&EPA
          United States
          Environmental Protection
          Agency
         Office of Air Quality
         Planning and Standards
         Research Triangle Park NC 27711
EPA-450/3-39-17
May 1989
          Air
Projected Impacts of
Alternative New Source
Performance Standards
for Small Industrial-
Commercial-lnstitutional
Fossil Fuel-Fired Boilers

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                                        EPA-450/3-89-17
     PROJECTED IMPACTS OF ALTERNATIVE

 NEW SOURCE PERFORMANCE STANDARDS FOR

SMALL INDUSTRIAL-COMMERCIAL-INSTITUTIONAL

         FOSSIL FUEL-FIRED BOILERS
           Emission Standards Division
         U.S. Environmental Protection Agency
            Office of Air and Radiation
       Office of Air Quality Planning and Standards
         Research Triangle Park, N.C. 27711
                 May 1989

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This report has been reviewed by the Emission Standards Division of the
Office of Air Quality Planning and Standards, EPA,  and approved for
publication.  Mention of trade names or commercial  products is not intended
to constitute endorsement or recommendation of use.  Copies of the report  are
available through the Library Service Office (MD-35), U.S. Environmental
Protection Agency,,, Research Tri'angle Park,  N.C.  27711, or from National
Technical Information Services, 5285 Port Royal Road, Springfield,
Virginia  22161.V-%
                                     ii

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                               TABLE OF CONTENTS
                                                                          Page
1.    INTRODUCTION	   1-1

2.    EMISSIONS, COST AND ENERGY IMPACTS OF ALTERNATIVE NSPS  	   2-1
      2.1   Methodology   	   2-1
      2.2   Baseline Air Emissions and Fuel Mix Forecasts   	   2-3
      2.3   National Impacts  	   2-17
      References	   2-46

3.    ECONOMIC IMPACTS:  COMMERCIAL/INSTITUTIONAL SECTOR	     3-1
      3.1   Introduction	   3-1
      3.2   Selected Sectors	   3-2
      3.3   Generic Buildings	 .	   3-18
      References  		   3-38

4.    ECONOMIC IMPACTS:  INDUSTRIAL SECTOR	4-1

      4.1   Steam Users	   4-1
      4.2   Selected Industries	   4-32
      References	   4-38


                                  APPENDICES


APPENDIX A: PROFILE OF BOILERS IN COMMERCIAL BUILDINGS  	   A-l

APPENDIX B: HISTORICAL NEW BOILER SALES DATA	   B-l
                                     -m-

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                                LIST OF TABLES
                                  (continued)
                                                                           Page
2-20  Projected Coal Boiler Emissions Reductions  	   2-28
2-21  Projected Annualized Cost Increases for Coal Boilers   	   2-30
2-22  Projected Coal Boiler Emissions
      Control Cost-Effectiveness Ratios   	   2-31
2-23  Projected Residual Fuel Oil Boiler S02 Emissions Reductions    .  .   2-33
2-24  Projected Residual Fuel Oil Boiler PM Emissions Reductions   .  .  .   2-34
2-25  Projected Annualized Cost Increases for Oil Boilers    	   2-35
2-26  Projected Annualized Cost Increases for Oil Boilers    	   2-36
2-27  Projected Oil Boiler S02 Emissions Control
      Average Cost-Effectiveness Ratios   . . 	   2-37
2-28  Projected Oil Boiler S02 Emissions Control
      Incremental Cost-Effectiveness Ratios   . . 	   2-38
2-29  Projected Annual ized Cost Increases for Oil Boilers    	   2-39
                                                                •
2-30  Projected Annualized Cost Increases for Oil Boilers    	   2-41
2-31  Projected Oil Boiler S02 Emissions Control
      Average Cost-Effectiveness Ratios   	 . 	   2-42
2-32  Projected Oil Boiler S02 Emissions Control
      Incremental Cost-Effectiveness Ratios   	   2-43
2-33  Summary of Expected S02 Emissions Reductions  	   2-44
2-34  Summary of Expected PM Emissions Reductions   	   2-45
3-1   Elementary and Secondary Schools  	   3-6
3-2   Hospitals   	   3-7
3-3   Laundries   	   3-9
3-4   Hotels    ..."	   3-11
                                      -v-

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                                LIST OF TABLES
                                                                           Page
2-1   Crude Oil Price Projections    	    2-4
2-2   Alternative NSPS	    2-5
2-3   Residual Fuel Oil  Boiler Sales  in  1987	    2-7
2-4   Baseline Residual  Fuel Oil Boilers	    2-8
2-5   Coal Boiler Sales  in 1987	      2-9
2-6   Baseline Coal Boilers   	    2-11
2-7   Baseline Distillate Fuel Oil Boilers	    2-12
2-8   Baseline Natural Gas Boilers   	    2-13
2-9   Baseline Fuel Mix   .  .	    2-14
2-10  Baseline S02 Emissions  	    2-15
2-11  Baseline PM Emissions		    2-16
2-12  Projected Residual Fuel Oil  Boiler S02 Emissions Reductions    .  .    2-18
2-13  Projected Residual Fuel Oil  Boiler PM  Emissions  Reductions   .  .  .    2-19
2-14  Projected Annualized Cost  Increases  for
      Residual Fuel Oil  Boilers    	    2-21
2-15  Projected Residual Fuel Oil  Boiler Average  S02
      Emissions Control  Cost-Effectiveness Ratios   	    2-22
2-16  Projected Residual Fuel Oil  Boiler Incremental S02
      Emissions Control  Cost-Effectiveness Ratios   	    2-23
2-17  Projected Annualized Cost  Increases  for
      Residual Fuel Oil  Boilers    	    2-25
2-18  Projected Residual Fuel Oil  Boiler Average  S02
      Emissions Control  Cost-Effectiveness Ratios   	    2-26
2-19  Projected Residual Fuel Oil  Boiler Incremental S02
      Emissions Control  Cost-Effectiveness Ratios   	    2-27
                                      -TV-

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                                LIST OF TABLES
                                 (continued)
                                                                           Page
3-5   Colleges and Universities   	    3-12
3-6   Selected Sectors Economic Impacts:   FGO
      (Without Monitoring and Testing Costs)  	 .  	    3-15
3-7   Monitoring and Testing Cost Estimates   	    3-16
                                                                      <;
3-8   Selected Sectors Economic Impacts:   FGD
      (With Monitoring and Testing Costs)	    3-17
3-9   Selected Sectors Economic Impacts:   Very Low Sulfur Regulation
      (With Monitoring and Testing Costs)   	    3-19
3-10  Generic Buildings Boiler Configuration Data
      for Boston, Massachusetts   	    3-22
3-11  Generic Buildings Typical Boiler Configurations
      for Boston, Massachusetts   . .-	  .    3-23
3-12  Generic Buildings Boiler Configuration Data
      for Washington, D.C	.    3-24
3-13  Generic Buildings Typical Boiler Configurations
      for Washington, D.C	    3-26
3-14  Generic Buildings Boiler Configurations	    3-27
3-15  Estimates of Generic Buildings Annual
      Fossil Fuel Consumption in Boilers   	    3-28
3-16  Energy Consumption in Commercial Buildings in 1983  	    3-29
3-17  Generic Buildings Annual Rental Costs   	    3-31
3-18  Derivation of Estimates of Total Annualized Pollution Control
      Costs per Building for the Very Low Sulfur Fuel Standard  ....    3-33
3-19  Derivation of Estimates of Total Annualized Pollution Control
      Control Costs per Building for the  Scrubber Requirement   ....    3-34
3-20  Comparisons of .Estimates of Total Annualized
      Pollution Control Costs per Building  	    3-35
                                      -VI-

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                                LIST OF TABLES
                                  (continued)
                                                                           Page
3-21  Impacts of Total Annualized Pollution Control Costs on
      Rental Rates (With Monitoring and Testing Costs)   	    3-36
3-22  Impacts of Total Annualized Pollution Control Costs on
      Rental Rates (Without Monitoring and Testing Costs)    	    3-37
4-1   An Overview of the Use of Boilers
      in Manufacturing Industries in 1979   	    4-2
4-2   Federal Reserve Board Index of Industrial Production   	    4-5
4-3   Average Rates of After-Tax Profit on
      Stockholders' Equity by Industry Group   	    4-9
4-4   Average Rates of After-Tax Profit on
      Total Assets by Industry Group	    4-10
4-5   Average After-Tax Profits per Dollar
      of Sales by Industry Group  	    4-11
4-6   Employment by Industry Group	  .    4-13
4-7   Historical Trends:  Food and Kindred Products (SIC 20)	    4-15
4-8   Historical Trends:  Textile Mill Products (SIC 22)  .  ,	    4-17
4-9   Historical Trends:  Paper and Allied Products (SIC 26)	    4-19
4-10  Historical Trends:  Chemicals and Allied Products  (SIC 28)   ...    4-21
4-11  Historical Trends:  Petroleum and Coal Products (SIC 29)   ....    4-22
4-12  Historical Trends:  Iron and Steel Industry   	    4-24
4-13  Steam-Intensity Ratios  	    4-29
4-14  National Impacts  	    4-30
4-15  Estimated Return on Assets for Model Plants   	    4-37
                                     -V11-

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                                LIST OF TABLES
                                  (continued)
                                                                           Page
A-l   Commercial Buildings In 1983	     A-5
A-2   Commercial Buildings in 1986	     A-6
B-l   Historical Cast Iron Boiler Sales   	     B-2
B-2   Historical Resident!al/Commercial/Institutional
      Cast Iron Boiler Sales Estimates  	     B-3
B-3   Historical Firetube Boiler Sales  	     B-4
B-4   Historical Watertube Boiler Sales   	     B-5
                                    -viii-

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                                LIST OF FIGURES
                                                                           Pace
4-1   Federal Reserve Board Index of Industrial Production   	    4-4
4-2   Rates of After-Tax Profit on Stockholders' Equity   	    4-6
4-3   Rates of After-Tax Profit on Total Assets   	    4-7
4-4   After-Tax Profits Per Dollar of Sales    	    4-8
4-5   Derivation of Estimated Increase in National Average
      Industrial Product Prices Due to Pollution Control Costs   ....    4-27
A-l   U.S. Census Regions and Divisions   	    A-4
                                     -IX-

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                               1.  INTRODUCTION
      This report presents projected environmental, cost, and energy  impacts
of alternative air emission standards for new small (<29 MW, <100 MMBtu/hr)
industrial-commercial-Institutional fossil fuel-fired boilers.  These draft
standards would revise the emission regulations that currently exist  in
Subpart 0 of 40 CFR Part 60.  The effects of alternative sulfur dioxide  (S02)
and particulate matter (PM) emission standards are assessed in this report.
The methodology used to examine environmental, cost, and fossil fuel  results
projected under current and alternative air emission regulations also is dis-
cussed.
      For individual boilers, air emission regulations can play a significant
role in determining boiler fuel choice and the levels of air emissions.  Air
emission regulations can result in measurable national and regional environ-
mental, cost, and energy impacts, including changes in the types of fossil
fuels combusted and changes in the level of air pollutant emissions generated
by new small fossil fuel-fired boilers.
      This analysis examines projected impacts in the fifth year following
proposal of standards.  The analysis of alternative regulations is designed to
                                                             •
highlight potential environmental, cost, and energy impacts.  These impacts
are measured in terms of the projected change under current versus alternative
air emission regulations.  The analysis of environmental impacts focuses on
expected reductions in levels of air emissions.  Cost Impacts are evaluated in
terms of incremental changes in the total annual 1 zed costs for boiler and
pollution control equipment capital, operating, and fuel costs.  Energy
impacts are evaluated in terms of shifts in the demand between fuel types
(e.g., coal or residual fuel oil versus natural gas).

      This report addresses only fossil fuel (coal, oil  and natural gas)
consumption in small (<29 MW, <100 MMBtu/hr) new boilers.  It does not analyze
non-fossil fuel-fired steam generating units (I.e., wood or municipal solid
waste combustion).
                                      1-1

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      The balance of this report  is  presented  in  three  parts.   Section 2
presents the approach employed  to analyze  the  alternative standards and
describes key assumptions and  inputs.   The potential  national  environmental,
cost and energy impacts for the alternative standards are also summarized in
Section 2.  The methodology and results of the economic impact analyses for
the commercial/institutional sector  are presented in  Section 3.   The
industrial sector economic impact analyses are summarized in Section 4.
                                     1-2

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                    2.  EMISSIONS, COST AND ENERGY IMPACTS
                              OF  ALTERNATIVE NSPS

      The methodology and results of the projections of national S02 and PM
emissions reductions, total pollution control costs and energy Impacts of
alternative NSPS for new small (<29 MW, <100 MMBtu/hr) industrial-commercial -
institutional boilers In the fifth year after proposal are summarized in this
section.
2.1  METHODOLOGY
2.1.1  Scope
      This analysis addresses only fossil fuel (coal, fuel oil and natural
gas) combustion in new small boilers.  It does not include emissions from the
combustion of fuels like wood or municipal solid waste.
      Alternative NSPS for S02 and PM emissions control  from the combustion of
coal and fuel oil are assessed.  NOX emissions control  is not analyzed in this
report.                                                          ...
      The projected number, sizes and types of new industrial-commercial-
institutional boilers <29 MW (<100 MMBtu/hr) and constructed over the next
five years are based on recent sales levels.  These sales estimates are not
available by type of purchaser (industrial versus commercial/institutional).
As a result, the results are estimated for the total  industrial-commercial -
institutional sector.
      The projected fuel nix by boiler type, size and alternative air emission
regulation is based on recent sales data and exogenous assumptions.  These
estimates are not based on a life-cycle analysis of the least-cost fuel
type/pollution control compliance option and they are not based on a statis-
tical analysis of historical sales data.
      The boiler types are cast iron, firetube, firebox and watertube units.
The boiler size classes are:
   •  <1 MW  (<3 MMBtu/hr)
   •  1-3 MW (3-10 MMBtu/hr)
   t  3-9 MW (10-30 MMBtu/hr)
   •  9-29 MW (30-100 MMBtu/hr)
                                      2-1

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      The S02 emissions control  options are compliance low sulfur fuel types.
The PM emissions control options for coal combustion are dual mechanical
collectors and fabric filters.
      The national impacts are measured in terms of the projected change  under
current versus alternative national air emissions regulations.  The analysis
of environmental impacts focuses on projected decreases in S02 and PM emis-
sions in the fifth year after the proposal of the NSPS.  Cost impacts are
evaluated in terms of increases in the total annualized costs for new boiler
and pollution control equipment capital, operating and maintenance and fuel
costs.  Energy impacts are assessed in terms of potential  shifts in the demand
between fuel types in small new boilers in the next five years.
2.1.2  Analytical Approach
      The estimates of baseline S02 and PM emissions  under current air
emissions standards are based on recent sales data by boiler size and fuel
type and assumptions about representative air emissions rates and annual
capacity utilization rates.  American Boiler Manufacturers Association (ABMA)
data for 1987 firebox, firetube and watertube boiler sales and recent
Hydronics Institute cast iron boiler sales data were multiplied times five to
project the total capacity of new small industrial-commercial-institutional
boilers constructed by the fifth year after proposal  of NSPS.  This assumes
that recent sales levels will not change over the next five years.*
      The sales data are national; therefore, only national projections are
presented in this report.
      It is assumed that all  new small  boilers have a 26%  capacity factor with
the concurrence of the American Boiler Manufacturers  Association.   These
boilers have relatively low annual capacity utilization rates due  to the
seasonal nature of space heating requirements.  PEOCo Environmental,  Inc.
reviewed commercial boiler data from Indiana, New York and Ohio.   For 324 coal
boilers with an average size  of 15 MW (50 MMBtu/hr),  the average  capacity
factor was 23.6 percent.  For 5,615 oil/gas boilers with an average size of 4
MW (13 MMBtu/hr), the average capacity factor was only 10.4 percent.1    Some
   Historical boiler sales data are summarized in Appendix B.
                                     2-2

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industrial boilers may have higher capacity utilization rates because they are
used to provide process steam as well as space heating.
      In this analysis, the fuel costs are estimated based on projected
regional delivered fuel prices over a fifteen-year period beginning  in 1992.
Given that the standard is proposed in 1989 and this analysis focuses on
projecting fifth year Impacts, 1992 is the mid-point of this five-year period.
These fuel prices have been annual 1 zed using a ten percent discount  rate.
      Naturally, there is uncertainty related to energy market conditions over
the next twenty years.  EEA developed two forecasts of fuel prices in order to
evaluate the sensitivity of the projected impacts of alternative air emissions
standards to this exogenous assumption, fuel prices.                   (
                   (
      Two crude oil price forecasts (reference the Low Oil Price Scenario and
the High Oil Price Scenario in Table 2-1) were developed by EEA in 1986 with
the U.S. Department of Energy (Office of Policy, Planning and Analysis) WOIL
forecasting model.  Table 2-1 compares EEA's two 1986 forecasts with other
recent projections.  EEA estimated regional commercial and Industrial distil-
late and residual fuel oil and natural gas prices for the Low Oil Price
Scenario and the High Oil Price Scenario in Table 2-1 .2>3  The Low Oil Price
Scenario and the High Oil Price Scenario fuel prices have been used  in this
national impacts analysis.
      The alternative air emissions standards are summarized in Table 2-2.
These regulations are preliminary options; they are not an exhaustive,
complete compilation of possible combinations of S02 and  PM emissions stan- .
dards.  It was assumed that flue gas desulfurization (FGO) systems are
relatively expensive for these small boiler sizes and low annual  capacity
utilization rates.  Therefore, the S02 emissions control  compliance strategy
is selecting low sulfur coal or oil types in response to the alternative NSPS
or choosing natural gas.  The cost impacts reflect the associated increased
fuel costs and monitoring and testing costs.
2.2  BASELINE AIR EMISSIONS AND FUEL NIX FORECASTS
      The baseline air emissions and fuel mix forecasts are based on recent
new boiler sales data.  These estimates are multiplied times five to project
national impacts in the fifth year after proposal of NSPS.  ABMA expects
                                      2-3

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                   TABLE  2-1.  CRUDE OIL PRICE PROJECTIONS9
                                 (1985 $/bb1)



Year
1985 actual
1986 actual
1990
1995
2000
2005
Low Oil
Price
Scenario1*
27
14
14
20
25
31
High Oil
Price
Scenario6
27
14
24
27
31
37


GRIC
27
14
19
22
25
32


DOE/EIAd
27
14
13-19
17-26
23-38
N.A.


DOE/EIAe
27
14
12-17
15-22
20-32
N.A.
8  Average U.S. refiner acquisition cost of crude oil.
b  Energy and Environmental Analysis,  Inc.  1986.   Reference 2.
c  Gas Research Institute.  1988.   Reference 7.
d  U.S. Department of Energy,  Energy Information  Administration.
   Reference 8.
*  U.S. Department of Energy,  Energy Information  Administration.
   Reference 9.
1988.

1989.
                                     2-4

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                        TABLE 2-2.  ALTERNATIVE  NSPS
                                         Emissions  ceiling
                                          ng/J  (Ib/MMBtu)
            Fuel type                  S02              PM
            Fuel oil                688  (1.6)          43  (0.1)
                                    344  (0.8)
                                    215  (0.5)
                                    129  (0.3)

            Coal                    516  (1.2)a         129 (0.3)
                                                       21  (0.05)
3  30-day rolling average.
                                      2-5

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 short-term  industrial-commercial-institutional boiler sales to remain  rela-
 tively  constant  at  recent  levels.
      New boiler sales data do not distinguish residual  (heavy) fuel oil
 versus  distillate (light)  fuel oil.  ABMA used their own burner sales  data to
 estimate this distribution for firebox, firetube and watertube boilers.   Oil-
 fired cast  iron  boilers were assumed to burn only distillate fuel oil.
      Table 2-3  summarizes ABMA's 1987 data for small new residual  fuel  oil
 boiler  sales.  ABMA estimated that there were no residual fuel (heavy)  oil
 boiler  sales for new  low pressure steam or hot water boilers <1000  HP  in  1987.
 The  average boiler  size for the new high pressure steam watertube/firebox/
 firetube boilers <1000 HP  in 1987 was about 2 MW (7 MMBtu/hr).  The average
 boiler  size for  the stationary watertube boilers 10,000-80,000 pounds  of
 steam/hour  (PPH)  in 1987 was about 16 MW (55 MMBtu/hr).
      The actual  locations of these boiler sales is not known and,  as  a
 result, the distribution of local air emissions regulations for these  small
 new  boiler  sales is not known.  It is assumed that the average baseline
 emissions rates  for the new high pressure steam watertube/firebox/  firetube
 boilers <1000 HP with no alternate fuel was 709 ng SO^J (1.65 Ib SO^MMBtu)
 and  56  ng PM/J (0.13  Ib PM/MMBtu).  These estimates were reduced for the
 oil/gas combination boilers.  The average baseline emission rates for  the
 larger  stationary watertube boilers were assumed to be 1,096 ng SOz/J  (2.55 Ib
 S(VMMBtu)  and 99 ng PM/J  (0.23 Ib PM/MMBtu);  these estimates were also
 reduced for the  oil/gas combination boilers.  These estimates may overstate
 average "baseline"  emissions to the extent that some of these new small
 boilers may be located in  urban areas with very low sulfur local air emissions
•standards.
      Table 2-4  presents.an estimate of the distribution of new small  residual
 fuel oil boiler  sales by si'ze class.  Recall that this estimate represents the
 data in Table 2-3 for 1987 times five years.  This size boiler distribution is
 an EEA  estimate;  the  1987  sales levels in these boiler size categories were
 not  provided by  ABMA.
      Table 2-5  summarizes ABMA's estimates of new small (<29 MW, <100
 MMBtu/hr) coal boiler sales in 1987.  ABMA estimated 44 new coal boilers  <1000
                                      2-6

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              TABLE 2-3.  RESIDUAL  FUEL OIL  BOILER SALES  IN  1987"
Number
of boilersb
S°2 b
emissions
metric (short
tons tons)
PM
emissions
metric (short
tons tons)
High pressure steam
  watertube/fi rebox/fi retube
  <1000 HP (<40 MMBtu/hr)
    oil with no alternate fuel
    oil/gas combination
 84
144
868
864
(957)
(952)
83
74
(91)
(82)
Stationary watertube boilers
10,000-80,000 PPH
(12-100 MMBtu/hr)
oil with no alternate fuel
oil with gas/alternate fuel
gas with oil/alternate fuel
Total

8
35
-3fl
301

1,068
2,812
1.374
6,986

(1,177)
(3,100)
n.sm
(7,701)

87
291
121
656

(96)
(321)
(133)
(723)
*  American Boiler Manufacturers Association data categories.
b  Reference 4.
                                      2-7

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               TABLE  2-4.  BASELINE RESIDUAL FUEL OIL BOILERS8

Boiler Size, MW (MMBtu/hr)
1-3 3-9 9-29 1-29
(3-10) (10-30) (30-100) (3-100)
Number of boilers 1,020 205 280
S02 emissions6
metric tons, Mg 5,801 6,169 22,961
(short tons) (6,395) (6,800) (25,310)
PM emissions6
metric tons, Mg 485 694 2,100
(short tons) (535) (765) (2,315)
1,505

34,931
(38,505)

3,279
(3,615)
a  Boiler sales over a five-year period.   Reference  6.
b  In the fifth year assuming  current  air emissions  regulations.
                                     2-8

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                    TABLE 2-5.  COAL BOILER SALES IN 1987
            Number of boilers                              50*

            S02 emissions
                metric tons, Mg                        3,620*
                (short tons)                           (3,990)a

            PM emissions
                metric tons, Mg                          509b
                (short tons)                             (561)b


•  American Boiler Manufacturers Association.  Reference 4.
b  Reference 5.
                                      2-9

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HP with an average size of 4 MW (15 MMBtu/hr)  and 6 new stationary coal
boilers <29 MW (<100 MMBtu/hr)  with an average size of 17 MW (60 MMBtu/hr)  in
1987.
      The average baseline emission rates for these new coal boilers are
assumed to be 1,526 ng SOj/J (3.55  Ib  SOj/MMBtu).  For the small  coal  boilers
<1000 HP, the baseline emission rate estimate is 193 ng PM/J (0.45 Ib
PM/MMBtu); 258 ng PM/J (0.6 Ib  PM/MMBtu)  is assumed for the larger stationary
coal boilers.
      Table 2-6 presents an estimate of the size distribution of new small
coal boilers by size class after five years of sales.  This boiler size
distribution is an EPA estimate; the 1987 sales levels in these boiler size
categories were not provided by ABMA.
      Distillate fuel oil boilers are also sources of S02 and PM emissions.
Table 2-7 summarizes the baseline estimates for this fuel type.  The average
emissions estimates are 129 ng  SOa/J  (0.3  Ib SOj/MMBtu) and  4 ng  PM/J  (0.01 Ib
PM/MMBtu).
      Cast iron boiler sales data were provided to EPA by the Hydronics
Institute (see Appendix B).  EEA estimated residential  versus commercial/in-
stitutional cast iron boiler sales.  Distillate versus residual fuel oil cast
iron boiler sales data were not available.  It was assumed that oil-fired cast
iron boiler sales were distillate fuel  oil units.   Table  2-7 includes oil-
fired commercial/institutional  cast iron  boilers,  oil-fired low pressure steam
and hot water watertube/firetube/firebox  light oil  boilers <1000 HP and light
oil stationary watertube boilers <29 MW (<100  MMBtu/hr).
      Baseline estimates for new small  natural  gas boilers are summarized in
Table 2-8.  Table 2-8 includes  commercial/institutional cast iron boilers as
well as watertube/firetube/firebox units  <1000 HP and stationary watertube
units <29 MW (<100 MMBtu/hr).   The average emission  rates estimates are 0.26
ng SOj/J (0.0006 Ib SO^MMBtu) and 4 ng PM/J "(0.01 Ib PM/MMBtu).
      The baseline fuel mix is  shown in Table  2-9.   Natural  gas and distillate
fuel oil are the predominant fuel  types for new units <9  MW (<30 MMBtu/hr).
      The baseline S02 and PM emissions estimates by  fuel  type  and  boiler size
class are summarized in Tables  2-10 and 2-11,  respectively.
                                     2-10

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                       TABLE 2-6.   BASELINE COAL BOILERS4

Boiler Size, MW (MMBtu/hr)
1-3 3-9 9-29 1-29
(3-10) (10-30) (30-100) (3-100)
Number of boilers 145 85
S02 emissions'*
metric tons, Mg 5,014 7,215
(short tons) (5,527) (7,953)
PM emissions6
metric tons, Mg 636 915
(short tons) (701) (1,009)
20 250

5,869 18,098
(6,470) (19,950)

993 2,545
(1,095) (2,805)
a  Boiler sales over a five-year period.
b  In the fifth year assuming current air emissions regulations.
                                     2-11

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             TABLE  2-7.  BASELINE DISTILLATE FUEL OIL BOILERS4

Boiler Size, MW (MMBtu/hr)
<1 1-3 3-9 9-29
(<3) (3-10) (10-30) (30-100)
Number of boilers 60,575 5,690 375
S02 emissions'1
metric tons, Mg 18,774 7,607 2,286
(short tons) (20,695) (8,385) (2,520)
PM emissions"
metric tons, Mg 626 295 100
(short tons) (690) (325) (110)
55

767
(845)

36
(40)
<29
(<100)
121,835

29,434
(32,445)

1,057
(1,165)
*. Boiler sales over a five-year  period.  References  5  and  6.   Excludes
   estimates of residential  boilers.

b  In the fifth year assuming  current  air emissions regulations.
                                     2-12

-------
                  TABLE  2-8.  BASELINE NATURAL GAS BOILERS4
                                    Boiler Size, MW (MMBtu/hr)
                                   1-3         3-9         9-29         <29
                                  (3-10)     (10-30)     (30-100)
Number of boilers
S02 emissions"
metric tons, Mg
(short tons)
PM emissions"
metric tons, Mg
(short tons)
62,325

39
(43)

644
(710)
7,400

23
(25)

381
(420)
580

8
(9)

145
(160)
115

5,
(5)

77
(85)
70,420

74
(82)

1,247
(1,375)
*  Boiler sales over a five-year period.  References 5 and 6.  Excludes
   estimates of residential boilers.

b  In the fifth year assuming current air emissions regulations.
                                     2-13

-------
                        TABLE  2-9.   BASELINE  FUEL  MIX*

Fuel Type
Natural gasb
Distillate
fuel oil0
Residual
fuel oil0
Coal
Total
Boiler Size, MW (MMBtu/hr)
<1 1-3 3-9 9-29 <29
(<3) (3-10) (10-30) (30-100) (<100)
62,325 7,400 580 115 70,420
60,575 5,690 375 55 66,695
0 1,020 205 280 1,505
0 145 85 20 250
122,900 14,255 1,245 470 138,870
a  Boiler sales over a five-year period;  total  number of boilers from Tables
   2-4 through 2-8.
b  Single-fuel units.
e  Single-fuel and oil/gas units.
                                     2-14

-------
                     TABLE  2-10.  BASELINE S02 EMISSIONS4
Fuel Type
  Boiler Size, MW (MMBtu/hr)
 1-3         3-9         9-29
(3-10)      (10-30)     (30-100)
                                                                        <29
(metric tons,
Natural gas
Distillate fuel oil
Residual fuel oil
Coal
Total
39
18,774
0
0
18,813
23
7,607
5,801
5.014
18,445
8
2,286
6,169
7.215
15,678
Mg)
5
767
22,961
5.869
29,601

74
29,434
34,931
18.098
82,537
(short tons)
Natural gas
Distillate fuel oil
Residual fuel oil
Coal
Total
43
20,695
0
0
20,738
25
8,385
6,395
5.527
20,332
9
2,520
6,800
7.953
17,282
5
845 .
25,310
6.470
32,630
82
32,445
38,505
19.950
90,982
   In the fifth year assuming current air emissions regulations.  Excludes
   estimates from residential boilers.  Reference Tables 2-4 through 2-8.
                                     2-15

-------
                  TABLE  2-11.  BASELINE PM EMISSIONS8

Fuel Type
Boiler Size, MW (MMBtu/hr)
<1 1-3 3-9 9-29
(<3) (3-10) (10-30) (30-100)
<29
(<100)
(metric tons, Mg)
Natural gas
Distillate fuel oil
Residual fuel oil
Coal
Total

Natural gas
Distillate fuel oil
Residual fuel oil
Coal
Total
644
626
0
__o
1,270

no
-690
0
	 0
1,400
381
294
485
636
1,797

420
325
535
701
1,981
145
100
694
915
1,854
(short tons)
160
110
765
1.009
2,044
77
36
2,100
993-
3,207

85
40.
2,315
1.095
3,535
1,247
1,057
3,279
2.545
8,128

1,375
1 , 165
3,615
2.805
8,960
In the fifth year assuming  current  air emissions  regulations.   Excludes
estimates from residential  boilers.   Reference Tables  2-4 through 2-8.
                                  2-16

-------
2.3  NATIONAL IMPACTS
      This section presents projections of national air emissions reductions
and Increases In total annual 1 zed pollution control costs from alternative S02
and PM NSPS for new small (<29 MW, <100 MMBtu/hr) 1ndustrial-commercial-
Institutional boilers in the fifth year after proposal of NSPS.  Results  are
presented assuming that the fuel mix under the alternative NSPS assumptions Is
Identical to the baseline estimates In Section 2.2 and also assuming that the
fuel mix under the alternative NSPS assumptions Is different than the baseline
estimates.  Results are presented for the Low Oil Price Scenario and the  High
Oil Price Scenario.
2.3.1  Alternative NSPS Fuel Mix 1s the Same as the Baseline Fuel Mix
2.3.1.1  Residual Fuel 011;  Low 011 Prices
      Table 2-12 presents projected residual fuel oil boilers S02 emissions
reductions by boiler size class.  It was assumed that small residual fuel oil
watertube/firetube/flrebox boilers burned medium sulfur oil in the baseline;
therefore, there is very little projected $03 emission reduction for a 688 ng
SOj/J (1.6 Ib SO^MMBtu)  emission  regulation  for  sizes <3 MW  (<10 MMBtu/hr).
The baseline residual fuel oil boiler S02 emissions  estimate  is 34,931 metric
tons (38,505 short tons), see Table 2-4.  A 688 ng SOj/J (1.6 Ib SOj/MMBtu)
standard is expected to reduce new small residual fuel oil boiler baseline S02
emissions by 28 percent.  A 344 ng SOj/J (0.8 Ib  SOe/MMBtu) control  level  is
forecasted to reduce new small residual fuel oil  boiler baseline S02 emissions
by 36 percent.  A 215 ng SOj/J (0.5 Ib SO^MMBtu) regulation  is  projected  to
reduce baseline S02 emissions by 78 percent.   A 129  ng SOj/J  (0.3 Ib
SOj/MMBtu)  limit will  reduce baseline S02  emissions  by 87 percent.
      Lower sulfur residual fuel oil types are also expected to reduce PM
emissions without the addition of any particulate matter emissions control
equipment.  Table 2-13 summarizes these expected PM emissions reductions.
      The annualized cost impacts without monitoring and testing costs
represent the fuel price increases associated with purchasing low sulfur
residual fuel oil types.  It is assumed that the fuel price increase (1985
dollars) for the stationary watertube boilers burning high sulfur residual
                                     2-17

-------
            TABLE  2-12.   PROJECTED  RESIDUAL  FUEL  OIL BOILER
                        S02 EMISSIONS REDUCTIONS4
  Alternative S02                       Boiler  size,  MW (MMBtu/hr)
  control  level                   1-3        3-9          9-29         1-29
 ng/J    (Ib/MMBtu)             (3-10)      (10-30)      (30-100)      (3-100)


                                          (metric  tons,  Mg)

  688       (1.6)                   176      1,320         8,554        10,050
  344       (0.8)                 2,989      3,745        15,757        22,491

  215       (0.5)                 4,043     ( 4,654        18,458        27,156

  129       (0.3)                 4,747      5,260        20,259        30,266


                                               (short  tons)
688
344
215
129
(1.6)
(0.8)
(0.5)
(0.3)
194
3,295
4,457
5,233
1,455
4,128
5,130
5,798
9,429
17,370
20,347
22,332
11,078
24,793
29,934
33,363
In the fifth year following  proposal of NSPS; reductions  from baseline
estimates.presented in Table 2-4;  alternative NSPS  fuel mix  is assumed to
be the same as the baseline  fuel mix.
                                 2-18

-------
            TABLE  2-13.  PROJECTED RESIDUAL FUEL OIL BOILER
                         PN  EMISSIONS REDUCTIONS4

Alternative S02
control level
ng/J (Ib/MMBtu)
Boiler size, MW (MMBtu/hr)
1-3 3-9 9-29
(3-10) (10-30) (30-100)
1-29
(3-100)
(metric tons, Mg)
688
344
215
129

688
344
215
129
(1-6)
(0.8)
(0.5)
(0.3)

(1.6)
(0.8)
(0.5)
(0.3)
0
176
246
317

0
194
271
349
130
281
. 342
403
(short
143
310
377
444
901
1,351
1,531
1,711
tons)
993
1,489
1,688
1,886
1,031
1,808
2,119
2,430

1,136
1,993
2,336
2,679
In the fifth year following proposal of NSPS; alternative NSPS fuel mix  is
assumed to be the same as the baseline fuel mix.
                                  2-19

-------
fuel oil In the baseline is S0.63/GJ  ($0.66/MMBtu)  to comply with the 129 ng
SOj/J  (0.3  Ib. SOa/MMBtu) limit.3  It is assumed that the fuel price increase
is S0.44/GJ ($0.46/MMBtu)  for the smaller watertube/firetube/firebox boilers
burning medium sulfur residual  fuel oil  in the baseline.3   Slightly smaller
fuel price premiums were used for the 215 ng SOz/J  (0.5  Ib  SO^MMBtu)
scenario.  For the 344 ng  SOz/J  (0.8  Ib  SO^MMBtu) control  level,  it  is
assumed that the fuel price increase  is  $0.47/60  ($0.50/MMBtu) for the
stationary watertube boilers and S0.28/GJ ($0.30/MMBtu)  for the smaller
watertube/fi retube/firebox boi1ers.
      The annualized cost  impacts for the Low Oil  Price  Scenario range from $4
million to $22 million (1985 dollars).   Table 2-14  presents estimates by
boiler size class.
      Cost-effectiveness is the annualized pollution control cost increase
divided by the expected annual  emissions reduction.   It  is  assumed that the PM
emissions reductions are incidental and  that the  total  annualized pollution
control cost increases can be compared with the expected S02 emissions
reductions.  If the total  annualized  pollution control  cost increases were
divided between the S02 and PM emissions  reductions,  then the S02  emissions
control cost-effectiveness ratios in  Tables 2-15  and 2-16 would be reduced.
      Cost-effectiveness ratios can be calculated  as average or incremental.
"Average" is calculated by comparisons with the baseline.   "Incremental"
ratios can be derived by comparing the results for  the  215  ng S02/J (0.5 Ib
SOz/MMBtu)  limit with the  688 ng  SOj/J (1.6 Ib SOj/MMBtu) standard and by
comparing the estimates for the 129 ng SOj/J  (0.3 Ib  SO^MMBtu) regulation
with the 215 ng SOj/J (0.5 Ib SO^MMBtu)  scenario.  Tables  2-15 and 2-16  show
the average and incremental S02 emissions  control cost-effectiveness  ratios
for residual fuel oil boilers by boiler  size category.
2.3.1.2  Residual Fuel 011;  High Oil  Prices
      It is assumed that the fuel price  increase  (1985 dollars) for the
stationary watertube boilers burning  high sulfur  residual fuel oil in the
baseline is S0.55/GJ ($0.58/MMBtu) to comply with the 344 ng SOj/J (0.8  Ib
SO^MMBtu)  limit; for this group  of boilers,  the fuel price increase  is
                                     2-20

-------
            TABLE  2-14.   PROJECTED ANNUALIZED COST INCREASES
                      FOR RESIDUAL FUEL OIL BOILERS8
                               (000 $1985)

Alternative S02
control level
ng/J (Ib/MMBtu)

688
344
215
129

688
344!
215
129

(1.6)
(0.8)
(0.5)
(0.3)

(1.61
(0.8)
(0.5-)
(0.3)
Boiler size, MW (MMBtu/hr)
1-3 3-9 9-29
(3-10) (10-30) (30-100)
Without
0
2,326
3,101
3,566
With
1,020
3,346
4,121
4,586
monitoring
575
2,577
3,245
3,646
monitoring
780
2,782
3,450
3,851
and testing
3,970
9,926
11,911
13,102
and testing
4,250
10,206
12,191
13,382
1-29
(3-100)
costs
4,545
14,829
18,257
20,314
costs"
6,050
16,334
19,762
21,819
In the fifth year following proposal of NSPS; alternative NSPS fuel mix  is
assumed to be the same as the baseline fuel mix; Low Oil Price Scenario.

Assumed to be $1,000 per year per boiler.  These estimates do not  include
the aggregate monitoring and testing costs for distillate fuel oil boilers,
                                  2-21

-------
            TABLE  2-15.   PROJECTED  RESIDUAL  FUEL  OIL BOILER
        AVERA6E S02 EMISSIONS  CONTROL  COST-EFFECTIVENESS RATIOS3
  Alternative S02                       Boiler  size,  MW (MMBtu/hr)
  control  level                   1-3        3-9          9-29         1-29
 ng/J    (Ib/MMBtu)             (3-10)      (10-30)      (30-100)     (3-100)


                                               (1985 $/Mg)

  688       (1.6)                   ---         591           497          602
  344       (0.8)                 1,119         743           648          726

  215       (0.5)                 1,019         741           660          728

  129       (0.3)                   966      ,   732           661          721


                                           (1985  $/short ton)

  688       (1.6)                   ---         536           451          546
  344..      (0.8)                 1,015         674           588          659

  215       (0.5)                   925         672           599          660

  129'       (0.3)                   876         664           599          654
Comparisons with the baseline;  with  monitoring  and  testing  costs;  alterna-
tive NSPS fuel  mix is assumed  to  be  the  same  as the baseline fuel  mix; Low
Oil Price Scenario.
                                  2-22

-------
               TABLE  2-16.  PROJECTED RESIDUAL FUEL OIL BOILER
          INCREMENTAL S02 EMISSIONS CONTROL COST-EFFECTIVENESS RATIOS9

Alternative S02
control level
ng/J (Ib/MMBtu)
Boiler size, MW (MMBtu/hr)
1-3 3-9 9-29
(3-10) (10-30) (30-100)
1-29
(3-100)
(1985 $/Mg)
688
344
215
129

688
344
215
129
(0.8)c
(0.5)d
(0.3)9

(o!s)c
(O..5)d
.(0.3)e
827
735
661

750
667
600
632
827
735
661
(1985 $/short
574
750
667
600
497
827
735
661
ton)
451
750
667
600
618
827
735
661

561
750
667
600
3  With monitoring and testing costs; alternative NSPS fuel mix is assumed to
   be the same as the baseline fuel mix; Low Oil Price Scenario.
b  Compared with the baseline.
0  Compared with the results for 688 ng/J (1.6 Ib/MMBtu).
d  Compared with the results for 344 ng/J (0.8 Ib/MMBtu).
e  Compared with the estimates for 215 ng/J (0.5 Ib/MMBtu).
                                     2-23

-------
S0.73/6J ($0.77/MMBtu) to comply with the 129 ng S
-------
           TABLE 2-17.  PROJECTED ANNUALIZED COST INCREASES
                      FOR RESIDUAL FUEL OIL BOILERS*
                               (000 $1985)

Alternative S02
control level
ng/J (Ib/MMBtu)

688
344
215
129

688
344
215
129

(1.6)
(0.8)
(0.5)
(0.3)

(1.6)
(0.8)
(0.5)
(0.3)
Boiler size, MW (MMBtu/hr)
1-3 3-9 9-29
(3-10) (10-30) (30-100)
Without
0
2,791
3,643
4,264
With
1,020
3,811
4,663
5,284
monitoring
630
3,035
3,770
4,190
monitoring
835
3,240
3,975
4,395
and testing
4,367
11,514
13,697 '
14,491
and testing
4,647
11,794
13,977
14,771
1-29
(3-100)
costs
4,997
17,340
21,110
22,945
costs"
6,502
18,845
22,615
24,450
In the fifth year following proposal of NSPS; alternative NSPS fuel mix is
assumed to be the same as the baseline fuel mix; High Oil Price Scenario.

Assumed to be $1,000 per year per boiler.  These estimates do not  include
the aggregate monitoring and testing costs for distillate fuel oil boilers.
                                  2-25

-------
            TABLE  2-18.   PROJECTED  RESIDUAL  FUEL OIL BOILER
        AVERAGE S02 EMISSIONS  CONTROL  COST-EFFECTIVENESS RATIOS3
  Alternative S02
  control  level
 ng/J    (Ib/MMBtu)
                           Boiler  size,  MW (MMBtu/hr)
                     1-3         3-9          9-29         1-29
                   (3-10)      (10-30)      (30-100)     (3-100)
  688
  344
  215
  129
(1.6)
(0.8)
(0.5)
(0.3)
5,796
1,275
1,153
1,113
 (1985 $/Mg)
633          543
865          748
856       ,   757
836          729
             647
             838
             833
             808
                                            (1985  $/short ton)
  688
  344
  215
  129
(1-6)
(0.8)
(0.5)
(0.3)
5,258
1,157
1,046
1,010
574
785
775
758:
493
679
687
661
587
760
755
733
Comparisons with the baseline;  with  mdnitoring  and  testing costs; alterna-
tive NSPS fuel  mix is assumed  to  be  the  same  as the baseline fuel mix; High
Oil Price Scenario; reference  Tables 2-12  and 2-17.
                                  2-26

-------
               TABLE  2-19.  PROJECTED RESIDUAL FUEL OIL BOILER
          INCREMENTAL S02 EMISSIONS CONTROL COST-EFFECTIVENESS RATIOS3

Alternative S02
control level
ng/J (Ib/MMBtu)
Boiler size, MW (MMBtu/hr)
1-3 3-9 9-29
(3-10) (10-30) (30-100)
1-29
(3-100)
(1985 $/Mg)
688
344
215
129

688
344
215
129
(1 6)b
(0.8)c
(0.5)d
(0.3)'

(1 6)b
(0.8)c
(0.5)d
(0.3)e
5,796
992
808
882

5,258
900
733
800
633
992
808
693
(1985
574
900
733
629
543
992
808
441
$/short ton)
493
900
733
400
647
992
808
590

587
900
733
535
a  With monitoring and testing costs; High Oil Price Scenario; reference
   Tables 2-12 and 2-17.
b  Compared with the baseline.
e  Compared with the results for 688 ng/J (1.6 Ib/MMBtu).'
d  Compared with the results for 344 ng/J (0.8 Ib/MMBtu).
9  Compared with the estimates for 215 ng/J (0.5 Ib/MMBtu).
                                     2-27

-------
       TABLE  2-20.   PROJECTED COAL BOILER  EMISSIONS REDUCTIONS3

Alternative
control level
ng/J (Ib/MMBtu)

516b (1.2)b


129 (0.3)

21 (0.05)

1-3
(3-10)

3,602
(3,971)

212
(234)
560
(617)
Boiler size
3-9
(10-30)

5,184
(5,714)

305
(336)
819
(903)
, MW (MMBtu/hr)
9-29
(30-100)
S02
4,214
(4,645)
PM
496
(547)
911
(U004)
1-29
(3-100)

13,000
(14,330)

1,013
(1,117)
2,290
(2,524)
In the fifth year following proposal  of NSPS;  reductions from baseline
estimates presented in Table 2-6;  alternative  NSPS fuel mix'is assumed  to
be the same as the baseline fuel  mix.

30-day rolling average.
                                  2-28

-------
      Table 2-21 shows the projected annualized pollution control cost
increases for coal boilers by boiler size class.  The S02 emissions control
costs without monitoring and testing are based on a fuel price increase of
S0.31/6J ($0.33/MMBtu), 1985 dollars.3  The S02 emissions control  monitoring
and testing costs are assumed to be $31,000 per year per boiler.*
      The PM emissions control costs for the 129 ng PM/J (0.3 Ib  PM/MMBtu)
standard is based on the annualized capital and O&M costs for a double
mechanical collector; a fabric filter is the applicable control equipment type
for the 21 ng PM/J (0.05 Ib PM/MMBtu) regulation.  The PM emissions control
monitoring and testing costs are assumed to be $16,000 per year per boiler.*
The coal boiler emissions control cost-effectiveness ratios are summarized  in
Table 2-22.
2.3.1.4  Distillate Fuel Oil
      Significant S02 and PM emissions reductions from distillate fuel oil
combustion are not expected.  The baseline average emissions estimates are  129
ng S02/J (0.3 Ib SOj/MMBtu)  and 4 ng  PM/J  (0.01 Ib PM/MMBtu).
2.3.2  Alternative NSPS Fuel Mix 1s Different than the Baseline Fuel Mix
      Very low sulfur residual fuel oil may not be readily available in all
areas of the country with access to medium or high sulfur residual fuel oil
supplies.  In order to comply with the alternative S02 emission  limits where
very low sulfur residual fuel oil is not available,  flue gas desulfurization
(FGD) systems could be installed or other compliance fuels (e.g., distillate
fuel oil or natural gas) could be purchased.
      The national projections of the annualized cost increases and emissions
reductions associated with alternative NSPS will be different (than the
estimates presented in Section 2.3.1) if the compliance strategies are a mix
of very low sulfur residual fuel  oil  and other alternatives.  For sensitivity
analyses purposes, it was assumed that half of the residual  fuel  oil demand in
the baseline would select compliance very low sulfur residual fuel oil and
half would choose distillate fuel oil under the alternative NSPS.
   These monitoring and testing cost estimates do not necessarily reflect the
   average costs associated with the proposed standards.

-------
               TABLE 2-21.
PROJECTED ANNUALIZED COST INCREASES
  FOR COAL BOILERS*
     (000 $1985)

Alternative Monitoring Boiler size, MW (MMBtu/hr)
control level and 1-3 3-9 9-29
ng/J (Ib/MMBtu) testing (3-10) (10-30) (30-100)
so2
516b (1.2)b No . 1,027 1,478 1,202
Yes 5,522 4,113 1,822
PM
129 (0.3) No 2,755 1,870 645
Yes 5,075 3,230 965
21 (0.05) No 5,945 5,860 2,830
Yes 8,265 7,310 3,150
1-29
(3-100)

3,707
11,457

5,270
9,270
14,725
18,725
a  In the fifth year following  proposal  of NSPS;  alternative NSPS fuel mix is
   assumed to be the same as the  baseline  fuel  mix.

°  30-day rolling average.
                                   2-30

-------
TABLE 2-22.  PROJECTED COAL BOILER EMISSIONS CONTROL
             COST-EFFECTIVENESS RATIOS*
            1985 $/Ng (1985 $/short ton)

Alternative Boiler size,
control level 1-3 3-9
ng/J (Ib/MMBtu) Type (3-10) (10-30)

516b (l-2)b Average 1,533
(1,391)

129 (0.3) Average 23,940
(21,690)
21 (0.05) Average 14,760
(13,400)
21 (0.05) Incremental0 9,170
(8,330)
a With monitoring and testing costs.
" 30-day rolling average.
** Ps^mna v*a/4 ui-i + ki + ha v*Ac»ii1 +o £r\v* TOO n/-i DM/

793
(720)

10,590
(9,610)
8,930
(8,100)
7,940
(7,200)


i in -s m D
MW (MMBtu/hr)
9-29
(30-100)
so2
432
(392)
PM
1,950
(1,760)
3,460
(3,140)
5,270
(4,780)


M/MMD+ii \
1-29
(3-100)

881
(800)

9,150
(8,300)
8,180
(7,420)
7,400
(6,720)



                        2-31

-------
The average emissions estimates for distillate fuel  oil are 129 ng S02/J (0.3
Ib SOa/MMBtu)  and 4 ng PM/J (0.01  Ib PM/MMBtu).
      Tables 2-23 and 2-24 summarize the projected emissions reductions.
Compared with the projections in Tables 2-12 and 2-13, these estimates  are  not
substantially different.
2.3.2.1  Low 011 Price Scenario
      The baseline projection of new small  residual  fuel oil boilers  is not
available by location or by economic sector (industrial versus commercial/in-
stitutional).   The fuel price differences between residual and distillate fuel
oils may vary by location and economic sector.  As a result, two estimates
(Tables 2-25 and 2-26) of the projected annualized cost increases have  been
prepared.  The cost assumptions in Table 2-25 reflect Midwest industrial
distillate fuel oil prices, whereas the cost assumptions in Table 2-26  are
illustrative of higher East Coast commercial distillate fuel oil prices.3
      The monitoring and testing costs are assumed to be applicable to
distillate fuel oil boilers for the 129 ng S2/J (0.5 Ib
StVMMBtu)  emission limit without the  expense  of  fuel  sampling  or  certifr
ication.
      The projected S02 emissions control cost-effectiveness ratios  in Tables
2-27 and 2-28 reflect monitoring and testing costs,  fuel price increases and
S02 emissions  reductions for the baseline residual fuel  oil  boilers  as well  as
the monitoring and testing costs (without any expected S02 emissions reduc-
tions) for the baseline distillate  fuel  oil boilers.   It is assumed that the
PM emissions reductions are incidental and  that the  total  annualized pollution
control cost Increases can be compared with the expected S02 emissions
reductions.  If the total annualized pollution control cost increases were
divided between the S02 and PM  emissions  reductions, then  the S02 emissions
control cost-effectiveness ratios  in Tables 2-27  and  2-28 would be reduced.
2.3.2.2  High 011 Price Scenario
      As above, two estimates of the projected annual ized cost  increases have
been developed; Table 2-29 reflects Midwest industrial distillate  fuel oil
                                     2-32

-------
            TABLE  2-23.  PROJECTED RESIDUAL FUEL OIL BOILER
                        S02 EMISSIONS REDUCTIONS3
  Alternative S02                      Boiler size, MW (MMBtu/hr)
  control level                  1-3        3-9         9-29          1-29
 ng/J    (Ib/MMBtu)            (3-10)     (10-30)     (30-100)      (3-100)


                                            (metric tons, Mg)

  344       (0.8)                3,868      4,502       18,009        26,379
  215       (0.5)                4,394      4,956       19,358        28,709
  129       (0.3)                4,745      5,259       20,258        30,263


                                                (short tons)
344
215
129
(0.8)
(0.5)
(0.3)
4,264
4,844
5,231
4,963
5,463
5,797
19,851
21,339
22,331
29,078
31,646
33,359
In the fifth year following proposal of NSPS; reductions from baseline
estimates in Table 2-4; alternative NSPS fuel mix is assumed to have less
residual fuel oil and more distillate.fuel oil than the baseline fuel mix.
                                  2-33

-------
            TABLE 2-24.  PROJECTED RESIDUAL FUEL OIL BOILER
                        PN EMISSIONS REDUCTIONS4

Alternative S02
control level
ng/J (Ib/MMBtu)

1-3
(3-10)
Boiler size,
3-9
(10-30)
MW (MMBtu/hr)
9-29
(30-100)

1-29
(3-100)
  344
  215
  129
(0.8)
(0.5)
(0.3)
291
327
361
                                            (metric  tons,  Mg)
381
411
442
1,646
1,736
1,826
2,318
2,473
2,629
  344
  215
  129
(0.8)
(0.5)
(0.3)
321
360
398
                                                (short  tons)
420
453
487
1,814
1,914
2,013
2,555
2,727
2,898
In the fifth year following  proposal of NSPS; alternative  NSPS  fuel  mix is
assumed to have less  residual  fuel oil and more distillate fuel  oil  than
the baseline fuel mix.
                                 2-34

-------
               TABLE 2-25.
             PROJECTED ANNUALIZED COST INCREASES
                FOR OIL BOILERS*
                   (000 $1985)
     Alternative S02
     control level
    ng/J    (Ib/MMBtu)
                           Boiler size, MW (MMBtu/hr)
                     1-3        3-9         9-29         1-29
                   (3-10)     (10-30)     (30-100)     (3-100)
     344
     215
     129
(0.8)
(0.5)
(0.3)
                                      Without monitoring and testing  costs
4,884
5,271

5,504
4,781
5,115

5,315
16,476
17,468

18,064
26,141
27,854

28,883
                                         With monitoring and testing  costs
344
. 215
129
(0.8)
(0.5) .
(0.3)
5,394j;
5,781b
12,214C
4,883b
5,217b
5,895C
- 16,616b
17,608b
' 18,399C
26,893"
28,606b
36,508C
a  In the fifth year following proposal of NSPS; alternative NSPS  fuel mix  is
   assumed to have less residual fuel oil and more distillate fuel oil than
   the baseline fuel mix; Low Oil Price Scenario.

b  $1,000 per year per residual  fuel oil boiler.

c  $1,000 per year per residual  and distillate fuel oil boiler.
                                     2-35

-------
               TABLE 2-26.  PROJECTED ANNUALIZED COST INCREASES
                               FOR OIL  BOILERS3
                                  (000 $1985)

Alternative S02
control level
ng/J (Ib/MMBtu)

344
215
129

344
215
129

(0.8)
(0.5)
(0.3)

'(0.8)
(0.5)
(0.3)
Boiler size, MW (MMBtu/hr)
1-3 3-9 9-29
(3-10) (10-30) (30-100)
Without
7,711
8,101
8,331
With
8,221b
8,611b
15,041C
monitoring
7,220
7,554
7,757
monitoring
7,322b
"7,656b
- 8,337C
and testing
23,722
24,714
25,310
and testing
23,862b
24,854b
25,645C
1-29
(3-100)
costs
38,653
40,369
41,398
costs
39,405b
41.1216
49,023C
a  In the fifth year following proposal of NSPS; alternative NSPS  fuel  mix is
   assumed to have less residual  fuel oil and more distillate fuel  oil  than
   the baseline fuel mix; Low Oil Price Scenario.

b  $1,000 per year per residual fuel  oil  boiler.

c  $1,000 per year per residual and  distillate fuel  oil  boiler.
                                     2-36

-------
            TABLE 2-27.   PROJECTED OIL BOILER S02 EMISSIONS CONTROL
                      AVERAGE COST-EFFECTIVENESS RATIOS8
Alternative
S02 control
  level                1-3
ng/J  (Ib/MMBtu)     (3-10)
                                      Boiler Size,  MW (MMBtu/hr)
                                3-9           9-29              1-29
                              (10-30)        (30-100)           (3-100)
344     (0.8)      1,394-2,125
215     (0.5)      1,316-1,959

129     (0.3)      2,574-3,169
                                              (1985 $/Mg)
                            1,084-1,626
                            1,053-1,545

                            1,121-1,585
                                 923-1,325
                                 909-1,284

                                 908-1,265
                               1,019-1,494
                                 996-1,432

                               1,206-1,620
344
215

129
(0.8)
(0.5)

(0.3)
1,265-1,928
1,193-1,777
2,335-2,875
                                            (1985 $/short ton)
  984-1,475
  955-1,401
1,017-1,438
837-1,202
825-1,164

824-1,148
  925-1,355
  904-1,299

1,095-1,470
   With monitoring and testing costs; alternative NSPS fuel mix is assumed to
   have less residual fuel oil and more distillate fuel oil than the baseline
   fuel mix; Low Oil Price Scenario.
                                     2-37

-------
           TABLE 2-28.  PROJECTED OIL BOILER S02 EMISSIONS CONTROL
                     INCREMENTAL COST-EFFECTIVENESS  RATIOS9

Alternative SQ2
control level
ng/J (Ib/MMBtu)

215 (0.5)b
129 (0.3)c

215 (0.5)b
129 (0.3)c
Boiler size, MW (MMBtu/hr)
1-3 3-9 9-29
(3-10) (10-30) (30-100)
(1985 $/Mg)
735 735
18,324 2,243
(1985 $/short
667 667
16,623 2,034

735
879
ton)
667
797
1-29
(3-100)

735
5,085

667
4,613
"  With monitoring and testing costs; alternative NSPS fuel mix is assumed  to
   have less residual fuel oil and more distillate fuel oil than the baseline
   fuel mix; Low Oil Price Scenario.

6  Compared with the results for 344  ng/J (0.8 Ib/MMBtu).

c  Compared with the estimates for 215 ng/J (0.5 Ib/MMBtu).
                                     2-38

-------
            TABLE 2-29.  PROJECTED ANNUALIZED COST INCREASES
                             FOR OIL BOILERS4
                               (000 $1985)

Alternative S02
control level
ng/J (Ib/MMBtu.)

344
215
129

344
215
129

(0.8)
(0.5)
(0.3)

(0.8)
(0.5)
(0.3)
Boiler size, MW (MMBtu/hr)
1-3 3-9 9-29
(3-10) (10-30) (30-100)
Without
6,279
6,705
7,016
With
6,789b
7,215b
13,726C
monitoring
6,041
6,408
6,675
monitoring
6,143b
6,510b
7,255C
and testing
20,446
21,537
22,331
and testing
20,586b
21,677b
22,666C
1-29
(3-100)
costs
32,766
34,650
36,022
costs
33,518b
35,402b
43,647C
In the fifth year following proposal of NSPS; alternative NSPS fuel mix is
assumed to have less residual fuel oil and more distillate fuel oil than
the baseline fuel mix; High Oil Price Scenario.

$1,000 per year per residual fuel oil boiler.

$1,000 per year per residual and distillate fuel oil boiler.
                                  2-39

-------
prices and Table 2-30 is based on higher East Coast commercial distillate fuel
oil prices.3
      The monitoring and testing costs are assumed to be applicable to
distillate fuel  oil  boilers for the 129 ng S(yj  (0.3  Ib SOs/MMBtu)  regula-
tion, but not for the 215 ng StVJ  (0.5  Ib SCyMMBtu)  standard.  Distillate
fuel oil  is assumed  to be a compliance fuel for the 215 ng S02/J (0.5 Ib
SO^MMBtu)  emission  limit without the  expense of  fuel  sampling or  certif-
ication.
      The projected  S02 emission  control  cost-effectiveness  ratios in Tables
2-31 and 2-32 reflect monitoring and testing costs, fuel price increases and
S02 emission reductions for the  baseline residual  fuel  oil  boilers as well  as
the monitoring and testing costs (without any expected S02 emissions reduc-
tions) for the baseline distillate  fuel  oil boilers.   It is assumed that the
PM emissions reductions are incidental and that the total annualized pollution
control cost increases can be compared with the expected S02 emissions
reductions.  If the  total annualized pollution control cost increases were
divided between the  S02 and PM emissions reductions,  then the S02  emissions
control cost-effectiveness ratios in Tables 2-31  and  2-32 would be reduced.
2.3.3  Summary of Projected Emissions  Reductions
      Tables 2-33 and 2-34 summarize the expected S02  and PM emissions
reductions in the fifth year following proposal  of NSPS.  These forecasts may
be understated if residual fuel  oil  and coal  boiler sales increase above
recent levels.
                                     2-40

-------
               TABLE 2-30.  PROJECTED ANNUALIZED COST  INCREASES
                                FOR OIL BOILERS9
                                  (000 $1985)
     Alternative S02                      Boiler size, MW  (MMBtu/hr)
     control level                  1-3        3-9         9-29          1-29
    ng/J    (Ib/MMBtu)             (3-10)      (10-30)     (30-100)      (3-100)


                                      Without monitoring and testing  costs


     344       (0.8)                9,222      8,580       27,990      45,792
     215       (0.5)                9,649      8,948       29,082      47,679

     129       (0.3)                9,959      9,215       29,876      49,050


                                         With monitoring and testing  costs
344
215
129
(0.8)
(0.5)
(0.3)
9,732!*
10,159b
16,669C
8,682b
9,050b
9,795C
28,130b
29,222b
30,211C
46,544b
48,431b
56,675e
a  In the fifth year following proposal of NSPS; alternative NSPS fuel mix  is
   assumed to have less residual fuel oil and more distillate fuel oil than
   the baseline fuel mix; High Oil Price Scenario.

b  $1,000 per year per residual fuel oil boiler.

c  $1,000 per year per residual and distillate fuel oil boiler.
                                     2-41

-------
            TABLE  2-31.   PROJECTED OIL BOILER S02 EMISSIONS CONTROL
                      AVERAGE COST-EFFECTIVENESS RATIOS*

Alternative
SO? control
level
ng/J (Ib/MMBtu)

344
215
129

(0.8)
(0.5)
(0.3)
Boiler Size, MW (MMBtu/hr)
1-3 3-9 9-29 1-29
(3-10) (10-30) (30-100) (3-100)
(1985 $/Mg)
1,755-2,516 1,365-1,928 1,143-1,562 1,271-1,764
1,642-2,312 1,314-1,826 1,120-1,510 1,233-1,687
2,893-3,513 1,380-1,863 1,119-1,491 1,442-1,873
344     (0.8)      1,592-2,282
215     (0.5)      1,489-2,097

129     (0.3)      2,624-3,187
                                            (1985 $/short ton)
1,238-1,749
1,192-1,657

1,252-1,690
1,037-1,417
1,016-1,369

1,015-1,353
1,153-1,601
1,119-1,530

1,308-1,699
   With monitoring and testing  costs;  alternative  NSPS fuel  mix is assumed to
   have less residual fuel  oil  and more distillate fuel  oil  than the baseline
   fuel mix; High Oil Price Scenario.
                                     2-42

-------
           TABLE  2-32.   PROJECTED OIL  BOILER  S02 EMISSIONS CONTROL
                     INCREMENTAL COST-EFFECTIVENESS RATIOS8

Alternative S02
control level
ng/J (Ib/MMBtu)

215 (0.5)b
129 (0.3)c

215 (0.5)b
129 (0.3)c
Boiler size, MW (MMBtu/hr)
1-3 3-9 . 9-29
(3-10) (10-30) (30-100)
(1985 $/Mg)
809 809
18,547 ( 2,459
(1985 $/short
734 734
16,822 2,231

809
1,099
ton)
734
997
1-29
(3-100)

809
5,305

734
4,813
8  With monitoring and testing costs; alternative NSPS fuel mix  is assumed  to
   have less residual fuel oil and more distillate fuel oil than the baseline
   fuel mix; High Oil Price Scenario.

b  Compared with the results for 344 ng/J (0.8 Ib/MMBtu).

c  Compared with the estimates for 215 ng/J (0.5 Ib/MMBtu).
                                     2-43

-------
                       TABLE 2-33.   SUMMARY OF EXPECTED
                           S02  EMISSIONS  REDUCTIONS4
Fuel  type
              Alternative S02
               control  level         1-3
             ng/J   (Ib/MMBtu)     (3-10)
                                             Boiler size,  MW (MMBtu/hr)
                                                3-9       9-29         1-29
                                             (10-30)     (30-100)      (3-100)
Residual
fuel  oil
Coal
             688
             344
             215
             129

             516
                    (1.6)
                    (0.8)
                    (0.5)
                    (0.3)
  0.2
2.9-3.9
4.0-4.4
  4.7

  3.6
                                             (103 metric  tons)
  1.3
3.7-4.5
4.7-5.0
  5.2

  5.2
  8.6
15.8-18.0
18.4-19.4
  20.3

  4.2
  10.1
22.5-26.4
27.2-28.7
  30.3

  13.0
                                             (103 short  tons)
Residual
fuel oil
Coal
             688
             344
             215
             129

             516
                    (1.6)
                    (0.8)
                    (0.5)
                    (0.3)

                    (1.2)1
  0.2
3.3-4.3
4.4-4.8
  5.2

  4.0
  1.5
4.1-5.0
5.1-5.5
  5.8

  5.7
  9.4
17.4-19.9
20.3-21.3
  22.3

  4.6
  11.1
24.8-29.1
29.9-31.6
  33.4

  14.3
   In the fifth year following proposal  of NSPS;  reductions from baseline
   estimate.

   30-day rolling average.
                                     2-44

-------
                       TABLE 2-34.  SUMMARY OF EXPECTED
                            PM EMISSIONS REDUCTIONS4
Fuel type
   Alternative
  control level        1-3
ng/J   (Ib/MMBtu)    (3-10)
                         Boiler size, MW (MMBtu/hr)
                            3-9       9-29         1-29
                         (10-30)    (30-100)      (3-100)
Residual
fuel oil
                 SO,
688
344
215
129
(1.6)
(0.8)
(0.5)
(0.3)
                     (103 metric tons)
   0
0.2-0.3
0.2-0.3
0.3-0.4
  0.1
0.3r0.4
0.3-0.4
  0.4
  0.9
1.4-1.6
1.5-1.7
1.7-1.8
  1.0
1.8-2.3
2.1-2.5
2.4-2.6
Coal
                 PM
129
 21
(0.3)
(0.05)
  0.2
  0.6
  0.3
  0.8
  0.5
  0.9
  1.0
  2.3
Residual
fuel oil
Coal
                 .S02
688
344
215
129
129
 21
(1.6)
(0.8)
(0.5)
(0.3)
                 PM
(0.3)
(0.05)
                     (103 short tons)
  0
0.2-0.3
0.3-0.4
0.3-0.4
  0.2
  0.6
  0.1
0.3-0.4
0.4-0.5
0.4-0.5
  0.3
  0.9
  1.0
1.5-1.8
1.7-1.9
1.9-2.0
  0.5
  1.0
  1.1
2.0-2.6
2.3-2.7
2.7-2.9
  1.1
  2.5
   In the fifth year following proposal of NSPS; reductions from baseline
   estimate.
                                     2-45

-------
                                  REFERENCES
1.    Program Office Support:   Environmental  Impacts of Fossil Fuel Utiliza-
      tion.   PEDCo Environmental,  Inc.  Cincinnati,  Ohio.  Prepared for the
      U.S.  Environmental  Protection Agency,  Industrial  Environmental Research
      Laboratory.   Draft  Final.   1980.   p.  2-16.

2.    Projections  of Industrial  Fuel  Oil  and  Natural Gas Prices.  Energy and
      Environmental Analysis,  Inc., Arlington,  Virginia.  Prepared for the
      U.S.  Environmental  Protection Agency, Office  of Air Quality Planning  and
      Standards.   October 1986.

3.    Letter and  attachments from Hogan,  T.  (EEA)  to Link, T. (EPA/EAB).
      Regional Commercial Oil  and Gas Price Forecasts.   July 16, 1987.
      Letter and  attachments from Hogan,  T.  (EEA)  to Link, T. (EPA/EAB).
      Annualized  Commercial  Oil  and Gas Prices.  July 28, 1987.
      Letter and  attachments from Hogan,  T.  (EEA)  to Link, T. (EPA/EAB).
      Annualized  Industrial  Fuel  Prices.   June  5,  1987.

4.    Letter from Hogan,  T.  (EEA)  to Pahel-Short,  R. (EPA/ESD).  Revised Small
      Boiler Baseline S02 Emissions.  October 17, 1988.

5.    Letter from Hogan,  T.  (EEA)  to Pahel-Short,  R. (EPA/ESD).  Small Boiler
      Baseline PM Emissions  Estimates.   November 3,  1988.

6.    Letter from Hogan,  T.  (EEA)  to Pahel-Short,  R. (EPA/ESD).  Revised
      Baseline Estimates  for New Small  Boilers  by  Fuel  Type.  October 18,
      1988.

7.    Holtberg, P. et al.  Baseline Projection  Data  Book.  1988 GRI Baseline
      Projection  of U.S.  Energy  Supply  and  Demand  to 2010.  Gas Research
      Institute.   Washington,  D.C.   December  1988.   p.  14.

8.    Annual Energy Outlook  1987 With Projections  to 2000.  U.S. Department of
      Energy, Energy Information Administration.  DOE/EIA-0383(87).  March
      1988.

9.    Annual Energy Outlook  1989 With Projections to 2000.  U.S. Department of
      Energy, Energy Information Administration.  DOE/EIA-0383(89).  January
      1989.
                                     2-46

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             3.  ECONOMIC IMPACTS:   COMMERCIAL/INSTITUTIONAL SECTOR

 3.1   INTRODUCTION
       The assessment of the potential  economic Impact of a NSPS on commer-
 cial/Institutional  (C/I) boilers was organized two ways.  One set of analyses
 focused on the Impact of new regulations on "generic" buildings where boilers
 are  used only for space and hot water heating •-  the predominant use of
 boilers in commercial/institutional  buildings. Here the impacts of potential
 regulatory costs are related to the operating budgets and rental rates of
 commercial buildings.  A second set of analyses focused on selected commercial
 sectors where economic impacts might be more severe than for "generic" build-
 ings.   For example,  applications such as laundries or hospitals, where steam
 is used for specialized purposes other than space heating,  could lead to more
 significant economic impacts for those sectors.
       This analysis  is focused on  the impacts of  "model  plants" intended to be
 representative of various situations where boilers are used in the C/I sector.
 In most instances, the model plant is actually one building where boilers
 provide various energy services, depending on the activities of the building
 occupants.  An example of this situation is a building where boilers are used
 exclusively for space and hot water heating.   In  some commercial sector
 applications, such as hotel  chains or large commercial  laundries,  one firm may
 own  several buildings or "model plants."  In these cases,  we have tried to
 focus  on the specific building or boiler installation as our model  unit for
,analysis.  We have done so because a business with multiple plants will
 consider the economic viability of each of its plants.
       An important aspect of the economic analysis for C/I  boilers is that it
 should be viewed as  a "worst case" analysis intended to  identify the limits of
 possible adverse consequences of a NSPS.  The reasons why this should be
 viewed as a "worst case" analysis  are:
   •  Only very stringent regulatory scenarios are considered such as
       very low sulfur residual oil or installation of flue gas desul-
       furization equipment.
   •  These stringent regulations  are applied to  all  boiler sizes in the
       model building analyses, ignoring the effect of a  boiler size cut-
       off; the proposed NSPS may not be applicable to all  of these
       boiler sizes.

-------
   t  In buildings with more than  one boiler installed,  we have assumed
      that all boilers in the building would be  subject  to the NSPS.  In
      fact; most new boilers would be replacements  in existing build-
      ings  and not all  of the existing boilers would necessarily be
      replaced at the same time.
   •  We have made no allowance  for the fact that several  urban areas
      already have regulations.   In effect,  the  baseline for considering
      impacts of the NSPS implies  no (or  very lax)  regulatory controls
      are currently in place.
   •  The analysis assumes that  the boilers  are  firing a dirty fuel
      (e.g. residual oil) rather than natural  gas.   The  impacts pre-
      sented here would be applicable only when  such dirty fuels are
      fired.  In fact, natural gas is currently  the predominant fuel
      choice in C/I boilers.*
All of these considerations tend to overstate the likely economic impacts of
any NSPS, emphasizing that this  is a "worst  case" type of analysis.
3.2  SELECTED SECTORS
3.2.1  Approach
      The goals in this phase of the study are threefold:  1)  identify those
boiler applications which would  likely incur economic impacts from a New
Source Performance Standard for  small  boilers  used  in commercial/institutional
buildings; 2) select from each sector several  "example"  firms for which suf-
ficient data on boiler use and establishment sales  could be obtained; and 3)
examine pollution control cost impacts for each  selected firm/sector.
      Several factors were considered in  selecting  specific end uses.  One
factor was to try to identify applications which use boilers  for other
purposes beside space heating, such as cooking,  baking,  sterilization.  To the
extent that energy usage'is more intensive (Btus per dollar of sales),
economic impacts would tend to be  greater.   Another consideration might be an
application which tends to have  a  low ratio  of business  sales/revenue per
square foot of building space.   In such  instances,  increases  of building
operating costs would tend to have a more significant effect  on price
increases needed to sustain profitability.   Motels  or hotels  and some labor
service activities could be examples where building operating costs are a more
   See Appendix A

-------
significant element in the total costs of the firm.  Still another factor
would be to consider public entities, such as schools, which are widespread
and where the economic impacts take the form of increases in local government
budgets.
      Important examples of commercial/institutional establishments that use
boilers for applications other than space heating include laundries, hospitals
and some hotels.  These three groups have been included in this analysis
because they have daily special steam demand requirements that are distinct
from the seasonal space heating requirements in generic buildings.
      Colleges and universities have also been included in this selected
sectors analysis.  This group uses relatively large boilers in central heating
facilities and sends steam or hot water through underground pipes to most or
all of the numerous buildings on campus.  This group is distinct from the
generic buildings discussed in Section 3.3 because the typical college/uni-
versity boiler sizes are substantially larger than the typical boilers in
commercial "generic" buildings.
      Elementary and secondary schools are another "selected sector."  Elemen-
tary and secondary schools use boilers for seasonal space heating purposes
like generic buildings.  They are analyzed in this section (as opposed to
Generic Buildings, Section 3.3) because comparing pollution control costs to
building rental rates is not appropriate for this group.
3.2.2  Data Sources and Descriptions of Selected Sectors
      Data on the boiler configuration and total annual costs/revenues per
establishment for large and small firms within each selected sector have been
gathered through telephone contacts and reviews of published company financial
statements.  (In performing this part of the analysis, effort has focused on
publicly-owned companies due to government rules limiting contacts with
individual firms)-.  Specifically, the following information has been obtained:
         Number and size of boilers per establishment
         Annual hours of operation per boiler
         Boiler fuel type
         Annual boiler fuel use and expenditures
                                      3-3

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         Building (or establishment)  size (sq.  feet)

         Annual total revenues (or total  expenditures) per establishment

      In some instances data on annual  boiler fuel  use, annual boiler fuel

expenditures and/or establishment-specific total  annual revenues were unavail-
able.  Therefore, estimates of these  data were made using the following pro-

cedures:

   •  Annual Boiler Fuel Consumption
      Data are collected on: 1) boiler heat input (in MMBtu/hr), 2)
      average daily number of hours of boiler operation, and 3) average
      number of days per year of boiler use for establishments in each
      selected sector.  The product of these three  variables yields an
      estimate of total boiler fuel consumption for an establishment.
   0  Annual Boiler Fuel Expenditures
      Where data on total annual  boiler fuel expenditures are not
      forthcoming, information has been obtained  on the average mix of
      fuels used in the boiler and average annual fuel prices per MMBtu.
      These data have been used in conjunction with the boiler fuel use
      estimates to calculate total fuel expenditures.

   0  Annual Total Revenues (or Expenditures) per Establishment
      As noted earlier, information on  establishment-specific total
      sales (or total costs) is a key requirement for evaluating             —
      economic impact.  This also is  the information most difftcult to
      obtain from individual companies  and institutions.  Therefore,
      estimates have been made using  a  variety of approaches and other
      data as follows:

      Elementary and Secondary Schools:

      Total Cost per School - (pupils/school) * (cost/pupil)
      Hospitals

      Total Cost per Hospital - (beds/hospital) * (cost/bed)
      Hotels

      Total Sales - (rooms/hotel) * (average occupancy rate)
         * (average daily room rate)  *  365 days/year

      Laundries    Total Sales per facility -
                -  (total company sales)  * (facility sq. ft)/
                -.  (total sq. ft of all company facilities)

Elementary and Secondary Schools

      Boiler configuration data for 100 boilers in  elementary and secondary

schools in Illinois, provided by the  Illinois Environmental  Protection Agency,

show that all of the boiler sizes are smaller than  4 MW (15  MMBtu/hr) and most
of these boilers are smaller than 3 MW  (10 MMBtu/hr).
                                     3-4

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      Table 3-1 presents a range of data on the boiler configurations of four
typical elementary and four secondary schools located in urban mid-Atlantic
cities.  The boilers range from 125 hp to 150 hp and are used primarily for
space heating during the winter.  As shown in Table 3-1, the boilers provide
heat for buildings ranging in size from about 47,000 to 200,000 square feet.
The fuel used to fire the boilers constitutes a relatively small percentage of
the total school budget -- 0.4-1.7 percent.
Hospitals
      Generally, boilers used in hospitals provide steam for the preheat coils
in air handling units, and for heat exchangers which provide hot water for
perimeter heating (fan coils and convectors), zone control heating, domestic
hot water, humidification and sterilization. Boiler configuration data for 73
boilers in hospitals in Illinois (provided by the Illinois Environmental
Protection Agency), 76 boilers in hospitals in Minnesota (provided by the
Minnesota Pollution Control Agency) and 92 boilers in hospitals in Boston
(provided by the Commonwealth of Massachusetts, Department of Environmental
Quality Engineering, Division of Air Quality Control) indicate that most of
the boilers are smaller than 9 MW (30 MMBtu/hr).
      Table 3-2 provides statistics on the boiler configurations of .three
hospitals ranging in size from 365,000 square feet to 760,000 square feet.
All of these hospitals are equipped with multiple boilers.  Typically, one
boiler is used only as a back-up.  The others are used for various lengths of
time throughout the year depending on need.  As shown in Table 3-2, the
boilers are sized between 5 and 14.2 MW (17 MMBtu/hr and 48.5 MMBtu/hr).
Depending on the extent to which the boilers are operated, annual  fuel
consumption ranges from 44.3 TJ (42,000 MMBtu) to 180.4 TJ (171,000 MMBtu).
Although hospitals are more energy-intensive, the annual cost of fueling a
boiler is a relatively insignificant portion of the total annual costs of
operating a hospital: 0.3 -1.4 percent.  The relatively low share of fuel
costs in hospital budgets is due to the high costs of highly-trained doctors
and auxiliary personnel plus increasingly expensive medical equipment.
                                      3-5

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                 TABLE 3-1.   ELEMENTARY AND SECONDARY SCHOOLS
                             Junior High
                               School'
                               Elementary
                                 School8
Boiler
Configuration


Building Size


Annual Fossil Fuel
Use (MMBtu)

Boiler Fuel Costs
(x 1000)

Enrollment
(No. of pupils)

Annual Building
Operating Costsb
(xl,000)

Boiler Fuel as
% of Total Costs
3 steam boilers
125 hp each
(5 MMBtu/hr each)

125,000 -
185,000 sq. ft.

5,606 - 7,984
$22.9 - 32.6
455 - 1,450
$1,727 - 5,504
0.4 - 1.7
2 steam boilers
150 hp each
(6 MMBtu/hr each)

47,000 -
104,000 sq. ft.

3,177 - 5,872
$13.0 - 35.9
460-670
$1,746 - 2,543   .
0.5 - 1.7
a  Range for four schools.

b  $3,796/pupil times the total  number of pupils.
                                     3-6

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                             TABLE 3-2.   HOSPITALS

Hospital
A
Hospital
B
Hospital
C
Boiler
Configuration
81:  29.1 MMBtu/hr
B2:  29.1 MMBtu/hr
Bl: 16.7 MMBtu/hr
B2: 25.1 MMBtu/hr
B3: 25.1 MMBtu/hr
Bl: 48.5 MMBtu/hr
82: 48.5 MMBtu/hr
B3: 29.1 MMBtu/hr
Building Size   460,000 sq. ft      < 365,000 sq. ft
Annual Fossil   42,048
Fuel Use
(MMBtu)
                     170,820
                     760,000 sq. ft


                     121,300
Boiler Fuel     $204
Costs (x 1000)
                     $827
                     $642
Annual
Building
Operating
Costs (xl,000)
$76,303
$59,818
$136,696
Boiler Fuel
as % of
Total Costs
  0.3
  1.4
  0.5
                                      3-7

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Laundries
      Commercial laundries require substantial  quantities of steam for
washing, drying and finishing operations.   Wash water heating is probably the
major source of boiler load in a commercial  laundry.   Boiler configuration
data for 15 boilers in laundries in Illinois,  4 boilers in laundries in
Minnesota and 18 boilers in laundries  in Boston show  that all of the boiler
sizes are smaller than 15 MW (50 MMBtu/hr)  and most are smaller than 6 MW (20
MMBtu/hr).  Commercial laundry boilers are  characterized by relatively high
capacity utilization rates: about 55 percent.
      The boilers in Table 3-3 range in size from 2.9 - 7.3 MW (10.0 to 25.1
MMBtu/hr).  Many laundry establishments are equipped  with at least one back-up
boiler although, as noted in the table, some are only single-boiler opera-
tions.
      Since boilers are used relatively intensively in laundry operations, one
would expect that the cost of fueling  a boiler might  be a significant fraction
of total establishment sales.  Given the estimates of total annual boiler fuel
expenditures obtained from three laundry plants (shown in Table 3-3), this
appears not to be the case.  Using these data,  boiler fuel  costs range from
1.8 to 2.7 percent of total plant revenues.   However,  the total boiler fuel
expenditures reported by the laundry plants listed in Table 3-3 imply fuel
prices which were only 50 percent of the national  average price for natural
gas in 1986.  Using the latter price,  as more representative of most laun-
dries, and the estimates of annual boiler fuel  use in Table 3-3, boiler fuel
costs range from 4.2 percent to 8.3 percent of total  plant revenues.
Hotels
      Boiler applications in hotels vary broadly.  In some hotels boilers are
used to provide steam for general space and hot water heating in guest rooms
as well as driving turbines for summer cooling, running water pumps, laundry,
heated swimming pool and restaurant facilities on  the premises.  In other
hotels, boilers are used only for very specific applications and are therefore
very small.  For example, a medium-sized hotel  in  Washington, O.C. relies on a
80 kW (0.3 MMBtu/hr) boiler to provide steam for an on-site laundry facility
that is operated 14 hours/day and 6 days per week.  Boiler configuration data
                                     3-8

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                             TABLE 3-3.   LAUNDRIES


Plant
1
Laundry A
Plant
2

Laundry
B
Boiler
Configuration
81:  23.4 MMBtu/hr
B2:  16.7 MMBtu/hr
81: 10.0 MMBtu/hr
82: 10.0 MMBtu/hr
81: 25.1 MMBtu/hr
Building Size   75,000 sq. ft
                     65,000 sq.  ft
                        N.A.
Annual Fossil   109,500
Fuel Use
(MMBtu)
                     47,400
                     125,750
Annual Plant    $11,100
Sales (xl,000)
                     $5,600
                     $7,500
Boiler Fuel
as % of
Total Sales
2.7 - 4.9
2.7 - 4.2
1.8 - 8.3
                                      3-9

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for 21 boilers 1n hotels in Boston indicate that all  boilers are smaller than
7 MW (25 MMBtu/hr).
      Boiler configuration data for a large and a small  hotel are presented  in
Table 3-4.  Both hotels rely on boilers primarily to  supply space and hot
water heating for guest rooms,  laundry and kitchen facilities particularly
during the winter.  As shown in the table, the annual  boiler fuel consumption
varies widely between the two hotels -- a reflection  of different building and
boiler sizes and different degrees of boiler usage.   Despite the difference  in
the absolute values for boiler fuel consumption and hotel  revenues, boiler
fuel costs are roughly the same percentage of total sales  (1.6-2.0 percent)
for both the 1arge and the smal1  hotel.
Colleges and Universities,
      Boiler configuration data for 72  boilers in colleges/universities in
Illinois, 90 boilers in colleges/universities in Minnesota and 86 boilers in
eolleges/universities in Boston show that boiler sizes range from very small
(<1 MW, <5 MMBtu/hr) to large (>29 MW,  >100 MMBtu/hr).
      Boiler configuration data for a large university and a small  college are
presented in Table 3-5.  In both  cases, boilers are used to provide steam for
hot water and space heating for a number of buildings  at various times
throughout the year.  Generally,  the boilers are operated  one at a  time except
during peak periods (i,e., winter)  when additional capacity is needed.
      With respect to the large university shown in Table  3-5, two  of the
boilers are sized above the 29  MW (100  MMBtu/hr)  level  (currently defined as
the cut-off for "small" boilers).   The  other two boilers are only slightly
below the cut-off point.  For this  reason,  this example  has not been included
in the cost impact analysis presented below.   However,  it  is interesting to
note that the proportion of total  operating costs  contributed by annual  boiler
fuel expenditures is very low (1.4  percent)  and essentially similar to that of
the small college listed in Table 3-5.
3.2.3  Worst Case Economic Impacts
      Boiler fuel expenditures  as a percentage of  total  revenues per
establishment provide an indication of  the overall importance of steam in
relation to total sales (or budgets)  for selected  commercial/institutional
                                    3-10

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                             TABLE 3-4.  HOTELS
                           Large
                           Hotel
                                 Small
                                 Hotel
Boiler
Configuration
Bl: 8.35  MMBtu/hr
82: 11.70 MMBtu/hr
5 steam boilers
0.7 MMBtu/hr each
Building Size
685 rooms
227 rooms
Annual Fossil
Fuel Use (MMBtu)
72,010
8,486
Boiler Fuel
Costs (x 1000)
$294
$53
Annual Building
Revenues (xl,000)
$14,883
$3*430
Boiler Fuel as %
of Total Revenues
2.0
1.6
                                     3-11

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                    TABLE 3-5.  COLLEGES AND UNIVERSITIES
                             Large
                           University
                                  Small
                                 College
Boiler
Configuration
Bl: 145 MMBtu/hr
B2: 121 MMBtu/hr
B3:  97 MMBtu/hr
B4:  85 MMBtu/hr
Bl: 24 MMBtu/hr
82: 29 MMBtu/hr
83: 10 MMBtu/hr
Annual Fossil
Fuel Use (MMBtu)
922,000
107,383
Boiler Fuel
Costs (x 1000)
$4,000
$444
Annual Building
Operating Costs
(xl,000)
$293,291
$29,585
Boiler Fuel as %
of Total Costs
   1.4
   1.5
                                     3-12

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sectors.  To evaluate the economic impacts of a NSPS,  It also  is essential to
examine the ability of a firm to pay for the costs of  pollution control.  In
this respect, a useful measure is the annualized cost  of pollution control as
a percentage of total annual revenues per establishment.
      The objective is to use relatively high (not necessarily the most
likely) compliance costs estimates in order to delimit the magnitude of
possible adverse economic impacts.  The "worst case" cost impact is calculated
by assuming full pass-through of compliance costs.  Most commercial/insti-
tutional buildings do not use boilers (see Tables A-l  and A-2) and, therefore,
will not be subject to any economic impacts due to a NSPS.
      A "worst case" cost estimate for coal combustion would be patterned
after the promulgated PM and NOX NSPS for large (>29 MW,  >100 MMBtu/hr)
industrial-commercial-institutional boilers (51 FR 42768) and the promulgated
S02 NSPS for large industrial-commercial-institutidnal  boilers (52 FR 47827).
It would include a sodium scrubber (other feasible and demonstrated, but more
expensive alternatives are dual alkali and lime spray drying FGO systems), a
S02 monitor at the FGO inlet, a S02 monitor at the  FGO  outlet,  a  PM emissions
control device (an electrostatic precipitator or a fabric filter—because the
wet FGD system may not, in and of itself, remove enough of the PM emissions),
an  opacity monitor, a low excess air system to control NOX  emissions,  a NOX
                             •
monitor, and an 02/C02  outlet diluent monitor.  However, relatively few coal-
fired boilers smaller than 29 MW (100 MMBtu/hr) have been used in the commer-
cial/institutional sector.  Even fewer coal-fired boilers may be ordered in
the next five years because of the drop in oil  prices since early 1986.
      Most of the boilers in the commercial/institutional  sector fire natural
gas (see Table A-l).  Natural gas is not subject to the proposed S02  and PM
emissions standards.  Therefore, adverse economic impacts are not expected for
new small package boilers firing natural gas.
      Given that coal is not a representative new small boiler fuel  type in
the commercial-institutional sector and that adverse economic impacts are not
expected from new small boilers firing natural  gas, this analysis has focused
on distillate and residual fuel oil combustion compliance options.
                                     3-13

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      An expensive control  compliance option  would  be to require a scrubber
for fuel oil combustion 1n  new small  boilers.  EPA  has determined that sodium
scrubbing systems, a conventional  wet flue gas  desulfurlzatlon (FGO) system,
have been widely applied to small  oil-fired steam-generating units and are
considered demonstrated for purposes  of developing  NSPS.1
      EPA has prepared estimates of the annual 1zed  capital  and operating costs
for various sizes of scrubbers.2  In  applying these costs,  some assumptions
concerning boiler operation in multiple boiler  establishments are necessary.
Specifically, in sizing the scrubbers it is assumed that multiple boiler
establishments:  1) operate boilers one at a  time;  2) use the largest boiler
most of the time; and 3) employ the other boilers as  back-up units.  These
assumptions reflect the standard boiler operating procedures stated by most of
the respondents who provided data for this analysis.   The assumption of single
boiler operation in multiple boiler establishments  also is  verified by the
relatively low boiler capacity utilization rates characteristic of most of the
selected sectors.
      Table 3-6 incorporates the selected sector data from  Section 3.2.2 with
information on the annual 1 zed capital  and operating costs for various sizes of
scrubbers.  Boiler fuel expenditures  account  for from 0.5 percent to as much
as 8 percent of the. total annual revenues of  a  commercial/institutional
establishment.  The incremental  costs of pollution  control  are under 5 percent
of total annual revenues for each  of  the selected sectors.   The results
suggest that this very stringent control  requirement  could  lead to potential
increases of 2-4 percent 1n the prices of (or budgets for)  some laundries,
hotels and schools.
      The impacts of this very stringent control scenario did not include the
costs of monitoring and testing, which can be a significant expense.3  Table
3-7 summarizes EPA estimates for these parameters.  The cost estimates in
Table 3-7 do not necessarily reflect  the average expenses associated with the
proposed standards.  Table  3-8 shows  the impacts of including monitoring and
testing costs.  The result  indicates  potential  price  increases (or budget
increases for schools) of from 3 to 8 percent for some laundries,  hotels and
schools.
                                     3-14

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              TABLE 3-6.  SELECTED SECTORS ECONOMIC IMPACTS: FGO
                    (Without Monitoring and Testing Costs)

Annual
Revenues
Sector (x 1,000 $)
Laundry A:
Plant 1
Plant 2
Laundry B
Hospital A
Hospital B
Hospital C
Large Hotel
Small Hotel
Small College
Jr. High 1
El em. School 1

11,100
5,600
7,500
76,303
59,818
136,696
14,883
3,430
29,585
,727-5,504
,746-2,543
Scrubber
Size
(MMBtu/hr)

23.4
10.0
25.2
29.1
50d
100d
20d
5*
53d
5
6
Annual i zed
Scrubber
Cost'
(x 1,000 $)

120.4
93.1
120.4
140
200
285
120.4
70
200
70
70
Boiler
Fuel
Cost
Percent5

2.7-4.9
2.7-4.2
1.8-8.3
0.3
1.4
0.5
2.0
1.6
1.5
0.4-1.7
0.5-1.7
Pollution
Control
Percent6

1.1
1.7
1.6
0.2
0.3
0.2
0.8
2.0
0.7
1.3-4.1
2.8-4.0
8  Rough extrapolation of estimates'in Reference 1 converted to 1985 dollars;
   assumes low annual capacity utilization rate and a 0.13147 capital recovery
   factor (10 percent interest and 15 years); excludes monitoring and testing.

b  Boiler fuel costs divided by annual revenues (see Tables 3-1 through 3-5).

c  Annualized scrubber cost divided by annual revenues.

d
   Two largest boilers

   Sum of all five boilers
                                     3-15

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                      TABLE 3-7.   MONITORING AND TESTING
                                COST ESTIMATES"
                                    (000$)
                             Capital           Annual  O&N          Annualizedb
Opacity monitor                 59                 8                  16
            monitor             55                46                  53
PM/S02 test
Total                          122                54                  70
8  Reference 3.

6  Annual O&M plus (0.13147 times capital  cost);  this capital recovery factor
   is based on a 10 percent interest rate  and 15  years.
                                     3-16

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              TABLE 3-8.  SELECTED SECTORS ECONOMIC IMPACTS: F60
                      (With  Monitoring and Testing Costs)
Sector
Laundry A:
Plant 1
Plant 2
Laundry B
Hospital A
Hospital B
Hospital C
Large Hotel
Small Hotel
Small College
Jr. High.
El em. School
Annual
Revenues
(x 1,000 $)

11,100
5,600
7,500
76,303
59,818
136,696
14,883
3,430
29,585
1,727-5,504
1,746-2,543
Scrubber
Size
(MMBtu/hr)

< 23.4
10.0
25.2
29.1
50d
100d
20d
5«
53d
5
6
Annual 1 zed
Scrubber and
Monitoring
Cost'
(x 1,000 $)

190.4
163.1
190.4
210
270
355
190.4
140
270
140
140
Boiler
Fuel
Cost
Percent6

2.7-4.9
2.7-4.2
1.8-8.3
0.3
1.4
. 0.5
2.1
1.6
1.5
0.4-1.7
0.5-1.8
Pollu-
tion
Control
Percent6

1.7
2.9
2.5
0.3
0.5
0.3
1.3
4.1
0.9
2.5-8.1
5.5-8.0
a  Includes annualized scrubber costs from Table 3-6 and annualized monitoring
   and testing costs from Table 3-7.

b  Boiler fuel costs divided by annual revenues (see Tables 3-1 through
   3-5).

e  Annualized scrubber and monitoring and testing costs divided by annual
   revenues.

d  Two largest boilers

8  Sum of all five boilers
                                     3-17

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      The significant Impacts due to this stringent control scenario requiring
scrubbers and monitoring requirements occur due to the very high capital costs
assumed for scrubbers on these smaller sized boilers,  and expensive monitoring
requirements which significantly Increase the costs of using boilers.  The
most severe impact would be experienced 1n places  like schools which utilize
very small boilers only for space heating purposes.
      A less expensive but still stringent S02  emissions  control  standard
would be a very low sulfur fuel  regulation.  This  regulation may require fuel
sampling and/or initial PM/S02 tests.   This 1s  assumed  to cost $1,000 per
year.  The fuel price Increase is estimated to be  no larger than S0.73/GJ or
$0.77/MMBtu (1985 dollars).  This estimate 1s based on the projected dif-
ference in commercial residual fuel  oil prices between high (3.0 percent)
sulfur and very low (0.3 percent) sulfur.4'5  Table 3-9 summarizes the poten-
tial price impacts of a very low sulfur fuel requirement  (0.3 percent sulfur)
on boilers firing residual fuel  oil.  In this regulatory  scenario (with
monitoring and testing costs), some  laundries could experience price (or
budget) increases of about 1 percent.
3.3   GENERIC BUILDINGS
3.3.1 Scone
      The generic buildings analysis addresses  the potential  impact of a
revised NSPS in buildings where  the  primary use of the  boiler is space
heating.  Representational boiler configurations for five different building
size ranges were developed from  a small sample  of  actual  configurations in
different cities.  In order to capture the effects of regional (climatic)
differences, the data collection and analysis were performed separately for an
area in the northern and an area in  the southern United States.
      Generic buildings use boilers  primarily for  space heating,  although a
small portion of boiler energy use may be for.water heating.   The list of
generic buildings excludes buildings with a significant additional  process
requirement for steam.  Offices, assembly halls, religious institutions and
                                     3-18

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                TABLE 3-9.  SELECTED SECTORS  ECONOMIC  IMPACTS:
                          VERY LOW SULFUR  REGULATION
                      (With Monitoring and Testing Costs)

Sector
Laundry A:
Plant 1
Plant 2
Laundry B
Hospital A
Hospital B
Hospital C
Large Hotel
Small Hotel
Small College
Jr. High
El em. School
Annual
Revenues
(x 1,000 $)

11,100
5,600
7,500
76,303
59,818
136,696
14,883
3,430
29,585
1,727-5,504
1,746-2,543
Annual Fossil
Fuel Consumption
(MMBtu/yr)

109,500
47,400
125,750
42,048
170,820
121,300
72,010
8,486
107,383
5,606-7,984
3,177-5,872
Annual
Pollution
Control Cost"
(x 1,000 $)

85
37
98
33
133
94
56
8
84
5-7
3-6
Pollution
Control
Percent"

0.8
0.7
1.3
0.1
0.2
0.1
0.4
0.2
0.3
0.1-0.4
0.1-0.3
"  (Annual fossil fuel consumption times $0.77/MMBtu) plus $1,000.

b  Annual pollution control costs divided by annual revenues.
                                     3-19

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retail space use boilers primarily for space heating and are Included In this
analysis.*
      Data from two regional  areas are studied separately in order to under-
stand how boiler configurations vary with climatic  area.  Boston, Massa-
chusetts was selected as the  northern study area.   Boiler use in a southern
area is represented in this study by data from Washington, D.C.  The generic
buildings economic Impact analysis provides estimates of potential cost
impacts of specific alternative air emissions standards for new commercial/
institutional boilers in five building size classes and two regions.  The cost
impacts are measured by comparing the annualized  pollution control costs of
regulatory scenarios to estimates of the annual building operating budget.
The annual building operating budget is estimated to be the building size (in
square feet) times the rental  rate (dollars per square foot).  This analysis
assumes full cost pass-through of the total  annualized pollution control
costs.
      This approach measures  the potential  increase in building rental rates
to tenants as a consequence of worst case NSPS control scenarios.  The
economic impact on the tenant would obviously depend on the nature of the
business activity of each tenant.  Tenants  whose business implies a very high
ratio of sales per square foot of floor space rented (grocery store, Wall
Street brokers) would tend to see very little impact on profit margins since
building control costs would  be such a small  percentage of sales.  Other
tenants with a relatively low ratio of sales  per square foot of space would
tend to experience relatively greater impacts on their cost structure.
Essentially, the objective in focusing on the Impact of the NSPS on building
rental rates is intended to provide an indicator which any building tenant can
relate to in assessing whether they might be  significantly affected by a NSPS.
3.3.2 Approach
      A different data collection strategy  is necessary for each city because
data availability in Boston is different from data  availability in Washington,
O.C.  The Boston data on boiler use were provided by the Division of Air
Quality Control, Department of Environmental  Quality Engineering of the
    Schools were included in the  selected  sectors analysis  in  Section 3.2.
                                     3-20

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Commonwealth of Massachusetts.  This office tracks the generation of air
pollution by source, frequency of use, and fuel type.  Information  is avail-
able on the number, size, frequency of use, address and purpose of  establish-
ment for boilers within the Boston city limits.  Building size data were not
available from this data source.  In addition, data were acquired on commer-
cial building vacancies, rental rates and building sizes from three real
estate agencies.6-7'8  These rental  data were  matched  with  the boiler informa-
tion to develop a data set on boiler use in generic buildings in Boston.
      In Washington, D.C. data were collected from the O.C. Boiler  Inspector's
Office.  From these records of boiler registration and safety inspection, data
on address, number of boilers and boiler size were gathered.  From  the D.C.
Tax Assessor's Office information was collected on building address, type of
occupant, and building size.  These two data sources were matched by building
address to create a data set on boiler use in generic buildings in  Washington,
D.C.
Boston Data
      Collection and compilation of data on boiler use in Boston, Massa-
chusetts resulted in the set of 21 data points shown in Table 3-10.  These are
all office buildings.  From these data we see that boiler size ranges from 1-4
MW (3 to 13 MMBtu/hr) in generic buildings and that there is only one building
with a boiler larger than 3 MW (10 MMBtu/hr).  Small  buildings tend to have
fewer boilers than larger buildirns.  In most Boston buildings with multiple
boilers, the average annual capacity utilization rate is low.  This suggests
that the additional boilers serve as backup and not as primary boilers.
      Based on these data, the typical configurations shown in. Table 3-11 were
developed.  In these configurations, all additional boilers in a building are
considered to be the same size as the first.   The number and size of these
boilers were calculated from the average number and size in each building size
range.
Washington. D.C. Data
      Collection and compilation of data on boiler use in  Washington,  O.C.
resulted in the set of 12 data points shown .in Table 3-12.   These are mostly
office and apartment buildings; there are a few churches and small  retail

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TABLE 3-10.  GENERIC BUILDINGS BOILER CONFIGURATION DATA
                FOR  BOSTON, MASSACHUSETTS

Building
Size
(1000 sq.ft.)
22
30
32
50
60
64
66
72
72
82
90
100
110
110
120
150
196
200
280
333
580
Boiler 1
(MMBtu/hr)
3
3
3
6
6
4
6
8
6
4
9
4
5
3
6
4
13
9
10
7
7
Boiler 2 Boiler 3 Boiler 4
(MMBtu/hr) (MMBtu/hr) (MMBtu/hr)



10 10
4 4

6


4

4
5

6
4 4 4
12
9
7
7
7
                          3-22

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      TABLE 3-11.  GENERIC BUILDINGS TYPICAL BOILER CONFIGURATIONS
                        FOR BOSTON,  MASSACHUSETTS3

Building Size
Range
(1000 sq.ft.)
1-25
26-50
51-100
101-200
201+
Total Number
of Boilers
1
1
2
2
2
Boiler Size
of Each
(MMBtu/hr)
3
5
5
6
7
Derived from Table 3-10,
                                  3-23

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TABLE 3-12.  GENERIC BUILDINGS BOILER CONFIGURATION DATA
                  FOR WASHINGTON, D.C.

Building
Size
(1000 sq.ft.)
22
34
81
129
139
186
202
245
285
287
345
875
Boiler 1
(MMBtu/hr)
1
3
2
3
5
5
6"
6
6
7
12
13
Boiler 2 Boiler 3 Boiler 4
(MMBtu/hr) (MMBtu/hr) (MMBtu/hr)


2
3

4
6
6
6 6
4
8 8
13
                          3-24

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stores.  Specific average capacity utilization rates  for each building  are
unavailable.  These data show that boiler size ranges  from 0.3 to 4 MW  (1 to
13 MMBtu/hr).  Only two buildings have boilers larger  than 3 MW  (10 MMBtu/hr)
and these buildings are both over 300,000 square feet.  As with  the Boston
data, small buildings tend to have smaller and fewer  boilers than large
buildings.
      Table 3-13 shows the typical boiler configurations drawn from the
Washington data.  It was assumed that all boilers in  any given building are
the same size.  The original data are subdivided into  the defined building
size ranges.  Typical configurations are drawn from simple averages of  the
number and size of boilers in each building size range.
Boston and Washington Configurations Compared
      Boston and Washington show similar boiler use patterns.  Both Boston and
Washington have an identical number of boilers in each building  size range.
The Washington buildings, in general, tend to have slightly smaller boilers
than.the Boston buildings (see Table 3-14).  This assumption is  consistent
with Washington's relatively wanner climate.
      Table 3-15 presents estimates of annual fossil fuel consumption in
boilers in generic buildings.  Actually, there is considerable variability in
energy consumption per square foot in commercial  buildings due to building
design characteristics, HVAC equipment differences and energy conservation
measures.  In general, there are economies of scale - energy consumption per
square foot decreases as building size increases.
      Table 3-16 summarizes other comparable estimates of annual  fossil fuel
consumption in commercial buildings which include a boiler.9  The average
values in Table 3-16 show that the estimates in Table 3-15 for small buildings
are reasonable.
Office Building Rental Rates
      Office building annual rental rates vary over a wide range, from  $10-
60/square foot.  Typical rental rates may be $15-30/square foot.6'7'8  For  this
analysis, the selection of a relatively high rental  rate will bias the
economic analysis toward minimizing the cost impacts of pollution control
costs.  Therefore, a relatively low rental rate,  $15/square foot, has been
                                     3-25

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         TABLE 3-13.  GENERIC BUILDINGS TYPICAL  BOILER CONFIGURATIONS
                             FOR WASHINGTON,  D.C.a

Building Size
Range
(1000 sq.ft.)
1-25
26-50
51-100
101-200
201+
Total Number
of Boilers
1
1
2
2
2
Boiler Size
of Each
(MMBtu/hr)
1
3
2
4
8
a  Derived from Table 3-12.
                                     3-26

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             TABLE 3-14.  GENERIC BUILDINGS BOILER CONFIGURATIONS8



Building
Size Range
(1000 sq.ft.)
<25
25-50
51-100
101-200
>200
Washington.

Number
of
Boilers
1
1
2
2
2
D.C.
Boiler
Size
of Each
(MMBtu/hr)
1
3
2
4
8
.Boston,

Number
of
Boilers
1
1
2
2
2
Massachusetts
Boiler
Size
of Each
(MMBtu/hr)
3
5
5
6
7
8  See Tables 3-11 and 3-13.
                                     3-27

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               TABLE 3-15.  ESTIMATES OF GENERIC BUILDINGS
                ANNUAL FOSSIL FUEL CONSUMPTION IN BOILERS
 Building
Size Range             Washington.  D.C.              Boston. Massachusetts
(1,000 sq. ft.)
<25
25-50
51-100 {
101-200
>200
GJ/yr
1,16.0
2,560
2,954
3,480
6,330
(MMBtu/yr)
(1,100)
(2,300)
(2,800)
(3,300)
(6,000)
GJ/yr
1,320
3,340
4,220
5,275
8,440
(MMBtu/yr)
• (1,250)
(3,000)
(4,000)
(5,000)
(8,000)
                                   3-28

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        TABLE 3-16.   ENERGY CONSUMPTION IN COMMERCIAL BUILDINGS IN 1983
Fuel Type
Northeast
North Central
Natural Gas"
    No. of Buildings"
    Avg. Building Size (sq. ft.)b
    Avg. Annual Gas Consumption
         per Building (MMBtu)c
  113,000
   15,700
    1,168
   212,000
    22,500
     2,055
Fuel Oild
No. of Buildings*
Avg. Building Size (sq. ft.)*
Avg. Annual Fuel Oil Consumption
per Building (MMBtu)9

101,000
23,800

1,389

Qf
Q •

Q
a  Reference 9; p. 106, 109.
b  Buildings which use natural gas to fire boilers.
c  Includes natural gas consumption .in boilers and other equipment.
d  Reference 9, p. 119, 122.
8  Buildings which use fuel oil only to fire boilers.
f  Data withheld because the relative standard error was greater than 50% or
   fewer than 20 buildings were sampled.
9  Includes'fuel oil consumption in boilers and other equipment.
                                     3-29

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chosen in order that the cost impacts will  not be understated for most office
building tenants.  The annual building rental  cost estimates are summarized  in
Table 3-17.
3.3.3 Results of the Regulatory Analysis
Scone
      The generic buildings economic impact analysis provides estimates of
potential cost impacts of specific alternative air emissions standards for new
commercial/institutional boilers in the five building size classes and two
regions.  The cost impacts are measured by  comparing the annualized pollution
control costs to estimates of the annual building rental costs.
      The baseline is assumed to be high (3.0  percent)  sulfur residual fuel
oil.  This is not an appropriate baseline assumption for many municipal areas.
For example, New York City, Philadelphia and Boston require very >ow sulfur
fuel oil.  Therefore, this analysis overstates the potential cost impacts for
buildings in these communities.   This economic analysis also tends to be a
"worst case" analysis of specific alternative  air emissions standards.  It is
using a relatively low building rental  rate which overstates the economic
impacts of increased pollution control  costs for  many tenants.   In addition,
there is no significant cost impact for most generic buildings  because most
these buildings do not use boilers and  many of the rest use natural  gas (which
is not subject to the cost impacts presented in this section).*   Furthermore,
this analysis assumes that there will  be no boiler size cutoff;  the  altern-
ative air emissions standards are assumed to be applicable to new boilers as
small as 0.3 MW (1 MMBtu/hr).  Finally,  this analysis includes  monitoring and
testing costs which may not necessarily be  part of the  alternative air
emission standard.
Cost Estimates
      Two regulatory scenarios have been evaluated:
   •  a very low sulfur fuel standard,  129  ng  StyJ  (0.3 Ib  SOj/MMBtu),
      with a $1,000 per year per boiler monitoring and  testing  cost
      assumption
   See Appendix A.
                                    3-30

-------
           TABLE 3-17.  GENERIC BUILDINGS ANNUAL RENTAL COSTS
Building
Size Range
(1000 sq.ft.)
Representative
Building Size
(1000 sq.ft.)
Annual
Rental
Costs3
   <25                          12                      $  180,000

 25-50                          37                         555,000

 51-100                         75                       1,125,000

101-200                        150                       2,250,000

  >200                         380b                      5,700,000



Representative building size times $15/sq.ft.

In 1983, there were 7,000 office buildings which were larger than 200,000
square feet with a total area of 2,671 million square feet.; or an average
of 2,671,000,000/7,000 or 380,000 square feet.  Nonresidential Buildings
Energy Consumption Survey:  Characteristics of Commercial Buildings 1983.
U.S. Department of Energy, Energy Information Administration.   DOE/EIA-
0246(83).  July 1986.  p.55,57.
                                  3-31

-------
   t  a flue gas desulfurization (FGO) or scrubber requirement with a
      $70,000 per year per boiler (see Table 3-7)  monitoring and testing
      cost assumption
      Table 3-18 shows the estimates of the total  annualized pollution control
costs for the very low sulfur fuel  requirement.  The sulfur premium is
estimated to be 50.73/GJ or $0.77/MMBtu (1985 dollars) for 3.0 to 0.3 percent
sulfur.5'6

      Table 3-19 presents estimates of the total annualized pollution control
costs for scrubbers.  The monitoring and testing cost estimates are larger
than the estimates used in Table 3-18.  These total  annualized pollution
control cost estimates are summarized in Table 3-20.

Impacts on Building Rental Rates
      The impacts of total annualized pollution control  costs on building
rental rates are summarized in Table 3-21.  The range is large, 1-67 percent.
Table 3-21 suggests significant economies of scale -  the cost impacts are
small for large buildings.
      The cost impacts in Table 3-21 are relatively  large for buildings
smaller than 50,000 square feet for the scrubber scenario.   It is important to
note that the overwhelming s'hare (88 percent)* of  commercial  buildings  which
have boiler installations were less than 50,000 square feet in size.
      Table 3-22 presents estimates of the projected  impacts of annualized
pollution control costs (without monitoring and testing  costs)  on building
rental rates.  The impacts are negligible for the  very low  sulfur fuel
standard.
    See  Table  A-l  in Appendix A.
                                    3-32

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                 TABLE 3-18.   DERIVATION OF ESTIMATES OF TOTAL
                ANNUALIZED POLLUTION CONTROL COSTS PER BUILDING
                     FOR THE  VERY LOW SULFUR FUEL STANDARD3
                                     (000$)

Washlnoton. D.C.
Building
Size Range
(000 sq. ft.)
<25
25-50
51-100
101-200
>200
Monitoring
and
Testing
1
1
1
1
1

Fuel Cost
Increase"
0.8
1.8
2.2
2.5
4.6

Total0
1.8
2.8
3.2
3.5
5.6
Boston.

Fuel Cost
Increase6
1.0
2.3
3.0
3.9
6.2
MA

Total0
2.0
3.3
4.0
4.9
7.2
a  129 ng SOj/J (0.3 Ib SOa/MMBtu).

b  Annual fuel consumption from Table 3-14 times S0.73/GJ or $0.77/MMBtu
   ($1985).

c  Monitoring and testing costs plus fuel cost increase.
                                     3-33

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           TABLE 3-19.  DERIVATION OF ESTIMATES OF TOTAL ANNUALIZEO
                     POLLUTION CONTROL COSTS PER BUILDING
                         FOR THE SCRUBBER REQUIREMENT'
                                    (000$)

Wash i not on, D.C.
Building
Size Range
(000 sq. ft.)
<25
25-50
51-100
101-200
>200
Monitoring
and
Testing"
70
70
70
70
70
Scrubber
Cost6
40
50
50
70
80
Total*
110
120
120
140
150
Boston,
Scrubber
Costc
50
70
70
70
75
MA
Totald
120
140
140
140
145
a  Scrubber is required.

b  See Table 3-7.

c  Estimates extrapolated from Reference 1 converted to 1985 dollars; assumes
   low capacity utilization rate and a 0.13147 capital  recovery factor  (10
   percent interest and 15 years).

d  Monitoring and testing plus scrubber costs.
                                     3-34

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           TABLE 3-20.  COMPARISON OF ESTIMATES OF TOTAL ANNUALIZED
                     POLLUTION CONTROL COSTS PER BUILDING3
                                    (000$)

Building
Size Range
(1000 sq. ft.)
<25
25-50
51-100
101-200
>200
Washinaton. D.C.
Very Low
Sulfur
1.8
2.8
3.2
3.5
5.6
Scrubber
110.0
120.0
120.0
140.0
150.0
Boston. Massachusetts
Very Low
Sulfur Scrubber
2.0
3.3
4.0
4.9
7.2
120.0
140.0
140.0
140.0
145.0
3  See Tables 3-18 and 3-19.  Includes monitoring and testing costs.
                                     3-35

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       TABLE 3-21.  IMPACTS OF TOTAL ANNUALIZED POLLUTION CONTROL COSTS
             ON RENTAL RATES  (WITH MONITORING AND TESTING  COSTS)3
                             (percent Increases)"

Building
Size Range
(1000 sq. ft.)
<25
25-50
51-100
101-200
>200
Washington. D.C.
Very Low
Sulfur
1
c
C
C
C
Scrubber
61
22
11
6
3
Boston. Massachusetts
Very Low
Sulfur Scrubber
1
1
c
c
c
67
25
12
6
3
3  Total annualized pollution control  cost estimates from Table 3-20 divided
   by annual building rental costs in .Table 3-17.

b  Total annualized pollution control  costs as a percent of annual building
   rental costs.

c  Less than 0.5 percent.
                                     3-36

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       TABLE 3-22.  IMPACTS OF TOTAL ANNUALIZED POLLUTION CONTROL COSTS
            ON RENTAL RATES (WITHOUT MONITORING AND TESTING COSTS)3
                              (percent increases)5

Building
Size Range
(1000 sq. ft.)
<25
25-50 <
51-100
101-200
>200
Washinaton. O.C.
Very Low
Sulfur
c
c
c
c
c
Scrubber
22
9
4
3
1
Boston, Massachusetts
Very Low
Sulfur Scrubber
c
c
c
c
c
28
13
6
3
1
•
a  Annualized pollution control cost estimates (excluding monitoring and
   testing) from Table 3-20 divided by annual building rental costs in Table
   3-17.

b  Annualized pollution control costs as a percent of annual building rental
   costs.

0  Less than 0.5 percent.
                                     3-37

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                                  REFERENCES
1.    51 FR 22402, 22412.

      Summary of Regulatory Analysis for New Source Performance Standards:
      Industrial-Commercial-Institutional  Steam Generating Units of Greater
      than 100 Million Btu/hr Heat Input.   Radian Corporation, Research
      Triangle Park, North Carolina.  EPA-450/3-86-005.  Prepared for the U.S.
      Environmental Protection Agency,  Office of Air Quality Planning and
      Standards.  June 1986.  p.  5-50,  5-51, 5-55,  5-56 and 5-57.

2.    Model Boiler Cost .Analysis  for Controlling  Sulfur Dioxide (S02)
      Emissions from Small  Steam  Generating  Units.   U.S.  Environmental
      Protection Agency,  Research Triangle Park,  N.C.
      CEPA Publication No. EPA-450/3-89-14.   May 1989.


3.    Memorandum and attachments  from Copland, R.  (EPA/SOB) to Link, T.
      (EPA/EAB).  Revised Regulatory Alternatives for Small Boiler Impacts
      Analysis.  July 2,  1987.

4.    Letter and enclosure from Hogan,  T.  (EEA) to Link, T. (EPA/EAB).
      Regional Commercial Oil and Gas Price Forecasts..  July 16, 1987.

5.    Letter and attachments from Hogan, T.  (EEA) to Link, 'T. (EPA/EAB).
      Annualized Commercial Oil and Gas Prices.  July 28, 1987.

6.    Boston Trend.  Cushman and  Wakefield,  Boston.  1986.

7.    Hunneman Office Market Survey.  Hunneman, Boston.  1986.

8.    The Spaulding & Sly Report.  Spaulding & Sly, Boston.  1986.

9.    Nonresidential Buildings Energy Consumption Survey:  Commercial Build-
      ings Consumption and Expenditures 1983.  U.S. Department of Energy,
      Energy Information Administration.  DOE/EIA-0318(83).  September 1986.
                                     3-38

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                   4.  ECONOMIC IMPACTS:  INDUSTRIAL SECTOR

      This section summarizes the economic Impact analyses for the Industrial
sector.  Because the number of industries affected by the proposed standards
is large, a two-fold approach has been used.  The first component focuses on
major steam using Industries and the second component addresses smaller
industrial groups.
4.1  MAJOR STEAM USERS
      Boilers are used in all manufacturing groups.  This section discusses
trends in the financial and economic characteristics of a subset of manufac-
turing industries labeled ,"major steam users."
      The major steam users consist of the following manufacturing groups:
   •  Food (SIC 20)
   t  Textiles (SIC 22)
   t  Paper (SIC 26)        ...         ..
   0  Chemicals (SIC 28)
   t  Petroleum (SIC "29)
   •  Primary metals (SIC 33)
These industries have been selected because:
   •  as a group, they account for most of the total  number of
      industrial boilers and industrial boiler annual  fuel  consumption;
      and
   •  individually, they represent those industrial classes with the
      greatest number of boilers.
Table 4-1 shows that this group of major steam users accounted for 79 percent
of the total number of large (greater than 14.7 MW or 50 MMBtu/hr) boilers, 90
percent of the total annual fuel  consumption in large boilers, and 71 percent
of the total number of boilers between 14.7 and 29.3 MW (50-99 MMBtu/hr) in
the manufacturing sector in 1979.1   Data are not available  for boilers  smaller
than 14.7 MW (50 MMBtu/hr) by industry group.
      This section also summarizes the projected short-term economic impacts
on each of these major steam user groups of the alternative air emissions
                                      4-1

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               TABLE 4-1. AN OVERVIEW OF THE USE OF BOILERS  IN
                       MANUFACTURING INDUSTRIES IN 1979*
Manufacturing Group
(SIC Code)
                               >14.7 MW (>50 MMBtu/hrlb
Number of    1979 Fuel  Consumption
Boilers        PJ       (1012 Btu)
   14.7-29.3 MW
(50-99 MMBtu/hr)c
Number of Boilers
Food and kindred
products (20)
Textile mill
products (22)
Paper and allied
products (26)
Chemicals (28)
Petroleum (29)
Primary metals (33)
Subtotal for major
steam users
Total manufacturing
Subtotal/total
1,122
382
1,239
1,783
653
_647
5,826
7,408
79%
338.7
74.8
1,661.9
1,290.4
493.1
596.3
4,455.3
4,928.4
90%
(321.0)
(70.9)
(1,575.2)
(1,223.1)
(467.4)
(565. 2)
(4,222.8)
(4,671.2)
90%
593
286
331
618
241
20Z
2,276
3,203
. 71%
8  Unweighted data:  includes only establishments which responded to the
   survey (Form EIA-463); does not include estimates for establishments which
   did not respond to the survey.   Includes natural  gas, coal, fuel oil,
   pulping liquor, blast furnace gas,  coke oven gas, refinery off-gas, wood
   and miscellaneous other fuels.

b  Reference 1, p. 5,

c  Reference 1, p. 28.
                                     4-2

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     standards for new small industrial fossil fuel-fired boilers.  A "worst case"
     analysis has been conducted in order to delimit the magnitude of possible
     adverse economic impacts.
*   4.§.1 Economic Profiles
           Overview.  The six aforementioned major steam users accounted for 40
     percent of total product shipments by the manufacturing sector in 1986.3  They
     represent a collection of manufacturing industries which have experienced
     sharply different trends in output, profitability and general economic perfor-
     mance to date.
           Figure 4-1 and Table 4-2 compare, for example, the growth in output for
     each of the six industries since 1977.4  In  general,  output  in the food,
     chemicals and paper industries grew relatively consistently at or above the
     industrial annual average of 2.6 percent over the past ten years.  In 1987 the
     quantity of goods produced in these three sectors was up 38-44 percent over
     1977 levels and 20-35 percent over the levels experienced during the 1982 eco-
     nomic recession.  Output in the food sector, in particular,  appeared to be
     relatively insensitive to economic recession.
           In contrast, production in the textile, petroleum and primary metals in-
     dustries fell 10-35 percent below 1977 levels during the recession of 1982.
     Although output for these three industries recovered in the post-1982 period,
     this group has lagged behind the food, chemicals and paper industries and has
     continued to experience problems.  For instance, primary metal production
     dropped between 1984 and 1986 due to continued competition from steel imports
     and steel substitutes.
           Figures 4-2 through 4-4 and Tables 4-3 through 4-5 review the profit-
     ability and the financial performance of each of the six major steam using
     sectors.  Figure 4-2 measures trends in the after-tax rate of return which
     accrued to Investors in each of the six industries during the eight quarters
     of 1985 and 1986.  Investments in the food and kindred products (SIC 20)
     industry yielded the highest after-tax rates of return over these eight
     quarters --a reflection of the strong growth in food production observed
     earlier in Figure 4-1.  Rates of return on equity in the paper (SIC 26),
     chemicals (SIC 28) and textile (SIC 22) industries also exceeded the all man-
     ufacturing average in 1985 and" 1986.  In contrast, the primary metals (SIC 33)
                                           4-3

-------
                      FIGURE 4-1

        Federal Reserve Board Index Of

               Industrial Production

             INDEX BY MANUFACTURING GROUP
                       1977 = 100
160
140
120
100
 80
 60
 40
 20
       _L
J	I	I	I	I
J	I
  1977  1978  1979   1980  1981   1982  1983 , 1984   1985   1986  1987
                         4-4

-------
                       TABLE 4-2.   FEDERAL RESERVE BOARD
                        INDEX OF INDUSTRIAL PRODUCTION4
                                 (1977 » 100)

Year
1987
1986
1985
1984
1983
1982
1981
1980
1979
1978
Food
137.8
134.4
130.2
126.9
120.4
114.9
113.7
111.4
106.7
104.3
Textiles
115.9
109.2
103.2
104.2
100.9
89.2
98.1
100.8
104.4
102.8
Paper
144.4
136.5
127.6
127.2
119.8
109.4
112.4
110.6
110.8
106.8
Chemicals
140.2
132.0
127.1
121.6
114.0
103.8
112.6
106.4
111.4
106.8
Petroleum
93.5
92.7
86.8
87.4
84.0
84.2
89.4
94.0
101.7
102.5
Primary
Metals
81.3
75.1
80.5
82.3
73.0
65.8
95.0
90.4
108.5
107.0
Total
Industrial
129.8
125.1
123.8
121.4
109.2
103.1
111.0
108.6
110.7
106.5
a  Reference 4.  Also see Figure 4-1.
                                      4-5

-------
                         RGURE 4-2
 Percent

 20
             Rates Of After-Tax Profit On

                 Stockholders' Equity

                 PERCENT BY INDUSTRY GROUP
 15
 ID-
-10
-15
-20
-25
-30
                            Ofl^M^MU
                            riuiwy
     1965.1   19852   1965.3   1965.4    1966.1   19662   1966.3   1966.4

                          YEAaQTR
                            4-6

-------
                        RGURE 4-3

   Rates Of After-Tax Profit On Total Assets
                 PERCENT BY INDUSTRY GROUP
Percent
10
 8
 •2-
 •8-
•10-
-12
     1965.1   19652   1965.3   1965.4   1986.1    19662   1966.3   1986.4

                            YEAR. QTR
                            4-7

-------
                         FIGURE 4-4

        After-Tax Profits Per Dollar Of Sales
                   CENTS BY INDUSTRY GROUP
 CENTS
 8-
 •8
-10
    1965.1   19852   1965.3   1965.4   196ai    19662    196&3    1966.4
                          YEARQTR
                           4-8

-------
               TABLE 4-3.  AVERAGE RATES OF AFTER-TAX PROFIT ON
                    STOCKHOLDERS' EQUITY BY INDUSTRY GROUP"
                                   (Percent)


4Q 1986
3Q 1986
2Q 1986 ^
1Q 1986
4Q 1985
3Q 1985
2Q 1985
1Q 1985
Food &
Kindred
Products
19.6
15.5
15.7
12.9
16.9
16.5
15.0
12.8
Textile
Mill
Products
17.0
14.3
14.6
12.0
13.5
7.8
7.4
5.7
Paper
& Allied
Products
12.3
10.6
12.1
7.9
9.4
8.1
11.7
9.8
Chemicals Petroleum Primary
& Allied & Coal Metals
Products Products
8.2
15.4
14.9
12.8
3.1
8.7
13.4
12.5
4.5
1.0
11.5
7.4
8.8
9.3
5.2
10.5
- 4.0
- 30.7
- 2.0
- 2.6
- 13.3
- 7.3
- 8.1
. - 3.0
All
Manuf .
8.6
8.5
12.2
9.0
9.3
9.9
10.9
10.5
a  Quarterly Financial Report for Manufacturing, Mining and Trade Corpora-
   tions.  U.S. Department of Commerce, Bureau of the Census.  Various issues.
                                      4-9

-------
        TABLE 4-4.  AVERAGE RATES OF AFTER-TAX PROFIT ON TOTAL ASSETS
                              BY INDUSTRY GROUP8
                                  (Percent)

Food &
Kindred
Products
4Q 1986-
3Q 1986
2Q 1986
1Q 1986
4Q 1985
3Q 1985
2Q 1985
1Q 1985
7.5
6.0
6.5
5.3
7.1
7.3
6.6
5.6
Textile
Mill
Products
7.9
6.6
6.7
5.4
6.1
3.5
3.5
2.7
Paper
& Allied
Products
5.5
4.8
5.6
3.7
4.5
3.8
5.7
4.7
Chemicals Petroleum Primary
& Allied & Coal Metals
Products Products
3.8
7.2
7.0
5.9
1.5
4.4
7.0
6.4
1.9
0.4
4.9
3.1
3.7
3.9
2.2
4.6
- 1.4
- 10.3
- 0.7
- 0.9
- 4.9
- 2.7
- 3.0
- 1.1
All
Manuf .
3.8
3.8
5.5
4.0
4.2
4.5
5.0
4.8
a  Quarterly Financial  Report  for Manufacturing, Mining  and  Trade Corpora-
   tions.  U.S.  Department of  Commerce,  Bureau of the Census.   Various issues.
                                    4-10

-------
             TABLE 4-5.  AVERAGE AFTER-TAX PROFITS PER DOLLAR OF
                            SALES BY INDUSTRY GROUP3
                                    (Cents)
         Food 4    Textile    Paper       Chemicals   Petroleum  Primary  All
         Kindred     Hill     & Allied    & Allied    & Coal     Metals   Manuf.
         Products  Products   Products    Products   Products
4Q 1986
3Q 1986
2Q 1986
1Q 1986
4Q 1985
3Q 1985
2Q 1985
1Q 1985
5.2
4.0
4.1
3.6
4.6
4.6
3.9
3.4
4.6
3.9
4.0
3.3
3.5
2.2
2.1
1.7
4.8
4.4
5.0
3.4
3.9
3.3
4.8
4.0
4.1
7.6
7.0
6.1
1.5
4.4
. 6.5
6.3
3.0
0.7
7.3
4.0
4.0
4.3
2.4
5.2
-1.2
-9.4
-0.6
-0.8
-4.3
-2.4
-2.6
-1.0
3.3
3.4
4.7
3.5
3.4
3.7
4.0
4.0
a  Quarterly Financial Report for Manufacturing, Mining and Trade Corpora-
   tions.  U.S. Department of Commerce, Bureau of the Census.  Various issues.
                                     4-11

-------
industry continued to be a poor investment  with  losses reported during each of
the eight quarters in 1985/1986.   Investments  in the petroleum industry (SIC
29) also have suffered recently as a consequence of the slide in crude oil
prices.  The after-tax rate of profit on  stockholders'  equity in the petroleum
sector fell from 11.5 percent in  the second quarter of 1986 to 1.0 percent in
the following quarter and then rose slightly to  4.5 percent by the end of the
year.
      Figure 4-3 illustrates trends in the  productivity of assets in terms of
producing income in each of the six major steam  using sectors.  As of the
fourth quarter of 1986, both the  textile  mill  products and the food and
kindred products industries were  the most productive in the use of assets.
Rates of return in the two industries averaged 7.9  percent and 7.5 percent,
respectively.  Asset productivity also has  remained strong in the paper and
chemicals industries (except for  a weak fourth quarter performance in the
latter). Neither the petroleum nor the primary metals industries has performed
well in relation to the other four.  As shown  in Figure 4-3,  the after-tax
profit rate on total assets in the petroleum industry fell  to 0.4 percent in
the third quarter of 1986 and the primary metals sector suffered a 10.3
percent loss during that same time period.
      Data on the after-tax profits per dollar of sales paint a similar
picture to that provided in the earlier figures.  Figure 4-4  shows that,
except for the fourth quarters, the chemicals  industry has  turned in the
highest level of after-tax profits per dollar  of sales  (6-8 cents) in
1985/1986.  Generally, the after-tax profits per dollar of sales have been
roughly similar (3-5 cents) for the food, textile and paper industries
especially during 1986.
      In 1983 the food and kindred products industry employed the largest
number of workers (1,635,000 laborers)  and  the petroleum and  coal  products
sector employed the fewest (192,000)  of the s.ix  manufacturing groups
considered in this study.  As shown in.Table 4-6, this  distribution is
expected to continue through the  mid-1990s  with  one exception: the number of
jobs in the paper and allied products industry will  exceed  that in the textile
industry in 1995 as the latter declines in  importance.   In  addition,  the
                                     4-12

-------
                   TABLE 4-6.  EMPLOYMENT BY INDUSTRY GROUP3
                              (Thousands of Jobs)
                                        1983            1990             1995
Food and kindred products               1,635           1,663            1,646


Textile mill products                     753             725             680


Paper and allied products                 663             699             705


Chemicals and allied products           1,051           1,098            1,115


Petroleum and coal products               192             191             192


Primary metals industries                 834             950             975



3  Reference 5.
                                     4-13

-------
number of jobs in the food and kindred products  industry also is projected to
reach a peak in 1990 and then decline by 17,000  through 1995.5
      In the remainder of this section,  U.S.  Department of Commerce data are
summarized for the last ten years  for each of the major steam users.3'6'7 Data
items of interest include trends in:
   t  value of shipments
   •  employment
   •  significance of imports and  exports
   •  new plant and equipment expenditures
      Food.  The Food and Kindred  Products industry (SIC 20)  is a relatively
large and diverse sector consisting of about  25  major sub-industries which
process food and beverages for human  and animal  consumption.   In 1986 this
industry accounted for the second  highest level  of product shipments among 14
manufacturing industries classified by 2-digit SIC.3  .
      As shown in Table 4-7, the real  (1985 $) value  of total shipments by the
food industry stayed relatively constant in the  late  1970s and then dropped
about 11 percent to $301.6 billion in 1985 before picking up  slightly in the
following year.
      Total employment in this sector also has been declining.  From 1979 to
1985 the labor force dropped from  1,733,000 to 1,602,000 and  then rose to
1,617,000 in 1986.  Despite this drop in employment;  labor productivity in the
Food and Kindred Products industry has grown  faster than the  rest of the
manufacturing industries due largely  to  significant technological improvements
in food processing machinery.8
      In recent years the U.S. has maintained a  deficit in the balance of
trade for food and kindred products.   Nevertheless, this deficit has been
declining.  In 1986, U.S. exports  of  processed food and beverages rose over 5
percent to $10.8 billion while imports rose only 2.5  percent  to $16.4 billion.
As shown in Table 4-7, imports in  recent years accounted for  about 4 percent
of the total volume of shipments of food and  kindred  products.  The U.S. also
has exported about 4 percent of the total  supplies  of food and kindred
products.
                                     4-14

-------
                              TABLE 4-7.  HISTORICAL TRENDS: FOOD AND KINDRED PRODUCTS (SIC 20)
tn


Value of Shipments ($109)
(1985 $109)
Total Employment (000)
Import/new supply ratio"
Export/shipment ratiob
New plant and
equipment ($109)
(1985 $109)
1977
192.9
319.6
1,711
.03
.04

n/a
n/a
1978
216.0
333.6
1,724
.04
.04

4.8
7.4
1979
236.0
334.8
1,733
.04
.04

5.0
7.1
1980
256.2
333.3
1,708
.04
.05

5.8
7.5
1981
272.1
322.8
1,671
.04
.05

6.0
7.1
1982
280.5
312.8
1,636
.03
.04

6.7
7.5
1983
287.1
308.1
1,615
.03
.04

5.8
6.2
1984
300.0
310.0
1,619
.04
.04

6.4
6.6
1985
301.6
301.6
1,602
.04
.03

7.0
7.0
1986
314.5
306.3
1,617
.04
.04

N.A.
N.A.
         a   Value of imports/(value of Imports plus domestic  shipments).
         b   Value of exports divided by value of domestic shipments.

-------
      According to a recent study,  the continuation of favorable consumer
purchasing habits, Increases In disposable income and changing demographics
all point towards increased industry shipments  in the future.  In addition,
the recent wave of mergers and acquisitions will  provide benefits in terms of
increased economies of scale and improved efficiency in this industry.  These
factors, in conjunction with favorable outcomes on food and agricultural
issuesin multilateral trade negotiations, indicate continued economic health
in the Food and Kindred Products industry.9
      Textiles. Shipments by the textile mill  industry (SIC 22} rose 2.4 per-
cent between 1985 and 1986 after having dropped 4.0 percent below the pre-
ceding year.  Despite the recent expansion in demand, domestic textile product
shipments have tended towards a pattern of long term decline in real terms.
Between 1977 and 1985, textile mill  product shipments (measured in constant
dollars) fell 21 percent. This was  largely attributable to the intense
competitive atmosphere generated by a rising volume of imports in recent
years.10 As  shown  in  Table 4-8, the ratio of imports to the  total new  supply
of textile products doubled over the 1977-1986  time frame.  During .the same
time period, the ratio of textile exports to total  shipments generally
declined.
      Industry restructuring, plant closings and  consolidations in the wake of
increased import competition made an impact on  employment.  As shown in Table
4-8, textile mill employment dropped 22 percent from 910,000 in 1977 to
705,000 workers in 1986.
         Investments in new plant and equipment in  the textile industry
averaged $2.0 billion a year (in 1985 $)  in the late 1970s.   These capital
expenditures dropped to $1.6-1.8 billion per year (in 1985 $) in the mid-1980s
due to a downturn in profits.
      Paper and Allied Products.  The Paper and Allied Products industry (SIC
26} produces pulp, paper, paperboard and converted  paper products.  Primary
paper products (pulp, paper and paper board} account for about 44 percent of
the total output of this industry.   Some of the primary product output is sent
directly to end-users.  However, most of it is  sold to firms in the  allied
conversion sector for further processing into paper products.  These firms,
                                     4-16

-------
                       TABLE 4-8.  HISTORICAL TRENDS:   TEXTILE MILL PRODUCTS  (SIC 22)


Value of Shipments ($109)
(1985 $109)
Total Employment (000)
Import/new supply ratio8
Export/shipment ratio6
New plant and
equipment ($109)
(1985 $109)
1977
40.6
67.4
910
.04
.04

1.2
2.0
1978
42.3
65.4
899
.04
.04

1.3
2.0
1979
45.1
64.1
885
.04
.05
.
1.4
2.0
1980
47.2
61.6
848
.04
.06

1.5
2.0
1981
50.1
59.8
823
.05
.05

1.7
2.0
1982
47.5
52.7
749
.05
.04

1.6
1.7
1983
53.4
56.2
741
.05
.03

1.6
1.7
1984
55.5
56.9
746
.06
.03

1.9
2.0
1985
53.3
53.3
702
.07
.03

1.8
1.8
1986
54.6
53.2
705
.08
.03

1.6
1.6
8  Value of imports/(value of imports plus domestic shipments).
b  Value of exports divided by value of domestic shipments.

-------
and those in the primary products  sector,  collectively operate more than 6,500
establishments nationwide.   Establishments involved largely in the relatively
capital-intensive primary products sector  have  increasingly concentrated in
the South close to abundant timber reserves.  Establishments in the more
labor-intensive allied conversion  industries  have  tended to be more widespread
and closer to end-users.11
      Except for the recession  of  1982,  the total  value of shipments by the
Paper and Allied Products sector increased steadily over the past 10 years.
The total value of shipments more  than doubled  between 1977 and 1986 at an
average annual rate of 8.0 percent.   In  real  terms,  the total  value of ship-
ments grew 1.7 percent per year over the 1977-1986 time period (see Table
4-9).
      During this time period,  total  industry employment reached a peak of
707,000 workers in 1979 and then declined  to  661,000 by 1983 as a result of
economic recession in 1982 and  the restructuring of firms through increased
merger and acquisition activity.  Total  employment in this industry rose from
1983 to 1986 as a result of increased output  and profitability.  By 1986
employment stood at 674,000 workers  or 1.8 percent above the level  of 1983.
      Imports of pulp (primarily from Canada) constituted a major,  albeit
declining, source of supply for this  sector during the past 9  years.   The
import share of new pulp shipments held  steady  at  about 31 percent  in the late
1970s and then declined to 24 percent in 1986.  Imports of paper and board
also held steady at about 10 percent  of  total supply throughout the late 1970s
and early 1980s and then jumped to 13 percent by 1985.   The decline in the
strength of the dollar has since caused  imports of paper and board  to drop
back to 12 percent of total new supply.
      Annual expenditures for new  plant  and equipment (measured in  1985 $)
rose almost 47 percent between  1977  and  1979  and then fell  26  percent to $6.3
billion during the 1982 economic recession.   Coincident with the growth in
output and profits since the recession,  annual  new capital  expenditures also
rose and stood at $8.7 billion  (in 1985  $)  in 1986.
      Chemicals and Allied Products.  Firms in  this  manufacturing group
produce basic materials and chemical  feedstocks for  use by other industries;
                                     4-18

-------
                     TABLE 4-9.  HISTORICAL TRENDS:  PAPER AND ALLIED PRODUCTS (SIC 26)


Value of Shipments ($109)
(1985 $109)
Total Employment (000)
Pulp mills (SIC 2611)
Import/new supply ratio8
Export/shipments ratiob
Paper and board
(SIC 262,263,266)
Import/new supply ratio8
Export/shipments ratio6
New plant and
equipment ($109)
(1985 $109)
1977
52.1
86.5
692

0.33
0.38


0.10
0.05

3.5
5.8
1978
57.0
88.2
699

0.31
0.35


0.11
0.05

3.8
5.9
1979
65.2
92.6
707

0.33
0.38


0.11
0.05

5.2
7.4
1980
72.8
94.8
693

0.31
0.45


0.10
0.08

6.5
8.5
1981
80.2
95.3
689

0.31
0.44


0.10
0.07

6.1
7.2
1982
79.0
88.2
662

0.29
0.41


0.10
0.06

5.6
6.3
1983
85.1
91.6
661

0.29
0.40


0.10
0.05

5.9
6.3
1984
95.9
99.1
681

0.31
0.38


0.11
0.05

7.2
7.4
1985
93.4
93.4
677

0.27
0.36


0.13
0.04

8.6
8.6
1986
103.8
101.1
674

0.24
0.37


0.12
0.04

8.9
8.7
a  Value of imports/(value of imports plus domestic shipments).
b  Value of exports divided by value of domestic shipments.

-------
they also manufacture consumer goods  such as cosmetics,  perfumes and drugs.
The chemical industry ranks fifth in  contribution to GNP among manufacturing
industries.  It is extremely diverse  both in terms of the large number of
chemical products and in terms of the firms producing the chemicals.12
      Like the paper industry, the chemicals industry is its own best
customer.  Only 13 percent of industrial  chemical  shipments go to final
customers; 46 percent go to other sectors of the  chemical industry; and 41
percent go to the manufacturing industry.13
      Measured in 1985 dollars, the total value of shipments by the chemicals
industry increased at a 2.2 percent annual  rate between  1977 and 1981.   The
1982 economic recession took a toll on the chemicals industry as the real
value of shipments dropped 10 percent in  one year to 193.0 billion dollars --
a level lower than that of 1977 (see  Table 4-10).   The real value of shipments
peaked again in 1984 at 218.8 billion dollars and then dropped to 193.1 bil-
lion dollars in 1986.
      Total employment in the chemical  and allied products sector reached a
peak of 1,109,000 laborers in 1981.  As a result  of the  1982 economic reces-
sion, subsequent mergers and industry restructuring,  the number of workers in
the chemicals industry fell 7.8 percent below the 1981 peak to 1,022,000 by
1986.
      The chemical and allied products industry has been a net exporter of
chemicals to the rest of the world.  As shown in  Table 4-10, imports averaged
about 5 percent of the total supply of chemicals  in the  late 1970s and  early
1980s.  Recently, however, the import share edged  up to  7 percent in 1986.
The export share of total shipments has dropped from 14  percent in 1980 to 11
percent in 1986.
      Petroleua Refining.  As shown in Table 4-11,  the real value of petroleum
and coal products shipments in the U.S. grew 13.2  percent per year between
1977 and 1981 --largely a reflection  of the doubling in  real crude oil  prices
which occurred in that time period.  Between 1981  and 1985, the real value of
shipments dropped 9.4 percent per year as a result  of slackening demand.
Shipments tumbled a further 30 percent from 1985  to 1986 due to the collapse
in crude oil prices in that time frame.14
                                     4-20

-------
                           TABLE 4-10.  HISTORICAL TRENDS:  CHEMICALS AND ALLIED PRODUCTS (SIC 28)
rv>


Value of Shipments ($109)
(1985 $109)
Total Employment (000)
Import/new supply ratio'
Export/shipment rat1ob
New plant and
equipment ($109)
(1985 $109)
1977
118.2
196.2
1,074
.04
0.10

7.4
12.3
1978
129.4
200.2
1,096
.05
0.10

7.8
12.1
1979
147.7
209.9
1,109
.05
0.13

9.8
13.9
1980
162.5
211.7
1,107
.05
0.14

11.6
15.1
1981
180.5
214.4
1,109
.05
0.13

13.1
15.5
1982
170.7
'193.0
1,075
.05
0.12

12.7
14.2
1983
183.2
204.7
1,043
.05
0.10

13.0
14.0
1984
198.2
218.8
1,049
.06
0.11

15.3
15.8
1985
197.3
197.3
1,044
.06
0.10

16.4
16.4
1986
198.3
193.1
1,022
.07
0.11

17.1
16.7
         *   Value of imports/(value of Imports plus domestic shipments).
         b   Value of exports divided by value of domestic shipments.

-------
 Value of Shipments ($io»)
              (1985 $109)

Total Employment (000)

fetroleuj,„,,.,„

T«MMAU^. I
New plant and
  equipment
      (1985 $10')
                                                      «80__1981     1982     1983
97.5
161.9
202
103.9
160.7
208
148.4
210.0
210
198.7
258.9
IQft
	 —
224.1
266.2
01 *
	 • 	
206.4
230.5
— • 	
191.6
206.2
J7O1
1 	
200.6
207.2
1965
• 	 — — .
179.1
179.1
1986
—— 	
129.3
125.9
201
                                                                               196
                189
                                                                                               ,79
                                168
0.09
0.01
11.8
19.6
0.07
0.01
13.2
20.4
0.07
0.01
15.2
21.6
0.07
0.01
19.6
25.5
0.07
0.02
26.0
30.9
0.07
0.03
26.4
29.5
0.09
0.03
23.1
24.9
0.11
0.03
2|.5 26.7
26.3 26.7
18,7
18.2

-------
      Employment trends In the petroleum and coal products sector (SIC 29)
have essentially mirrored the changes in shipments.  Employment peaked in 1981
at 214,000 workers and then declined to 179,000 in 1985 at a compound annual
rate decline of 4.5 percent.  This rate of decline increased to 6.1 percent
between 1985 and 1986 as a result of: 1) curtailments in oil and gas explora-
tion brought on by the sharp decline in crude oil prices; and 2) industry
retrenchment due to increased corporate merger and acquisition activity.
      The drop in crude oil prices in 1985/1986 had a significant impact on
new plant and equipment expenditures for the petroleum and coal products
industry.  Between 1981 and 1985, new plant and equipment expenditures (in
$1985) generally dropped $3-5 billion below the 1981 peak of $30.9 billion.
In 1986, capital expenditures plummeted 32 percent to $18.2 billion.
      Iron and Steel.   Since 1982, the iron and steel industry has been
embedded in a long term slump due to slow growth in domestic demand coupled
with world-wide market saturation and low productivity improvements.15   Steel
shipments in 1986 were $46.2 billion (in 1985$) or 44.5 percent below the 1981
level of $83.2 billion (see Table 4-12).  Pig iron production in 1986 also was
down 40 percent below 1981 levels.
      Structural shifts in the pattern of steel consumption, aging capital
stock and high labor costs have, in large part, been responsible for the steel
industry plight.  Even though the quantity of steel mill  product shipments
generally rose from 1982 through 1985,  the industry permanently .cut 12
percent of domestic steel making capacity and 20 percent of domestic iron
making capacity over this time period.  Despite these cuts, the industry still
operated at less than two-thirds capacity in the mid 1980s.16
      Higher levels of steel mill product imports also contributed to the in-
dustry's problems.  Imports soared from 15 percent of total steel mill
products supplied in 1979 to 26 percent in 1984 before falling slightly in
1985/1986 as a result of the President's Steel Import Restraint program.
      The iron and steel industry slashed its work force by nearly 25 percent
or 102,000 workers during the 1981/1982 economic recession.  The labor force
has continued to decline since that time period.  In 1986 a total of 175,000
                                     4-23

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                          TABLE 4-12.  HISTORICAL TRENDS:  IRON AND STEEL INDUSTRY8


Value of Shipments ($109)
(1985 $109)
Pig iron production
(106 short tons)
Raw steel production
(106 short tons)
Raw steel production
capability
utilization rate (%)b
Total steel mill
products shipments
(106 short tons)
Total Employment (000)
Market penetration of
imported steel mill
products (%)c
1977
50.6
83.8

81.3

125.3


78


91.1
452


18
1978
59.1
91.3

87.7

137.0


87


97.9
449


18
1979
67.3
95.5

87.0

136.3


88


100.3
453


15
1980
61.5
80.0

68.7

111.8


73


83.9
399


16
1981
70.1
83.2

73.6

120.8


78


88.5
391


19
1982
47.3
52.7

43.3

74.6


48


61.6
289


22
1983
48.2
51.7

48.7

84.6


56


67.6
243


21
1984
53.8
55.6

51.9

92.5


68


73.7
236


26
1985
52.5
52.5

50.4

88.3


66


73.0
208


25
1986
47.4
46.2

44.0

81.6


64


70.3
175


23
8  American Iron and Steel Institute and U.S. Department of Commerce.

b  Tonnage capability to produce raw steel for a full order book based on the current availability of raw
   materials, fuels and supplies, and of the industry's coke, iron, steelmaking, rolling and finishing
   facilities.2

c  Imports/(imports plus domestic production); in terms of short tons.

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                                   TABLE 4-12.  HISTORICAL TRENDS:  IRON AND STEEL INDUSTRY"
                                                          (continued)


Capital


expenditures
(1985 $109)
Net income ($109)
1977
n/a
n/a
n/a
1978
n/a
n/a
n/a
1979
2.5
3.6
0.8
1980
2.7
3.5
0.7
1981
2.4
2.9
1.7
1982
2.3
2.6
-3.4
1983
1.9
2.0
-2.2
1984
1.2
1.2
0
1985
1.6
1.6
-1.8
1986
0.9
0.9
-4.1
         8  American Iron and Steel Institute and U.S. Department of Commerce.
in

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laborers were employed in the iron and steel  industry--down 61 percent from a
1979 high of 453,000 workers.
      Operating losses have further frustrated the industry's attempt to
modernize aging plant and equipment.  As shown in Table 4-12, new capital
expenditures (in 1985 $) averaged $1.2-1.7 billion in 1984-1985 and were
concentrated largely on productivity and quality enhancing equipment such as
continuous casters.  Although these expenditures (in 1984/1985) were made in
the face of continuing operating losses, they were nevertheless down more than
50 percent below the amounts expended in the  late 1970s and early 1980s.
      After five consecutive years of losses, total  net income in 1987 was
$1.0 billion.  Production of raw steel  and steel  mill products increased in
1987 over 1986 levels and total  employment declined in 1987.   Raw steel
production capability utilization rate rose to 80 percent in  1987.17
4.1.2  Projected Impacts on Product Prices
      The economic impact analysis for the major steam user groups in the
industrial sector focuses on presenting aggregate incremental annualized
pollution control costs as a percent of 1985  average product  prices.   This
analysis assumes full passthrough of pollution control  costs.
      The effect of a regulatory option on 1985 average product prices is
calculated by finding the product of the change in the cost of new steam, the
share of steam affected by the regulatory option  and the amount of steam
consumed per dollar of 1985 output (see Figure 4-5).   The cost impacts are
stated in real  terms.  The only real  cost increase is assumed to be due to new
boiler, pollution control and fuel costs.   All  other production costs are held
constant in real terms at 1985 levels.
      When regulatory options are applied,  the first component of the product
price calculation (the change in the cost of  new  steam)  is affected.   The cost
of new steam changes due to an option's effect upon  annualized boiler and
pollution control capital costs,  annualized non-fuel  operating and maintenance
(O&M) costs, and annual ized fuel  costs.   When this new steam  cost change is
multiplied by the ratio of annual  steam consumed  (per unit of output)  to
annual dollar value of shipment  (per unit output)  a  gross change in product
price is derived.  Because a certain percentage of the  product is produced
                                     4-26

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                          RGURE 4-5
          Derivation Of Estimated Increase
   In National Average Industrial Product Prices
           Due To Pollution Control Costs
    A Product
       Price
 Steam
Intensity X
 Ratio
   % Of TOtal
Steam Affected By   y
Alternative Control   A
     Level
Where.
 Steam Intensity Ratio   —
               Industrial Boiler
         Total Fuel Consumption in 1985
            1985 Value Of Shipments
  % Of Total Steam
Affected By Alternative
    Control Level
           New SmaJI Industrial Boiler
          Total Fossil Fuel Consumption

            Total Fuel Consumption
    \         From All Boilers
                          x100
 Maximum Cost Impact  =
                                 Increase In Total
                                 Annualized Costs
                             Total Fossil Fuel Consumption
                            From New Small Industrial Boilers
            (%)   =   (GJ/$)  x  (%) x  ($/GJ)
                             4-27

-------
with steam generated from existing boilers,  the cost estimate is reduced by
the proportion of new boiler steam to total  steam used within each industry
group, which results in an average steam cost for the industry.
      The ratio of annual total  industrial  boiler fuel consumed to annual
dollar value of shipment by industry is assumed to remain constant over time.
Ratios employed in this analysis are listed in Table 4-13.  This table shows
that the paper industry is a relatively steam-intensive group.
      An analysis of average cost impacts would involve allocating the
projected increases in total annualized costs in Section 2 by industry group
(which is not available) and dividing by the consumption of all  fuels in new
small industrial boilers.  This  assumes full cost pass-through.   Next,
multiply by a small fraction which represents the amount of total steam
requirements met by new small  boilers.   This type of analysis was conducted
for the large (>29 MW, >100 MMBtu/hr) industrial boiler NSPS analysis and the
average change in product price  was  estimated to be less than 0.1 percent for
each of the major steam user groups.2
      This analysis for small  boilers focuses on the marginal. not average,
costs.  The marginal costs are the maximum,  worst case annualized cost
increases per unit of annual boiler  fuel  demand.  The maximum, worst case
annual 1 zed cost increase per unit of annual  boiler fuel  demand is derived from
the national impacts analysis  in Section 2.   Table 4-14 presents the deriva-
tion of this parameter for coal  and  residual fuel  oil.  Because  of the fabric
filter requirement for PM emissions  control, coal  is expected to have a
relatively larger average annualized cost impact per unit of annual  fuel
demand than residual fuel oil.
      The "% of total steam affected by the  alternative control  level" is 100%
if all of the boilers at the industrial  facility are new, smaller than 29 MW
(100 MMBtu/hr) and burn coal or  residual  fuel  oil.   Otherwise (and usually),
this parameter 1s less than 100  percent because some portion of  the  total
steam demand is met by larger and/or older boilers.
      The worst case marginal  cost impact analysis assumes the industry group
with the largest steam intensity ratio  in Table 4-13 (paper), the fuel type is
coal and all of the boilers are  new  coal-fired units <29 MW (<100 MMBtu/hr)  -
                                     4-28

-------
                      TABLE 4-13.   STEAM-INTENSITY RATIOS

Industry
Food
Textiles
Paper
Chemicals
Petroleum Ref.
Iron and Steel
1985
Industrial boiler
total fuel
consumption9
PJ (1012 Btu)
716
176
2,027
1,382
589
398
(679)
(167)
(1,921)
(1,310)
(558)
(377)
1985
Value of
shipmentsb
($109)
301.6
53.3
93.4
197.3
179.1
52.5
Industrial boiler
total fuel
consumption per $ of
value of shipments
GJ (106 Btu)
0.0024
0.0033
0.0217
0.0070
0.0033
0.0076
(0.0023)
(0.0031)
(0.0206)
(0.0066)
(0.0031)
(0.0072)
8  Includes natural gas, distillate and residual fuel oil, coal, wood, black
   liquor, LPG, refinery gas, blast furnace gas and coke oven gas.  EEA
   estimates.

b  U.S. Department of Commerce; reference Tables 4-7 through 4-12.
                                     4-?9

-------
                        TABLE 4-14.  NATIONAL IMPACTS'

Fuel Type
Coal
Residual
fuel oil
Annual
Fuel Demand
PJ (102 Btu)
8.65 (8.20)b
27.993 (26.532)b
Average Annual i zed Cost
Annual i zed Increase Per Unit of
Cost Increase Annual Fuel Demand
106 $1985 1985 $/GJ (1985 $/MMBtu)
18.245C 2.11 (2.23)
29.248d 1.04 (1.10)
8  Boiler size 3-29 MW (10-100 MMBtu/hr)  in the fifth year following proposal
   of NSPS.

b  Assumes a 26 percent average annual  capacity utilization rate.  A larger
   average annual capacity utilization  rate would result in smaller marginal •
   annualized cost impacts per unit of  fuel demand.

c  From Table 2-21, with monitoring and testing costs, $5.935 (4.113 + 1.822)
   million for S02 emissions  control  and  $12.31  (8.67 + 3.64)  million for
   complying with the 21 ng PM/J (0.05  Ib PM/MMBtu)  control level.

d  From Table 2-29, with monitoring and testing costs for the 129 ng SO^/J
   (0.3 Ib SOVMMBtu)  control  level,  $29.921  (7.255  + 22.666)  million less
   $0.673 million for distillate fuel oil monitoring and testing costs, or
   $29.248 million.
                                     *  •?•»

-------
so that 100% of the total steam demand is affected by the alternative control
level.  In this case, the expected change in product price is  (0.0206
MMBtu/dollar) * 100% *  ($2.23/MMBtu) - 4.6% (as outlined in Figure 4-5).
      This is a worst case analysis for several reasons:
   •  The coal annualized cost impacts in Table 4-14 include the
      estimates for fabric filters for new boilers 3-9 MW (10-30
      MMBtu/hr) and this is not required by the proposed coal  PM NSPS.
   •  A steam plant composed of only small new coal-fired boilers
      (without any older and/or larger boilers) is not typical; less
      than 100 percent of total steam requirements is affected by the
      NSPS is more typical.
   •  The cost impacts in Table 4-14 may be overstated if local air
      emissions standards are more stringent than the baseline assump-
      tions presented in Section 2.
   0  The cost impacts in Table 4-14 may include monitoring and testing
      costs which are not required by the proposed standards.
   t  The average annualized cost increase per unit of annual  fuel
      demand is overstated for new boilers with average annual capacity
      utilization rates .larger than 26 percent.
   •  Small coal boiler sales are much lower than oil or gas boiler
      sales (see Table 2-9); therefore, the pertinent marginal cost
      impacts for most affected facilities will be much smaller than
      $2.11/GJ ($2.23/MMBtu).
      The marginal impact on product prices is smaller than 4.6% for other
industry groups, other fuel types (residual  fuel oil, distillate fuel oil,
natural gas), and situations where less than 100 % of the total steam demand
is affected by the alternative control  level.   For example,  if the food
industry is selected with residual fuel oil  as the fuel  type and only 20% of
the total steam requirements at the plant are met by new units <29 MW (<100
MMBtu/hr), then the expected marginal  product price impact is  (0.0023
MMBtu/dollar) * 20% * ($1.10/MMBtu) - 0.05% (obviously much smaller than
4.6%).
      Therefore, the marginal annual costs of compliance with the proposed
standard are expected to increase product costs by less than five percent for
each of the major steam user groups.
                                     4-31

-------
4.2  SELECTED INDUSTRIES
4.2.1  Introduction
      The major steam users analysis focuses on aggregate two-digit SIC code
industries (i.e., SIC 28, Chemicals).   The selected industries analysis
addresses several smaller groups at the four-digit SIC code18  level.
      Industries most likely to experience cost-related impacts are those with
a high steam cost to production cost ratio.   A high ratio usually stems from
one of two factors:  1) the production process is  steam-intensive or 2) the
firm or industry has cyclic steam requirements, resulting in a low capacity
utilization of the boiler equipment.  Low capacity utilization causes the
capital  cost component of steam costs  to rise, yielding high annualized costs
per unit of steam.
      Capital availability constraints occur when  the cost of acquiring funds
is so high that a firm considers a project to be uneconomic or financially
unattractive.  -Capital availability is most  often  a problem for relatively
small firms.  Although some large firms may  have excessive debt burdens, lack
of access to organized capital  markets is more often characteristic of small
firms.
      Three four-digit SIC code industries were evaluated:
   t  rubber reclaiming (SIC 3031)
   t  automobile manufacturing  (SICs 3711, 3713 and 3714)
   •  liquor distilling (SIC 2085)
The economic analysis of selected industries focused on cost impacts,  capital
availability and profitability  indicators.
4.2.2  Methodology
4.2.2.1   Cost and profitability impacts.   The following three  steps are used
to estimate the cost impact of  regulatory options  on a selected industry:
   0  Step One -- Define a model  plant for the selected industry.
   t  Step Two -- Evaluate the  cost impacts  for the model  plant,
      assuming full cost absorption.
   •  Step Three -- Evaluate the impacts  on  the profitability  of the
      model plant.
                                    4-32

-------
Each step is described below.
      The selected Industries analysis focuses on model plants to measure the
economic Impact of regulatory options on each Industry.  The model plant
represents a typical plant for the segment of each Industry that might be
considering a boiler Investment either as boiler expansion or replacement.  A
model plant Is used since It 1s difficult to obtain precise details about the
expansion and replacement plans of actual firms.
      The following production characteristics for the model plant are
estimated:
   t  Plant Output/Year -- average product output per year In those
      plants more likely to Invest In new boilers.
   •  Price (Cost)/Un1t of Output -- the historic, average selling price
      per unit
   t  Plant Sales/Year -- plant output per year multiplied by price per
      unit of output.
   •  Plant Earnings/Year -- plant sales per year multiplied by a
      derived profit margin (percent return on sales).  The figure
      estimates the profitability of the model plant.
      The effect of regulatory options on product cost is calculated by
finding the product of the change in the cost of new steam, the share of steam
affected by .the new regulation, and the amount of steam consumed per dollar of
output.  The cost impacts are stated in real  terms.   The only real  cost
increase is due to new boiler and fuel costs; all other real  production costs
are held constant.
      The additional costs due to a regulatory option will  affect the profita-
bility of an industry.   This impact will  be assessed by examining the follow-
ing two financial Indicators for the model  plant:
   •  Net Profit After Taxes (Net Income).   Profit after all  costs and
      taxes have been deducted.
   •  Return on Assets.  Net income divided by total  assets,  converted
      to a percent form.
      The change in indicators due to regulatory options is a measure of the
ability of the model plant to absorb the additional  costs of a regulatory
option.
                                     4-33

-------
      Net income is calculated by subtracting expenses from total sales to
derive gross profit and then taxes are subtracted from gross profit to equal
net income.  Regulatory options could affect the amount of expenses, which
would alter net income.  Return on assets is derived by dividing net income  by
total assets for the model plant and converting to a percent form.  Altern-
ative regulatory options could affect net income, resulting in a change in
return on assets.
4.2.2.2  Capital availability.  Capital  availability constraints may result  if
regulatory options create a need for financing additional pollution control
investments.  The following two steps are used to evaluate whether capital
availability will be a constraint on a selected Industry:
   •  Step One -- Define financial indicators for a model firm.
   t  Step Two -- Evaluate the ability of a firm to finance pollution
      control investments.
      The firm is the focus of the capital  availability analysis because
decisions involving large capital expenditures are made at the corporate
level.  Depending upon the state of corporate cash reserves and the relative
costs of various financing tools, a firm will choose a combination of internal
and external financing instruments to meet  the additional investments required
to comply with regulatory options.
      The capital availability analysis  focuses on the following two financial
indicators, which measure each industry's financing ability:
   t  Coverage Ratio -- the number of times operating income (earnings
      before taxes and interest expenses) covers fixed obligations
      (annual interest on debt instruments  and long-term leases).
   •  Debt/Equity Ratio -- a measure of the relative proportions of two
      types of external financing.
      These two indicators are analyzed  for both the base case and the
regulatory options.  The change in indicators due to regulatory options is
analyzed to determine how difficult it will be for the firm to meet financial
requirements for the pollution control  equipment investment.
      The cash flow coverage ratio is calculated by dividing operating income
by fixed obligations, both of which could change as a result of alternative
regulatory options.  If the coverage ratio  remains above the 3.0 standard
                                     4-34

-------
benchmark, the cost of capital can be assumed to be above  "acceptable" levels.
However, as the coverage ratio falls, the cost of obtaining capital will rise.
      The debt/equity ratio Is calculated by dividing total debt by total
equity of the firm (book values).  The incremental debt Incurred from financ-
ing the pollution control required by the regulatory options 1s added to the
base debt; the Incremental equity Issued to finance the remainder of the
investment is added to the base case equity.  A new debt/equity ratio then is
calculated and the change is analyzed to assess the effect of the regulatory
options on the firm's capital structure.
      To determine the coverage and debt/equity ratios under alternative
regulatory options, five financing strategies, which differ by the percentages
of the investment financed by debt versus equity, are considered.  (Note that
for the changes in coverage ratios and debt/equity ratios,' 100 percent
external financing is assumed.)  The external financing scenarios are:
   •  zero percent new debt, 100 percent new equity
   t  25 percent new debt, 75 percent new equity
   •  50 percent new' debt, 50 percent new equity
   •  75 percent new debt, 25 percent new equity
   •  100 percent new debt, zero percent new equity.
4.2.3  Model Plant Descriptions19
      The typical rubber reclaiming industry plant has an annual output of
18,000 metric tons (20,000 short tons).  The typical plant's boiler house
contains three boilers that have a combined capacity of 62 MW (211 MMBtu/hr)
and all boilers are assumed to operate at 45 percent of rated capacity.   One
26 MW (87 MMBtu/hr) coal-fired boiler was assumed to be replaced.
      The model automobile manufacturing plant is assumed to be part of a 26-
plant firm.  Total annual firm production is 2.3 million vehicles.  The model
plant boiler house consists of four coal-fired boilers with a total capacity
of 102 MW (348 MMBtu/hr).  It was assumed that a 26 MW (87 MMBtu/hr) boiler
operated at a 25 percent average annual capacity utilization rate would be
replaced.
      The typical liquor distilling plant produces 17 million liters (4.5
million gallons) of distilled liquor annually.  It was assumed that two older
                                     4-35

-------
boilers would be replaced by a 26 MW (87 MMBtu/hr)  coal-fired boiler and a  18
MW (62 MMBtu/hr) boiler, both operated at an average annual capacity utiliza-
tion rate of 45 percent.
4.2.4  Reoulatorv Potion
      The three selected industry analyses all  involve new coal-fired boilers
18-26 MW (60-90 MMBtu/hr).  The regulatory option examined is a scrubber.
4.2.5  Summary of the Economic Impacts20
      The change in product cost was estimated  to be less than one percent  for
each of these three selected industries (assuming full  cost pass-through).
The expected change in return on assets is summarized in Table 4-15.
      The analysis of capital availability examines the  ability of the model
firm to finance the new boiler investment.  The coverage ratios and
debt/equity ratios did not vary significantly due to the pollution control
costs.  It was concluded that these industries  should be able to absorb
additional, financing of new boiler investments  without undue weakening of the
solvency position of the industries.
                                     4-36

-------
                    TABLE 4-15.   ESTIMATED RETURN ON ASSETS
                              FOR MODEL PLANTS"
                                   (percent)
Selected Industry
Base Case
Scrubber Requirement
Rubber reclaiming
Automobile manufacturing
Liquor distilling
   4.1
   8.1
   1.3
      1.0
      8.0
      0.5
   Reference 19, p. 9-33.
                                     4-37

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                                  REFERENCES


1.    Report on the 1980 Manufacturing  Industries  Energy Consumption Study and
      Survey of Large Combustors.   U.S.  Department of Energy,  Energy Informa-
      tion Administration.   DOE/EIA-0358.   January 1983.

2.    Projected Impacts of Alternative  Sulfur Dioxide New Source Performance
      Standards for Industrial  Fossil Fuel-Fired Boilers.  Energy and Environ-
      mental Analysis, Inc.,  Arlington,  Virginia.   Prepared for the U.S.
      Environmental Protection  Agency,  Office of Air Quality Planning and
      Standards.  March 1985.   p.  4-12.

3.    U.S. Department of Commerce,  Bureau  of Economic Analysis.  Survey of
      Current Business. Volume  67,  No.  6,  June 1987,  p.  S-3.

4.    Federal Reserve Board,  Statistical Release.   Industrial  Production.
      January 16,  1987; U.S.  Department of Commerce,  Bureau of Economic
      Analysis.  Survey of Current  Business.  Volume 68,  No. 12, December 1988,
      p. S-2.

5.    1985 OBERS BEA Regional Projections,  Volume  1:   State Projections to
      2035.  U.S.  Department of Commerce,  Bureau of Economic Analysis.  1985.
      p. 3.

6.    1987 U.S. Industrial  Outlook.  U.S.  Department of  Commerce, Inter-
      national Trade Administration.  January 1987.
    •
7.    Business Statistics:   1984.   U.S.  Department of Commerce, Bureau of
      Economic Analysis.  September 1985.

8.    Prospects for U.S. Basic  Industries,  1986-2000:  Implications for Elec-
      tricity Demand.  Electric Power Research Institute, Palo Alto,
      California.   EPRI P/EM-4502-SR.   March  1986.   p. 6-8.

9.    Reference 6, p. 39-1.

10.   Reference 6, p. 41-1.

11.   Reference 6, p. 5-1;  Reference 8,  p.  4-1 through 4-16.

12.   Reference 6, p. 11-1.

13.   Reference 8, p. 3-1 through 3-28.

14.   Reference 6, p. 10-1.

15.   Reference 8, p. 1-1 through  1-20.

16.   1985 Annual  Statistical Report.   American Iron  and Steel  Institute,
      Washington,  D.C.
                                    4-38

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17.   1987 Annual Statistical Report.  American Iron and Steel Institute,
      Washington, D.C.

18.   Standard Industrial Classification Manual 1987.  Executive Office of the
      President, Office of Management and Budget.

19.   Fossil Fuel Fired Industrial Boilers - Background Information Volume 1:
      Chapters 1-9.  EPA-450/3-82-006a.  U.S. Environmental Protection Agency,
      Office of Air Quality Planning and Standards.  March 1982.  Chapter 9.

20.   Reference 19, p. 9-31.
                                     4-39

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                                  APPENDIX A.
                  PROFILE OF BOILERS IN COMMERCIAL BUILDINGS

      This appendix summarizes information on the number and location of
boilers in commercial buildings.  This information is significant because most
commercial buildings in the United States do not include a boiler and,
therefore, will not be subject to an economic impact due to a NSPS.
      The U.S. Department of Energy/Energy Information Administration (Office
of Energy Markets and End Use) has conducted the Nonresidential Buildings
Energy Consumption Survey (NBECS) three times.  The 1979 NBECS collected data
during 1979 and 1980 from a statistical sample of 6,222 buildings.  The 1983
NBECS collected data during 1983 for a statistical sample of 7,140 buildings:
5,845 from the 1979 NBECS and 1,295 new buildings constructed between 1979 and
1982.  The 1986 NBECS collected data during 1987 for 9,189 buildings.  The
1986 NBECS excluded buildings smaller than 1,000 square feet and those whose
primary use is residential (the 1979 and 1983 NBECS did not).  Commercial
buildings in the 1979, 1983 and 1986 NBECS exclude buildings on military
installations and exclude buildings in which industrial or agricultural
activities occupied more of the total  floor space than any other type of
activity.
      The 1983 NBECS estimated that 73,000 (plus or minus 21,000*)  commercial
buildings constructed before 1980 had new (replacement) boilers installed
between January 1980 and July 1983.1   The 1983 NBECS  also estimated that there
were an average of 1.38 boilers per building which included a boiler.2
Therefore, about 100,000 (plus or minus 30,000) new (replacement) boilers were
installed between January 1980 and July 1983 in commercial buildings con-
structed before 1980.  The 1983 NBECS also estimated that 26,000 new boilers
were installed in new commercial buildings constructed in the four-year period
between 1980 and 1983.2 The total  average  annual commercial/institutional new
boiler sales level estimate is 100,000/3.5 years (or 28,600 annual  replace-
ments) plus 26,000/4 years (or 6,500 boilers per year in new buildings), or a
total of about 35,000 new boilers per year for the 1980-1983 period.
   This represents DOE/EIA's estimate of the 95 percent confidence interval
                                      A-l

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      The 1983 NBECS estimated that there were more than 1 million boilers  in
commercial buildings in 1983.*  Less  than 20  percent  of  the commercial  build-
ings in the U.S. in 1983 had boilers  (reference Table A-l).  Natural gas is
the primary commercial  boiler fuel  type in the North  Central, South and West
Census regions (see Figure A-l).  However, fuel  oil  and  natural gas have equal
market shares in the Northeast Census region.
      Larger commercial buildings  are more likely  to  use a boiler for space
heating in comparison with small buildings.   Only  10  percent of the commercial
buildings less than 5,000 square feet each include boilers.  However, at least
40 percent of the commercial buildings larger than 25,000 square feet include
boilers in 1983.
      The average number of boilers per building is  related to the building
size.  There is an average of three boilers  per building for buildings larger
than 200,000 square feet which use boilers (see Table A-l: 45,000 boilers in
14,000 buildings).  The average number of boilers  per building is less than
1.2 for'buildings smaller than 10,000 square  feet  which  use boilers (see Table
A-l: 450,000 boilers in 385,000 buildings).
      The categories with the largest total number of boilers in 1983 were
mercantile/sales/personal services, offices,  educational  and assembly.   The
area with the largest number of boilers in commercial  buildings in 1983 was
the Northeast Census region (374,000  boilers),  followed  closely by the North
Central region (325,000 boilers).   Table A-l  also  shows  that 39 percent of the
commercial buildings in the Northeast in 1983 used boilers versus 21 percent
for the North Central,  14 percent  for the West and 9  percent for the South.
      Table A-2 summarizes estimates  for 1986.   The total  number of buildings
with boilers in 1986 (627,000) is  smaller than the estimate for 1983 (733,000)
because the 1986 estimates exclude  residential  buildings  and buildings smaller
than 1,000 square feet.
      Table A-2 shows that very few new buildings  use boilers.   Less than 10
percent of the commercial buildings constructed  after 1970 use  boilers.
   For comparison,  PEDCo estimated  that  there were 1,295,130  commercial
   boilers in the U.S.  in 1977.3
                                     A-2

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      In 1986, 11 percent of the commercial buildings were not heated.  Warm
air furnaces were used in three times as many buildings as those with boilers,
Individual space heaters or electric baseboards were used in more commercial
buildings than were boilers.  Other alternatives to boilers were packaged
heating units, heat pumps and district heating.4
                                     A-3

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                      FIGURE A-1
         U.S. Census Regions And Divisions
                          NORTH
                          CENTRAL
4
                       A-4

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                   TABLE A-l.   COMMERCIAL BUILDINGS IN 1983a
Characteristic
 All      Bldgs.
bldgs. w/boilers
(10*)     (103)
                                                        No. of
                                           Bldgs.  buildings (103)
                                         w/boilers    that fire
                                            All     boilers with
                                           bldgs.
           Total
           no. of
           boilers
Nat. Fuel        	
Gas" Oil" Other"  (103)
All Buildings         3,948      733
Square Footage
     <5,000           2,248      227
    5,001-10,000        725      158
   10,001-25,000        567      169
   25,001-50,000        222       90
   50,001-100,000       107       49
  100,001-200,000        50       27
    >200,000             29       14
Principal Activity
  Assembly              457      116
  Educational           177       83
  Food sales/service    380       42
  Health care            61       15
  Lodging               106       31
  Mercantile/personal 1,071      133
  Office                575      128
  Residential*          236       87
  Warehouse             425       53
  Other                 179       25
  Vacant                281       19
                                            19
                                            10
                                            22
                                            30
                                            41
                                            46
                                            54
                                            48
                                            25
                                            47
                                            11
                                            25
                                            29
                                            12
                                            22
                                            37
                                            12
                                            14
                                             7
                           497   216
       48  1,015
                           159
                           105
                           109
                            62
                            32
                            19
                            11
                            85
                            60
                            27
                            10
                            23
                            83
                            88
                            59
                            33
                            16
                            13
50
56
56
22
17
10
 5
34
26
 Q
 6
 8
49
32
26
15
 7
 4
              Qc
              Q
             15
              7
              5
              3
              1
              Q
              8
              Q
              Q
              Q
              Q
              8
              Q
              Q
              Q
              Q
267
183
242
133
 86
 58
 45
146
157
 54
 29
 50
175
161
102
 74
 40
 26
Census Region
Northeast
North Central
South
West

670
1,211
1,493
574

263
251
138
82

39
21
9
14

132
222
79
64

132
23
46
Q

Q
8
17
Q

374
325
213
103
a  Reference 2.

b  The sum of natural gas, fuel oil and other is larger than column 2,
   "buildings with boilers," because some buildings use more than one fuel
   type.

e  Data withheld by DOE/EIA because the relative standard error was greater
   than 50 percent or because fewer than 20 buildings were sampled.

d  Primarily residential, but with some evidence of a commercial establishment
   on-site.
                                      A-5

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                  TABLE  A-2.  COMMERCIAL BUILDINGS  IN  1986"


All buildings
Square footage
1,001-5,000
. 5,001-10,000
10,001-25,000
25,001-50,000
50,001-100,000
100,001-200,000
200,001-500,000
>500,000
Census region
Northeast
Midwest"
South
West
Principal building activity
Assembly
Education
Food sales
Food services
Health care
Lodging
Mercantile and service
Office
Public order and safety
Warehouse
Other
Vacant
All
buildings
(103)
4,154

2,220
931
557
242
123
52
23
6

663
1,096
1,570
825

575
241
102
201
52
137
1,287
614
55
549
103
238
Buildings
with boilers
(103)
627

151
173
133
91
40
22
12
3

253
184
115
75

118
87
Qc
19
12
• 33
170
98
14
33
13
18
Buildings
with boilers
as % of all
buildings
15

7
19
24
38
33
42
52
50

38
17
7
9

21
36
--
9
23
24
13
16
25
6
13
8
a  Reference 4.
b  Same as North Central in Table A-l and Figure A-l.
c  Data withheld because the relative standard error was greater than 50
   percent, or fewer than 20 buildings were sampled.
                                     A-6

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                   TABLE  A-2.   COMMERCIAL BUILDINGS IN 1986*
                                  (continued)
                                                                 Buildings
                                 All            Buildings        with boilers
                               buildings      with  boilers       as % of all
                                 (103)            (10s)             buildings
Year constructed
  1900 or before                  188              62                33
  1901-1920                       255              71                28
  1921-1945  <                     629              120                19
  1946-1960                       878              147                17
  1961-1970                       730              115                16
  1971-1973                       243              22                 9
  1974-1979                       572              41                 7
  1980-1983                       350              28                 8
  1984-1986                       309              20                 6
   Reference 4.
                                      A-7

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                                  REFERENCES
1.    Nonresldential Buildings Energy Consumption  Survey:   Characteristics of
      Commercial  Buildings 1983.   U.S.  Department  of Energy,  Energy Informa-
      tion Administration.  DOE/EIA-0246(83).   July 1985.   p.  36-37.

2.    Reference 1, p.  113.

3.    Devitt, T.  et al.   Population  and Characteristics  of Industrial/Commer-
      cial Boilers in  the U.S.  PEDCo Environmental,  Inc.   Cincinnati, Ohio.
      Prepared for the Industrial  Environmental  Research Laboratory, U.S.
      Environmental Protection Agency.   EPA-600/7-79-178a.  August 1979.

4.    Nonresident!'al Buildings Energy Consumption  Survey:   Characteristics of
  {   Commercial  Buildings 1986.   U.S.  Department  of Energy,  Energy Informa-
      tion Administration.  DOE/EIA-0246(86).   September 1988.   p. 164-166.
                                     A-8

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                                  APPENDIX B.
                       HISTORICAL NEW BOILER SALES DATA

      This appendix presents historical new boiler sales data for units
smaller than 29.3 MW (100 MMBtu/hr).
      There are three major types of boilers:  cast iron, firetube, and water-
tube.  Cast iron boilers produce hot water or low pressure steam.  They are
fired by gas or oil.  Most of these units have firing rates which are smaller
than 59 kW (200,000 Btu/hr).  Table B-l summarizes annual cast iron boiler
sales data (provided to EPA by the Hydronics Institute, Berkeley Heights, New
Jersey).  Annual boiler sales have fluctuated over a wide range, from 155,400
units in 1975 to 347,900 units in 1980.
      Cast iron boilers are used in houses, apartment buildings and com-
mercial/institutional buildings.  It was assumed that all boilers smaller than
59 kW (200,000 Btu/hr) were residential.1  It was further assumed that about
75 percent of the boilers larger than 59 kW (200,000 Btu/hr) were in the
commercial/institutional sector (see Table B-2).
      Firetube boilers produce hot water and low and high pressure steam and
are larger than cast iron boilers.  They are fired primarily by gas or oil;
however, a small number of coal and wood units have been sold.  Firetube
boiler sales data (provided to EPA by the American Boiler Manufacturers
Association, Arlington, Virginia) are summarized in Table B-3.  In the ten-
year period presented in Table B-3, annual sales levels have ranged from a low
of 5,878 units in 1982 to a high of 8,739 units in 1977.
      Watertube boilers are available in many sizes (including units larger
than 29.3 MW or 100 MMBtu/hr) and are fired by many fuel types.  Table B-4
summarizes watertube boiler sales data for boilers smaller than 100,000 pounds
of steam per hour capacity (provided to EPA by the American Boiler Manufac-
turers Association, Arlington, Virginia).  Recent watertube boiler sales
levels are less than half of the 1970's sales levels.
                                      B-l

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                TABLE B-l.  HISTORICAL CAST IRON BOILER SALES3
                             (Thousands of Units)

Year
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984

<59
(<200)
128.5
160.7
174.1
184.5
251.5
297.4
186.8
174.4
169.6
205.7
.....UU fthnu
59-73
(200-250)
11.0
14.5
15.8
16.4
19.6
21.3
15.0
13.5.
12.4
13.5
sand Btu/hr c
73-132
(250-450)
8.0
10.1
11.2
11.1
11.2
19.2
10.4-
10.1
10.0
10.3

132-220
(450-950)
4.2
5.4
5.7
5.1
5.4
5.3
•4.6
3.9
3.9
4.0

>220
(>950)
3.7
4.0
4.3
4.2
4.3
4.7
4.5
4.3
4.0
4.4
Total
155.4
194.6
211.1
221.3
292.0
347.9
- 221.4
206.0
200.0
237.9
8  Hydronics  Institute.   Includes residential, commercial/institutional  and
   industrial boilers.
                                     B-2

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          TABLE B-2.   HISTORICAL RESIDENTIAL/COMMERCIAL/INSTITUTIONAL
                       CAST IRON BOILER SALES ESTIMATES
                             (Thousands of Units)

Residential6
1975 135.2
1976 169.2
< 1977 183.3
1978 193.7
1979 261.6
1980 310.0
1981 195.4
1982 182.3
1983 169.6
1984 213.7
Commercial /Institutional
kW (thousand Btu/hr)
59-220a >220a
(200-950) (>950)
17.4 2.8
22.4 3.0
24.6 3.2
24.4 3.2
27.2 3.2
34.4 3.5
22.6 3.4
20.5 • 3.2
27.4 3.0
20.9 . 3.3
Total
155.4
194.6
211.1
221.3
292.0
347.9
221.4
206.0
200.0
237.9
a  Estimates derived from Table B-l.  Includes 75 percent of the boilers
   larger than 59 kW (200,000 Btu/hr).

b  Estimates for single-family homes and apartment buildings.  Derived from
   data presented in. Table B-l.  (Includes all boilers less than 59 kW
   [200,000 Btu/hr capacity] plus 25 percent of the boilers larger than 59 kW
   [200,000 Btu/hr capacity].)
                                      B-3

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                 TABLE B-3.  HISTORICAL FIRETUBE BOILER SALES9
                              (Number of Units)

Year
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
.........[
<0.3
1,533
2,031
2,062
2,054
2,112
1,902
1,377
1,261
1,470
1,483
toiler Size MW(MMBtu/
0.3-1
d-3)
2,317
2,607
2,798
2,634
2,860
2,600
' 2,408
2,068
2,165
2,298
'h»O_ ...
nr; 	
1-12
(3-40)
3,360
3,620
3,879
3,753
3,729
3,131
2,922
2,549
2,755
2,902
Total
7,210
8,258
8,739
8,441
8,701
7,633
6,707
5,878
6,390
6,683
8  American Boiler Manufacturers  Association.   Includes  residential,  commer-
   cial/institutional and industrial  boilers.   Includes  firebox boilers.
   Includes hot water,  low pressure  steam and  high  pressure  steam boilers.
                                     B-4

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                 TABLE B-4.   HISTORICAL WATERTUBE BOILER SALES3



D,
10-25
Year
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
Units
107
93
110
76
67
57
64
42
37
37
KPPH
2,033
1,793
2,101
1,525
1,264
1,051
1,159
740
. *
663
664
nler Size (KPPH)fc
25-50
Units
150
119
140
138
153
128
98
60
55
56
KPPH
5,691
4,415
5,144
5,001
5,811
4,915
3,660
2,179
2,121
2,259
»

50-100
Units
102
71
100
115
95
76
72
61
47
41
KPPH
7,716
5,331
7,435
8,599
6,595
5,477
5,081
4,467
3,620
3,070
Total
Units
359
283
350
329
315
261
234
163
139
134
KPPH
15,440
11,539
14,680
15,125
13,670
11,443
9,900
7,386
6,404
5,993
a  American Boiler Manufacturers Association; stationary, industrial-type,
   Includes commercial/institutional and industrial boilers smaller than
   100,000 pounds of steam per hour capacity.


b  Thousand pounds of steam per hour capacity.
                                      8-5

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                                      REFERENCES
1.     Devitt,  T.  et al.   Population  and Characteristics  of  Industrial/Com-
      mercial  Boilers  in  the U.S.  PEDCo  Environmental,  Inc.   Cincinnati,
      Ohio.   EPA-600/7-79-178a.   Prepared for the  Industrial  Environmental
      Research Laboratory,  U.S.  Environmental Protection Agency.   August 1979,
                                     B-6

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                                   TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing)
1. REPORT NO.
  EPA-450/3-89-17
                              2.
                                                            3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
  Projected Impacts of Alternative New Source  Performance
  Standards for Small Industrial-Commercial-institutiona
  Fossil  Fuel-Fired Boilers
                                5. REPORT DATE

                                  Mav 1989
                                6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
  Energy and Environmental
  Arlington, VA  22209
Analysis,  Inc.
                               8. PERFORMING ORGANIZATION REPORT NO.
}. PERFORMING ORGANIZATION NAME AND ADDRESS
  Emission Standards Division
  Office  of  Air Quality Planning  and Standards
  U.S.  Environmental Protection Agency
  Research Triangle Park, North Carolina  27711
                                                            10. PROGRAM ELEMENT NO.
                                11. CONTRACT/GRANT NO.
                                  68-02-4384
12. SPONSORING AGENCY NAME AND ADDRESS
  Office  of Air Quality Planning  and Standards
  Office  of Air and Radiation
  U.S. Environmental Protection Agency
  Research  Triangle Park, North Carolina
                                13. TYPE OF REPORT AND PERIOD COVERED
                                 Final	
                                14. SPONSORING AGENCY CODE
                                  EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT
       This  report presents projected national environmental  cost and energy impacts
  of alternative sulfur dioxide  (SOe) and particulate  matter (PM) air emission
  standards  for new small industrial-commercial-institutional  steam generating units
  (small boilers)  firing coal, oil,  and natural gas.   The analysis examines  projected
  impacts in the fifth year'foilowing proposal of the  standards.  The report was
  prepared during  development of proposed new source performance standards  (NSPS)
  for small  boilers.
17.
                                KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
                                               b.lDENTIFIERS/OPEN ENDED TERMS
                                             c.  COS AT I Field/Group
   Air Pollution
   Pollution Control
   Standards of Performance
   Steam Generating Units
                     Industrial Boilers
                     Small  Boilers
                     Air Pollution Control
18. DISTRIBUTION STATEMENT

   Release unlimited
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