2/ Compilation of Air Pollution Emission Factors, AP-42,
US EPA, April 1976.
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3-4
Emission from New Sources
Planned growth in the power plant sector was that
reported on FPC Order 383-3 in April 1976, and subsequently
updated by FPC through mid-March 1977. Fuel use for this
growth was calculated using a national average heat rate
(Btu/kw-hr) for coal as provided by FPC and a 0.60 capacity
factor. For the "Business as Usual - NPS" case all growth
was assumed to meet the current Federal new source perfor-
mance standards— , except where SIP regulations for
particulates and S02 were more stringent than the NSPS.
For the "Business as Usual - BACT" case, BACT was assumed to
be 80 percent control of input sulfur assuming use of
locally available coal, 0.05 tparticulate/MMBtu, and 0.6
#NO /MMBtu. BACT was assumed to apply to units coming on
lini in or after 1984.
For the NSPS and BACT case, this approach, to a small
degree, may underestimate emissions of S02, since some new
plants coming on line after 1975 are not subject to NSPS.
Emissions of NO and particulates probably would not be
underestimates iince, over the past few years,4most new power
plants typically emit at levels near the NSPS.—7
Emission From Fuel Switching
The potential fuel-switchers were identified from three
sources of information. One source was the Federal Energy
Administration's lists of what that agency terms "Round 1"
and "Round II" candidates for prohibition orders (limiting
the use of oil or gas as primary boiler fuel) authorized by
the Energy Supply and Environmental Coordination Act (ESECA)
of 1974. For this analysis, it was assumed that all of the
Rounds I and II boilers would burn only coal by 1985. A
second group of potential fuel-switchers were identified
from boiler fuel-use data in the Energy Data System. It was
assumed that any boiler which used both coal and oil in 1975
would burn only coal- by 1985. The third source of informa-
tion was the Foster Associates' study of gas curtailments
3/ 1.2 #S00/MMBtu; 0.1 #particulate/MMBtu; 0.7 #NO /MMBtu
— ^ X
4/ Data collected by EPA's Emission Standards and Engineering
~~ Division for work on revising NSPS.
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3-5
done under SASD contract. This study identifies the power
plant boilers which can burn either gas and oil or gas and
coal, and estimates, through 1980, how much gas-burning will
be curtailed in these boilers because of natural gas short-
ages. These estimates were extended through 1985 using a
report sponsored by the gas industry.— For these boilers,
it was assumed that those which can burn coal would convert
to coal, and those which cannot burn coal would convert to
oil. Some boilers are designed for multi-fuel use, but
cannot, without considerable cost, be restored to a previous
coal-burning capability. For this set of boilers, it was
assumed that coal-burning capability would be restored only
in those identified by FEA as conversion candidates.
Although some boilers designed to burn only gas are being
converted to oil use (conversion to coal is impractical for
such boilers), these conversions were not considered, since
no hard data are available on the location and extent of
such conversions.
The changes in emissions that will result from fuel
switching were computed on a plant-by-plant basis by sub-
tracting 1975 base year emissions from projected 1985
emissions after switching fuels. Base year S02 emissions
came from an Energy Data System program (described earlier)
which operated on the types of fuels used and their sulfur
contents. Base year particulate matter and NO emissions
were derived from the National Emissions Data system which
uses either measured emissions or emission factors from
AP-42 (Compilation of Air Pollution Emission Factors, US
EPA). To estimate 1985 S02 emissions, it was assumed that
all coal and oil would be Burned in compliance with appli-
cable SIP regulations. To estimate 1985 particulate matter
emissions, the same assumption was made for coal-burners,
but for those sources which will switch from gas to oil,
the AP-42 emission factor for oil-burning was used. The
reason for this assumption was that, while most states apply
the same particulate emission limit for both coal-burners
and oil-burners, oil-burners rarely emit particulates up to
the allowed limit. To estimate 1985 NO emissions,
emission factors were applied to boilers switching from oil
or gas to coal. For boilers switching from gas to oil, the
_5/ "Future Gas Consumption of the United States," Volume
No.6, University of Denver Research Institute, September
1976.
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3-6
1985 emissions were assumed to be the same as those in 1975.
The reason for this assumption was that, based on AP-42
emission factors, the change in NO emissions is near zero
when switching from gas to oil andxis highly dependent on
the heating values assumed for the two fuels.
In computing the 1985 emission limits for SO,, and
particulate matter, it was assumed that replacement fuels
equaled replaced fuels on a total heat input basis. Excep-
tions were made where inspection data on ESECA boilers
(gathered by PEDCO Environmental Specialists, Inc. under
SASD contract) showed that oil-to-coal switching resulted in
either boiler derating or increased boiler efficiency, both
of which would result in lesser coal heat input.
II. COMPUTATION OF EMISSIONS IMPACT OF THE NATIONAL ENERGY
PLAN
Future changes in fuel use patterns resulting from the
proposed National Energy Plan were furnished from the PIES
model. This section describes the assumptions used to
translate changes in "business as usual" fuel use into
changes in "business as usual" emissions of S02, particu-
lates, and NO .
X
For this project, PIES forecasted (on an EPA regional
basis) changes in consumption of coal, oil, and gas that may
occur in 1985 and 1990 if the economic policies of the
National Energy Plan are implemented. Two sets of estimates
were provided — one for the coal substitution portion of
the Plan and one for the impact of the entire program
(including coal substitution and conservation). Fuel use
data were expressed in heat equivalents (Btus).
Increased coal consumption was assumed to be in newly
constructed units, and thus the associated emission increases
were computed both at the NSPS emission rates (1.2 #SO~/MMBtu,
0.1 #particulate/MMBTU, and 0.7 #NO /MMBtu) and at BACT
emission rates (90 percent control S02, 0.05 #particulate/
MMBtu, and 0. 6#NO /MMBtu). Decreases in coal consumption
under the total NEP were assumed to be by reduction in the
construction of planned new units. Decreased emissions were
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3-7
computed at both the NSPS and BACT emission rates. Excep-
tions to this assumption were made where projected NEP
decreases in a given time period exceeded the projected
"business as usual" growth for the same period. In this
situation some of the reduced consumption was assumed to be
in a projected growth (meeting NSPS or BACT) and some in
existing units (meeting SIP).
Decreases in oil or gas consumption were assumed to be
the result of retirements or fuel conversions and, thus,
would affect plants that were on line in 1975 (thus meeting
SIPs at the time the action took Place). Accordingly, emis-
sion decreases were computed using a weighted average SIP
emission limit for each pollutant by region. This weighted
average SIP was determined by dividing the maximum allowable
emissions for existing (in 1975) sources (in tons/year) by
the total regional fuel use (in Btus). (Maximum allowable
emissions had been calculated for estimation of the 1985
"business as usual" emissions by assuming that each power
plant existing in 1975 met applicable SIP emission limits
for 1985). Increases in oil consumption were assumed to be
as a result of boiler conversions from gas to oil-firing,
since no new oil-burning plants were being built. It had
been assumed that fuel switching in all dual-fired boilers
— where replacement fuels are subject to SIP emission
regulations — would take place under "business as usual."
Any additional conversions from gas to oil would require
boiler modifications, and, thus, it was assumed that
increased oil use under the NEP would be subject to NSPS.
U. S. GOVERNMENT FEINTING OFFICE : 1977 O - 237-773
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