EPA430-R-92-003
THE NATIONAL ALLOWANCE DATA BASE
VERSION 2.1
TECHNICAL SUPPORT DOCUMENT
Prepared for:
U.S. Environmental Protection Agency
Office of Atmospheric and Indoor Air Programs
Washington, DC 20460
Prepared by:
Susan S. Rothschild
E.H. Pechan & Associates, Inc.
May 1992
Printed on Recycled Paper
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NOTICES
This document has been reviewed by the Acid Rain Division, Office of Atmospheric and
Indoor Air Programs, U.S. Environmental Protection Agency, and approved for
distribution.
This document is available to the public through the Acid Rain Division, Office of
Atmospheric and Indoor Air Programs, U.S. Environmental Protection Agency.
u
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CONTENTS
Notices ii
Tables and Figure iv
Abbreviations and Symbols v
Acknowledgements vi
1. Introduction 1
2. National Allowance Data Base 8
3. Description of Data Elements ; 7
4. Allowance-related Data Bases 31
References 33
Appendices A-l
A. EPA Regions A-l
B. Multi-header Situations B-l
C. dBASE in Plus NADB Version 2.1 File Structure C-l
D. Calculations for TOTHT, S02, and S02RTE D-l
E. Enforceable S02 Emission Limit Determinations E-l
F. Methodology for Annualizatidn of S02 Emission Limits F-l
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TABLES
Number Page
1 NADB Version 2.1 Variable List 18
2 Sample NADB Version 2.1 Data 19
3 State Summaries for Selected Variables 20
4 EPA Region Summaries for Selected Variables 21
5 Operating Utility Summaries for Selected Variables 22
B-l Hypothetical Multi-header Data B-l
E-l Conversion Factors , E-2
E-2 Averaging Period Codes E-3
F-l S02 Emission Averaging Period Codes
and Anrniali7.flt.inn Factors F-2
FIGURE
Number Page
1 Schematic of Data Relationships 31
IV
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ABBREVIATIONS AND SYMBOLS
ADF - Adjunct Data File
bbl - Barrel
Btu - British thermal unit
CAA - Clean Air Act
GEM - Continuous Emissions Monitoring
cf - Cubic feet
CFR - Code of Federal Regulations
DOE - Department of Energy
EIA — Energy Information Administration
EPA — U.S. Environmental Protection Agency
FERC - Federal Energy Regulatory Commission
FGD — Flue gas desulfurization
FIPS — Federal Information Processing Standard
FPC — Federal Power Commission
FR - Federal Register
GADS - Generating Availability Data System
GWh - Gigawatt hour
IDBS - Integrated Data Base System
kW - Kilowatt
kWh - Kilowatt hour
Ibs — Pounds
MMBtu - Million Btu
MMcf — Million cubic feet
MW — Megawatt
NADB - National Allowance Data Base
NAPAP - National Acid Precipitation Assessment Program
NEDS — National Emissions Data System
NERC - North American Electric Reliability Council
NURF - National Utility Reference File
NSPS — New Source Performance Standards
OAQPS - Office of Air Quality Planning and Standards
ORIS - Office of the Regulatory Information System
PC — Personal (micro)computer
Pechan ~ E.H. Pechan & Associates, Inc.
ppm — Parts per million
PURPA - Public Utilities Regulatory Policy Act
QF — Qualifying facilities
RNSPS — Revised New Source Performance Standards
SAS - Statistical Analysis System
SDF - Supplemental Data File
SIP — State Implementation Plan
S02 — Sulfur dioxide
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ACKNOWLEDGEMENTS
This report would not have been complete without the valuable support provided by
Dianne Crocker, Annita Matusiak, Martha Schultz, and Debbie Wozniak of E.H. Pechan
& Associates, Inc.
VI
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SECTION 1
INTRODUCTION
The U.S. Environmental Protection Agency (EPA) began efforts in 1989 to create a
data base containing the necessary data elements on utility combustion sources to support
a market based system of acid rain controls. The EPA chose the 1985 National Utility
Reference File (NURF) data, augmented by the Department of Energy's (DOE) Energy
Information Administration (EIA) data, as the starting point for the development of the
National Allowance Data Base (NADB).
The NADB Version 2.1 data have undergone several stages of careful review: by the
EPA regions in summer 1990, prior to the release of Version 1.0; by EPA, during fall 1990
and spring 1991, which was followed by the release of Version 2.0; and by the utilities,
during a 45-day public review during summer 1991, which resulted in Version 2.1. The
NADB Version 2.1 will be utilized for calculating S02 emissions allowances (credits), as
delineated by the Acid Deposition Control Title IV of the Clean Air Act (CAA) (PL, 1990).
The NURF is a comprehensive utility-related data file that was developed in response
to the National Acid Precipitation Assessment Program (NAPAP). (NAPAP, through
many of the activities of its Emissions and Controls Task Group, has sponsored work both
in developing estimates of current emissions from the utility industry and in projecting
future emissions.) While NURF did not meet all conceivable NAPAP needs for data on
the utility industry, it provided a framework within which additional data could be
conveniently developed.
The NADB differs from the NURF file in the following ways:
• The source of most data elements in the NURF was the NAPAP
Emissions Inventory (Version 2), whereas the source of the data in
the NADB was most often the EIA.
• In preparing the NADB, the NURF data were extensively reviewed
and data inconsistencies were eliminated through contact with State
and local air agencies and utilities.
• Data elements needed for calculation of allowances under Title IV of
the CAA were expanded in the NADB.
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This document provides a description of how the NADB was developed and what its
key data elements are. Those interested primarily in understanding how the data were
assembled should read Section 2, which describes the development of the NADB. More
detailed information about the data elements is contained in Section 3. Section 4 includes
information about allowance-related data bases. The appendices provide further details.
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SECTION 2
NATIONAL ALLOWANCE DATA BASE
The NADB contains data for utility units, namely "fossil-fuel-fired combustion
devices," as defined in §402 of the CAA. The NADB does not necessarily encompass
all affected units, and all units in the NADB are not necessarily affected units.
Delineation of categories of units and their inclusion status in the NADB follows.
• Traditional utility units are included in the data base. These are
generally boilers attached to generating turbines (generators) which
are owned or operated by an electric utility; this includes existing
units (on-line prior to November 15,1990), new units (on-line after
November 15,1990), and planned units (not on-line as of
December 31,1991).
• Existing new and planned combined cycle units are included.
• New and planned simple combustion turbine units are included.
• New cogenerators are not included unless they are greater than 25
MW and can potentially sell more than one-third of their generation
to a utility.
• Existing simple combustion turbine units (on-line prior to
November 15,1990) are not included.
• Qualifying facilities (QF) under the Public Utilities Regulatory Policy
Act (PURPA) are not included (see Section 4).
• Units owned or operated by nontraditional utilities are not included.
The origin of the NADB is the 1985 NURF. Data were gathered from the sources
listed below:
• The 1985 National Emissions Data System (NEDS) submittals, which
serve as the basis for the 1985 NAPAP Emission Inventory.
• Form EIA-767 (EIA, 1982-1989) and Form EIA-67 (FPC, 1980-1981).
• Form EIA-759 (EIA, 1980-1989).
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• The Federal Energy Regulatory Commission (FERC) Form FERC-423
(FERC, 1985-1989).
• The EIA Integrated Data Base System (IDBS), which consists of Form
EIA-860 (EIA, 1989a) and Form EIA-861 (EIA, 1989b).
For further information on the NURF, see the NURF documentation (EPA, 1989a).
In July 1990, the data for each plant were submitted to the 10 EPA regions for review
of the following key elements: 1985 S02 emissions and emission rate, 1985 total heat
input, and 1985 802 emission limits and associated variables. See Appendix A for a list of
the EPA regions and associated States. Responses from the regions and the utilities were
compiled and acted upon through October 3,1990. The result was the NADB Version 1.0,
a file with 2,456 generating unit records and 36 variables (data elements). It was
disseminated to the public, evoking further responses.
Upon checking the revised data submittals, inconsistencies among specified variables
were discerned. In order to verify these values and eliminate inconsistencies whenever
possible, sources were contacted and asked to clarify and document these data values. A
conceited effort was made to revise the data base and incorporate whatever documented
information could be obtained. In addition, this version took into consideration the
occurrences of multi-header units in which there was not a one-to-one correspondence
between boilers and generators. This was addressed by including a data base record for
each boiler-generator combination within a plant. See Appendix B for an explanation and
example of how data for multi-header units within a plant are handled.
The NADB Version 2.0, produced in June 1991, contained boiler-generator data on
fossil-fuel steam generators of all sizes that were reported to be in operation by 1990, or
planned to soon be operational, in the 48 contiguous States and the District of Columbia.
Also included were reported data for simple combustion turbine and combined cycle units
planned for construction through 1995. The file included 3,732 boiler-generator records
and 36 fields (variables).
The NADB Version 2.0 was offered by EPA for public review (FR, 1991) during a 45-
day comment period commencing July 19,1991. For further information, see the NADB
Version 2.0 Technical Support Document (Pechan, 1991).
After the close of the comment period on September 3,1991, the Data Change Forms
and associated documentation submitted to the EPA Docket were reviewed by EPA (and
EIA when appropriate). Determinations were made regarding acceptance of suggested
changes to the data base. Responses to all the requested changes were submitted to the
Docket by EPA for public review. Changes were made to the data base, resulting in the
NADB Version 2.1. Reported data for simple combustion turbine and combined cycle
units planned for construction through 2006 are also included in this data base. The
NADB Version 2.1 is available in dBASE in Plus PC format, as well as on the IBM
mainframe in Statistical Analysis System (SAS) format.
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Represented in this data base are 329 operating utilities, 958 plants, 2,760
generators, and 2,914 boilers. There are 127 plants that have records with multiple
boiler-generator combinations, 894 plants with one-to-one boiler-generators, and 63 plants
with both. There are 2,298 records of one-to-one boiler-generator correspondence and
1,538 multi-headered records. The NADB Version 2.1 includes 3,836 boiler-generator
records and 38 fields. The data are sorted by State name, plant name, boiler ID, and
generator ID and then assigned a unique sequence number.
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SECTIONS
DESCRIPTION OF DATA ELEMENTS
The NADB Version 2.1 contains 38 data elements that have been grouped into five
categories. The first category — identification or fixed variables — includes variables
numbered 1 through 11. The second category contains elements numbered 12 and 13,
which relate to the calculation of the 1985 actual S02 emission rate, and the third
category includes data elements numbered 14 through 18, which are associated with the
determination of the 1985 allowable S02 emission rate. Elements numbered 19 through
34 fall into the fourth category as EIA-supplied data. The fifth and last category includes
the variables numbered 35 through 38, which are each calculated from other elements in
the data base.
Four tables, placed at the end of this section, further characterize the data: Table 1
lists and summarizes the variables; Table 2 offers a snapshot of the file with some sample
data; and Tables 3, 4, and 5 detail State, regional, and operating utility summaries of
selected variables. The PC version file structure is found in Appendix C.
Descriptions of each of the data elements appear below. Original sources of the data
elements are listed when appropriate. However, for a given record, the actual NADB
Version 2.1 data may have been obtained from a different source as a result of the utility
responses submitted during the comment period or because of a unique plant
configuration or reporting method.
IDENTIFICATION OR FIXED VARIABLES
1. Boiler-generator Sequence Number (SEQNUM) —
The boiler-generator records in this data file, NADB Version 2.1, are sorted by
State name, plant name, boiler ID, and generator ID, and are assigned a unique
sequential number from 1 to 3,836.
2. State Name (STATNAM) -
This field, from Form EIA-860, contains the name of the State where the plant is
located.
3. Plant Name (PNAME)-
The name associated with each plant, as reported on Form EIA-860, is contained
in this field. PNAMEs for planned units with similar names (NA) but different
ORISPLs were modified by appending the ORISPLs.
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4. Boiler Identification Code (BLRDD) -
This right justified character code identifies the boiler. In the majority of cases,
there is a one-to-one correspondence with the generator ID. The source of the
boiler code is Form EIA-767 or a report from the utility Gf there was no Form
EIA-767 filled out). If small, planned, or other units do not have an assigned
boiler code, a default value of two asterisks followed by the GENID is used.
5. Generator Identification Code (GENID) -
This right justified character code identifies the generator or turbine. In the
majority of cases, there is a one-to-one correspondence with the boiler ID. The
source of the generator code is Form EIA-860.
6. Operating Utility Name (UTILNAME) -
There is a utility name for every .utility; this name will be different from that in
the 1985 NURF if the name or operator changed between 1985 and 1989. The
source of the data is Form EIA-861. For the eight utilities with duplicate names,
the State postal code was appended to the utility name to ensure uniqueness.
7. Operating Utility Code (UCODE) -
Each operating utility has a unique utility code, originating from Form EIA-861.
This field, associated with UTILNAME, also reflects 1989 status.
8. EPA Region (EPARGN) -
This field contains the number of the EPA region in which the plant is located.
See Appendix A for a complete list.
9. County Name (CNTYNAME) -
The county name is obtained from Form EIA-860.
10. DOE (ORIS) Plant Code (ORISPL) -
This plant code was originally developed by the Office of the Regulatory
Information System (ORIS), which is a part of the Federal Power Commission
(FPC). It is now used as a unique plant identification code by EIA, assigned by
Form'EIA-861.
11. Phase 1 Allowances (PHASE1AD - '
This field contains the Phase 1 allowances, in tons, that appear in Table A of the
CAA (with multi-header situations taken into account). Note that these values
are not necessarily the final Phase 1 allocations.
1985 ACTUAL SO2 EMISSION RATE-RELATED VARIABLES
12. 1985 Boiler Total Heat Input (TOTHT) -
Total heat input, in 1012 Btu, is the sum of the products of the amount of each
fuel consumed and the associated heat content. These data, from the 1985
NURF, reflect 1985 values only. See Appendix D for detailed calculations.
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13. 1985 Boiler SO2 Emissions (SO2) -
This field contains S02 emissions, in tons, from the 1985 NURF. See Appendix D
for detailed calculations.
1985 ALLOWABLE SO2 EMISSION RATE OJMID-RELATED VARIABLES
14. Boiler SO2 Regulatory Category (SO2CATEG) -
The regulatory category determines the type of emission regulation the unit must
meet. The plant may be regulated under one of the following:
• The State Implementation Plan (SIP), meaning that State or local
regulations are binding (=1);
• The New Source Performance Standards (NSPS), 40 Code bf Federal
Regulations (CFR) Part 60, subpart D (-2);
• The revised NSPS (RNSPS), 40 CFR Part 60, subpart Da (=3);
• The NSPS, 40 CFR Part 60, subpart GG (-4);
• The SIP for the existing gas turbine, combined cycle, with auxiliary
firing (=6); or
• The NSPS, 40 CFR Part 60, subpart GG for the existing gas turbine,
combined cycle, with auxiliary firing (=9).
For units with no information, SO2CATEG=0.
The source of these data is EPA's Office of Air Quality Planning and Standards
(OAQPS) preliminary SIP limit data base. These data were updated based on information
and documentation provided by utilities, as well as Federal, State, and local regulatory
agencies. See Appendix E for further information.
15. Boiler SO2 Scrubber Flag (SCRUBBER) -
This field indicates whether the boiler was scrubbed (=1) or unscrubbed (=0) in
1985. For planned units for which no information was available, SCRUBBER=9.
Units that showed a zero percent S02 removal efficiency were assumed to be
unscrubbed. Scrubber information was obtained from EIA (EIA, 1985) and
updated with post-1985 reports.
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16. 1985 Boiler SO, Emission Limit (FELIM85) -
This field is the federally enforceable S02 emission limit (rounded to four decimal
places) that applied to each boiler in 1985; it has been converted to pounds of S02
per million Btu of heat input Qbs/MMBtu). For units with more than one limit,
the most stringent federally enforceable limit is used. For newer units subject to
NSPS, and those that came on-line after 1985, the federally permitted limit is
used. For units with no federally enforceable limit or units not yet permitted, a
code of 99.9 is used. The source of these data is the OAQPS preliminary SIP
limit data base. These data were updated based on information and
documentation provided by utilities, as well as Federal, State, and local
regulatory agencies. See Appendix E for additional details and conversion
factors.
17. 1985 SO2 Emission Limit Annualization Factor (ANNFACT) -
This field is the annualization factor that, when multiplied by the S02 emissions
limit (FELIM85), produces the annualized SO2 emission limit (ANNLIM85). See
Appendix F for information on methodology.
18. 1985 SO2 Emission Limit Averaging Period (AVGPD) -
This field contains 1 of 17 codes indicating the averaging period or time over
which the emission limit is applied. The source of these data is the OAQPS
preliminary SIP limit data base. These data were updated based on information
and documentation provided by utilities, as well as Federal, State, and local
regulatory agencies. See Appendix E for further information.
EIA-SUPPLIED VARIABLES
19. 1989 Generator Nameplate Capacity (NAMEPCAP) -
This field contains the 1989 nameplate capacity of the generator, in MW and
rounded to two decimal places. Form EIA-860 is the source of this value. For
combined cycle units with auxiliary firing, the gas turbine MW and steam
generating unit MW are combined for the nameplate capacity value.
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20. 1989 Generator Summer Net Dependable Capability (SUMNDCAP) -
This field contains the 1989 summer net dependable capability of the generator,
in MW and rounded to two decimal places. The source of this data element is
Form EIA-860. For combined cycle units with auxiliary firing, the gas turbine
MW and steam generating MW are combined for the summer net dependable
capability value.
Units built to produce both electricity and steam for sale may have more steam
(boiler) capability than electric (generator) capability. For the generating units
that have significant extra boiler capacity and sell steam, individual multipliers
were developed to adjust boiler capability in terms of generator summer
capability (kilowatts-electric).
If a value is not available, the default value is NAMEPCAP. For units coming
on-line after 1990, which may not yet have established a reliable value for
summer net dependable capability, the capability is determined from the
following formula:
SUMNDCAP*NAMEPCAP*factor,
where factor varies (EIA, I990a) based on the type of unit as described below:
Unit Type
Combined Cycle
Combustion Turbine
Steam Turbine
Jet Engine
Internal Combustion
21. Generator Month On-line (GENMNOND -
This data value, from Form EIA-860, is the month portion of the generator
startup date. For existing units, this is the first electricity date. For units that
have been repowered, it is the repowered generator startup date. For planned
units, it is the projected first electricity date.
22. Generator Year On-line (GENYRONL) -
This data value, from Form EIA-860, is the year portion of the generator on-line
date. See GENMNONL for further details.
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23. Boiler Month On-line (BLRMNONL) -
The boiler on-line month is the month portion of the boiler on-line date.
For units from plants of at least 100 MW and with a generator first electricity on-
line date between 1984 and 1989, the boiler on-line date is the generator first
positive generation date. . .
For units with a generator first electricity on-line date prior to 1984 or from
plants with less than 100 MW, the boiler on-line date is the generator first
electricity date.
For units with future on-line dates of 1990 and beyond, the boiler on-line date is
the projected generator first electricity date.
If the boiler on-line dates are different for multiple boilers that are feeding one
generator, the earliest of the boiler on-line dates is used for all of the boilers
feeding that generator.
24. Boiler Year On-line (BLRYRONL) -
The boiler on-line year is the year portion of the boiler on-line date. See
BLRMNONL for further details.
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25. 1985-1987 Boiler-generator Average Total Heat Input, "Baseline"
(BASE8587)-
The average total heat input (also called "baseline"), in 1012 Btu, is the arithmetic
. mean of the calculated heat inputs for all 1985 through 1987 Form EIA-767
reported fuels. The heat input for each year is calculated in the same way as the
1985 total heat input, as shown in Appendix D.
For steam units with no 1985 Form EIA-767 data tin plants under 100 MW), data
are obtained elsewhere. The 1985 fuel use data are apportioned, based on MW,
from Form EIA-759 plant-level data. The associated 1985 heat content is
determined from the average of the 1986 and 1987 Form EIA-767 heat contents.
If no heat content was reported on Form EIA-767 for either 1986 or 1987, the
appropriate average State heat content (computed for each fuel reported by all
plants in that State on Form EIA-767 from 1985 through 1987) is used as the
default value.
For units with OUTAGEHR=26,280 (the entire 1985-1987 baseline time period),
the value for BASE8587 is an alternative representative baseline value assigned
by EPA to correspond to one hour of fuel usage as authorized by §402(4)(a) of the
CAA. In this case, the value for OUTAGEHR is correspondingly changed to
26,279 (to avoid division by zero for the allowance calculations).
For multi-header units, there is a unique value for each boiler-generator,
obtained by apportioning the boiler based Form EIA-767 fuel data to each
generator, depending upon its fractional share of the total generation (or, if that
is not reported, the nameplate capacity) associated with that boiler. When Form
EIA-759 plant-level data are used, the data are first apportioned to each
generator, depending upon its fractional share of the plant's fossil-fuel nameplate
capacity. If there are multiple boilers feeding one generator, the data are divided
equally among all the boilers connected to the multi-headered generator.
For combined cycle units with auxiliary firing, all fuel consumed (including fuel
from auxiliary boilers, duct heat, or scrubber reheat) is included.
For gas turbines, fuel data were obtained from Form EIA-759 whenever possible.
Otherwise, the information was obtained from the utilities.
If there was no fuel consumption for any of the three years, the baseline value is
0. Note that outage hours do not affect the numerical value contained in this
field.
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26. Consecutive Planned and Forced Outage Hours (OUTAGEHR) -
This field represents the number of continuous hours (with a 2,920 hour
minimum) a unit was out of service between 1985 and 1987 due to a planned or
forced outage for nonroutine maintenance. The majority of the data are obtained
from the Generating Availability Data System (GADS) (NERC, 1990) that is
maintained by the North American Electric Reliability Council (NERC).
NERC defines a planned outage as "the removal of a unit from service to perform
work on specific components that is scheduled well in advance and has a
predetermined duration (e.g., annual overhaul, inspections, testing)." It defines a
forced outage as "an unplanned component failure (immediate, delayed,
postponed, startup failure) or other condition that requires the unit be removed
from service immediately or before the next weekend."
If there were individual outages each totaling less than four months (2,920 hours)
during 1985-1987, the value is 0. For utilities that did not report to GADS, unit
outages are allocated if they were well-documented planned or forced outages for
non-routine maintenance reported to EIA.
27. Primary Fuel Indicator (PRIMFUEU -
This field, for those units with fuel use, has a value of 1 if the coal heat input is
greater than 50 percent of the total heat input for the years 1985 through 1987,
and a value of 2 otherwise (for oil/gas units). For those units which did not
report any fuel use on Form EIA-767 for those years (generally, if the steam unit
was on standby or out of service, if the unit was part of a plant under 10 MW in
size, or if it is not a steam plant), the Form EIA-860 generator primary fuel
variable is used to determine the value of PRIMFUEL (the value is set at 1 if the
primary fuel was reported as coal, and is set at 2 otherwise).
28. 1980-1989 Gas Share (GAS8089) -
This value, calculated from 1980 through 1989 Form EIA-767 data for oil/gas
units on-line during the period from 1985 to 1987, is the percentage of gas
consumed by each boiler during this time period. The equation used is:
GAS8089=100*(1980-1989gas heat input)/(1980-1989 total heat input).
For units in plants under 100 MW which did not report fuel use prior to 1986,
Form EIA-767 data from the 1986 to 1989 time period are used. This field is
calculated at the boiler level From Form EIA-767 data for boilers in plants that
were identified, using Form EIA-759, as consuming more than 75 percent gas
between 1980 and 1989. For those boilers in plants not so identified, plant-level
data from Form EIA-759 are used. The value is 0 for coal units (those with a
greater than 50 percent coal share) on-line during the period from 1985 to 1987.
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29. 1989 Generator Heat Rate (HEATRATE) -
The generator heat rate value, in Btu/kWh, is the net full load heat rate reported
for each generator on Form EIA-860. To ensure that estimated heat rates fell.
within a reasonable range of 5,000 to 25,000, contacts were made to confirm
values that were outside that range. The higher values outside the range were
either revised downward or were left alone, since they were reported for very old
and inefficient units. A default value for fossil-fuel steam units is used if values
of 5,000 or less (mostly in retired or planned units) were reported, or if no data
were available. This default value of 10,000 is based on typical heat rates for
new fossil-fuel-fired units that range between 7,260 (efficiency of 47 percent) and
13,648 (efficiency of 25 percent) (EIA, 1990b). For planned simple combustion
turbine and combined cycle units, heat rate defaults of 13,648 and 8,322,
respectively, were used (EIA, 1990b).
V
30. 1985 Generator Generation (GENER) -
Whenever possible, generator generation for 1985, in GWh, is obtained from
Form EIA-767. Generator-level generation data are not available for units in
plants under 100 MW and for units whose utilities did not report individual
generator generation. In these cases, the data are apportioned, by MW, from
Form EIA-759 plant-level data. For combined cycle units with auxiliary firing,
the gas turbine generation and the steam generating unit generation are
combined for the generator generation value.
31. Total Capacity of the Fossil-steam Units of the Operating Utility
(UCAPFSSD-
This field is the sum, in MW, of the Form EIA-860 reported capacity of all the
fossil-fuel steam units operated by the operating utility of the particular unit in
1989. In a few cases, this value is 0 because all of the utility's units retired
before 1989 or had not come on-line by 1989. In addition, if the capacity was less
than 500 kW, this field value was set to 0.
32. Maximum of the Average Heat Inputs for Any Combination of Three
Consecutive Years from 1980-1989 (MXBS8089) -
This heat input data element (also called "maximum baseline"), in 1012 Btu, is the
maximum of the average heat inputs for every combination of three consecutive
years reported on Form EIA-767 between 1980 and 1989. It is calculated
similarly to BASE8587, but only for units subject to §405(0 of the CAA; the value
is 0 otherwise.
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33. Representative Year SO2 Emission Rate (RY_ER) -
The representative year S02 emission rate, in Ibs/MMBtu and rounded to four
decimal places, is nonzero only for those cases in which there is a positive
baseline (either BASE8587 or MXBS8089) value, but no 1985 emission rate.
This field is assigned the 1985 (or 1986 or 1987) S02 emission rate calculated
from EIA data. The EIA emission rate is calculated using Form EIA-767 fuel
quantity and quality data, EPA's AP-42 emission factors (EPA, 1985), and the
S02 control efficiency. See Appendix D for the formula.
If a unit has a positive baseline value, a S02RTE value of 0, all EIA emission
rates calculated to be 0, and is more than 90 percent gas for either the 1980 to
1989 (GAS8089>90) or 1985 time period, then this field is assigned a default
value of .0006, based on the AP-42 factor for natural gas. During the comment
period, a utility may have requested use of an alternate year's rate; if such a rate
is necessary for allowance calculations and was approved, it was included.
34. Municipally Operated Flag (FLAGMUNI) -
If an operating utility is municipally owned, this field has a value of 1, and 0
otherwise. The source of this data element is Form EIA-861.
CALCULATED VARIABLES
35. 1985 Boiler SO2 Emission Rate (SO2RTE) -
The actual. S02 emission rate, in Ibs/MMBtu and rounded to four decimal places,
is calculated from the boiler S02 emissions (tons) in 1985 and the boiler total
heat input of fuels burned (1012 Btu) in 1985. See Appendix D for detailed
calculations. The equation used is:
SO2RTE=(2*SO2)/(1000'TOTHT).
36. 1985 Annualized Boiler SO2 Emission Limit (ANNLEV185) -
The "allowable 1985 SO2 emission rate," in Ibs/MMBtu and rounded to four
decimal places, is defined in the CAA as an annual equivalent S02 emission limit.
ANNLIM85 is calculated using the equation:
ANNLIM85=ANNFACT*FELIM85.
16
-------
37. Generator Heat Input at 60 Percent Capacity (HT60) -
This field, in 1012 Btu, is calculated using the formula as shown, where 5,256 is a
conversion factor (60 percent of 8,760 hrs/yr):
HT60=(HEATRATE*SUMNDCAP*5256)/ltf.
The net summer capability is used because the nameplate capacity for many
units is not a good measure of the maximum MW a generator can produce. Most
planners use a measure of dependable capacity such as net dependable summer
capability.
38. Boiler-generator Share of Generator Heat Input at 60 Percent Capacity
(HT60SHR)-
This field, in 1012 Btu, is calculated from HT60 for multi-header units. For each
generator with multiple boilers, based on BASE8587, HT60 is apportioned among
the boilers. If the BASE8587 value for the multiple boilers are all 0, HT60 is
then shared equally among the boilers. If there is a single boiler associated with
a generator, HT60SHR is equal to HT60.
17
-------
Table 1
NADB Version 2.1 Variable List
Field
Number
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
Variable
Name
SEQNUM
STATNAM
PNAME
BLRID
GENID
UTILNAME
UCODE
EPARGN
CNTYNAME
ORISPL
PHASE1AL
TOTHT
SO2
SO2CATEG
'
SCRUBBER
FELIM85
ANNFACT
AVGPD
NAMEPCAP
SUMNDCAP
GENMNONL
GENYRONL
BLRMNONL
BLRYRONL
BASE8587
OUTAGEHR
PRIMFUEL
GAS8089
HEATRATE
GENER
UCAPFSST
MXBS8089
RY ER
FLAGMUNI
S02RTE
ANNLIM85
HT60
HT60SHR
Description
Boiler-generator sequence number
State name
Plant name
Boiler identification code
Generator identification code
Operating utility name
Operating utility code
EPA region
County name
DOE ORIS plant code
Phase 1 allowances (tons) from Table A of the CAA
1985 boiler total heat input (1012 Btu) from NURF
1985 boiler SO2 emissions (tons) from NURF
Boiler SO2 regulatory category (0=no information, 1=SIP,
2=NSPS D, 3=NSPS Da, 4=NSPS GG, 6=SIP for existing gas
turbine, combined cycle, with auxiliary firing, 9=NSPS GG for
existing gas turbine, combined cycle, with auxiliary firing)
Boiler SO2 scrubber flag (1 =yes, 0=no, 9=no information)
1 985 boiler SO2 emission limit (Ibs/MMBtu)
1985 SO2 emission limit annualization factor
1985 SO2 emission limit averaging period (see Technical Support
Document)
1989 generator nameplate capacity (MW)
1989 generator summer net dependable capability (MW)
Generator month on-line (first electricity)
Generator year on-line (first electricity)
Boiler month on-line
Boiler year on-line-
1985-1987 boiler-generator average total heat input, "baseline"
(1012 Btu) from Form 767
Consecutive planned and forced outage time during 1985-1987
>«= 2,920 hours (hours) from GADS
Primary fuel indicator based on greatest fuel heat share during
1985-1987 (1=coal>50%, 2=oil/gas)
1980-1 989 gas share (%)
1989 generator full load heat rate (Btu/kWh)
1985 generator generation (GWh)
Total capacity of the fossil-steam units of the operating utility (MW)
Maximum of the average heat inputs for any combination of three
consecutive years from 1980-1989 for selected units (1012 Btu)
Representative year SO2 emission rate (Ibs/MMBtu)
Municipally operated flag (1=yes, 0=no)
1985 boiler SO2 emission rate (Ibs/MMBtu)
1985 annualized boiler SO2 emission limit (Ibs/MMBtu)
Generator heat input at 60 percent capacity (1012 Btu)
Boiler-generator share of generator heat input at 60 percent
capacity (1012 Btu)
18
-------
Table 2
Sample NADB Version 2.1 Data
SEONUU STATNAM
1982
1883
1284
1285
128S
1287
1288
1289
1290
1291 •
8EQNUM
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
1982
1983
1284
1286
1286
1287
1288
1289
M 1290
CO 1291
CNTVNAUC
WYANDui it
6EOQWICK
SEDOWICK
6EDGWICK
CHEROKEE
CHEROKEE
CHEROKEE
CHEROKEE
CHEROKEE
GRAHAM
PNAME
OUINOARO
RIPLEV .
RIPLEY
R1PLEY
RIVERTON
RIVERTON
RIVERTON
RIVERTON
RIVERTON
ROSS BEACH
ORISPL
1205
1244
1244
1244
1239
1239
1239
1239
1239
1228
BLRIO
2
-1
-2
-3
LP
LP
39
40
41
1
QENID
8T2
1
2
3
3
4
7
8
8
1
UTTLNAHC
KANSAS CITY COY OF
KANSAS QA8 A ELECTRIC CO.
KANSAS OA81 ELECTRIC CO.
KANSAS OA8 & ELECTRIC CO.
EMPIRE DISTRICT ELECTRIC CO.
EMPIRE DISTRICT ELECTRIC CO.
EMPIRE DISTRICT ELECTRIC CO.
EMPIRE DISTRICT ELECTRIC CO.
EMPIRE DISTRICT ELECTRIC CO.
MIDWEST ENERGY INC.
PHA8E1AL
TOTHT
8O2
8O2CATEQ
8EQNUU
1282
1283
1284
128S
1288
1287
1288
1289
1290
1291
8EQNUM
1282
1283
1284
1285
1288
1287
1288
1289
1290
1291
NAMEPCAP SUMNOCAP
OENMNONL
167.60
23.00
31 JO
33.00
10.00
12.60
37 JO
60.00
28X10
11*)
135.00
26.90
30/40
34.60
lljOO
9.00
38.10
6320
31.50
12.00
11
7
0
OCNEM UCAPFSST
MXBS8089
128.98
0.00
0.00
0.00
0.00
0.00
177.81
288.69
341
0.04
661.00
961.00
961.00
961.00
344.00
344.00
344.00
344.00
344.00
KM
0.000000
0.000000
0.000000
0.000000
0.000000
0.000000
0.000000
0.000000
0.000000
0.000000
4220
0
0
0
0
0
0
0
0
0
1.623439
0.002388
0.003250
0.003426
0.001118
0.001118
2.187371
3.803229
0.082823
0.002100
3254.71
0.00
0.00
0.00
0.00
0.00
4877.00
8035.00
0.00
0.00
OENYMOML
1971
1938
1948
1949
1923
' 1941
1950
1954
1939
1954
«V_EB
0.0000
0.0006
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0006
BLflUNONL
11
7
BLRYROm.
BASESSIT
SCRUBBER •
0
0
0
0 '
0
0
0
0
0
0
OUTAOEHM
UCOOE
9996
10006
10006
10006
6860
6880.
6880
6800
6860
12524
FCUM8S ANNFACT
10000
3.0000
3.0000
3.0000
3.0000
3.0000
3.0000
3.0000
3.0000
99.9000
0.89
1.00
1.00
1.00
1.00
1X0
0.80
0.89
1.00
1X0
PMMFUCL
EPAMQN
7
7
7
7
. 7
7
7
7
7
7
AVOPO
3
0
0
0
0
0
3
3
0
0
HEATRATE
0
FLAOUUMl
1
0
0
0
0
0
0
0
0
0
1971
1938
1948
1949
1923
1923
1950
1954
1939
1954
3.381038
0.000796
0.001083
0.001142
0.000241
0.000302
1.978993
3.368561
0.045659
0.001847
383
0
0
0
0
0
0
0
0
0
1
2
2
2
2
2
1
1
2
2
0.000
81.170
81.170
81.170
3.610
3.610
0.000
0.000
3.610
•4680
9500.00
10000.00
10000.00
88267.00
30000.00
30500.00
12600.00
12700.00
19000.00
12600.00
8O2RTE
4.2728
0.0000
0.0000
0.0000
0.0000
0.0000
4.4592
4.4599
0.0000
0.0000
ANNUM88
HTWSHR
2.6700
3.0000
3.0000
3.0000
3.0000
3.0000
2.6700
2.6700
3.0000
99.9000
6.740620
1 .413864
1.697824
10565672
1.734480
1442772
2.603170
3.651164
3.146716
0.768400
6.740820
1 .413864
1.697824
10.665672
1.734480
1442772
2.603170
3.661164
3.145716
0.786400
-------
st
Table 3
State Summaries for Selected Variables
Blrs S02RTC
S02
TOTHT
GENER Gens NAMEPCAP Units BASE8587
AL
AR
AZ
CA
CO
CT
DC
DE
FL
QA
IA
IL
IN
KS
KY
LA
MA
MD
ME
Ml
MN
MO
MS
MT
NC
NO
NE
NH
NJ
NM
NV
NY
OH
OK
OR
PA
Rl
SC
SO
TN
TX
UT
VA
VT
WA
Wl
WV
WY
|W^"
51
22
47
151
57
28
2
17
167
50
73
114
115
88
72
91
45
52
16
119
77
85
43
9
51
24
36
8
61
47
27
124
171
51
1
91
5
35
13
37
295
19
34
5
22
114
33
19
-<,1BU"-
2.043
0.655
0.681
0.013
0575
0.945
1.097
1550
1.430
2.947
1.747
3.107
3.622
0.991
2.487
0535
1.670
2.058
0.949
1518
1.081
4.016
1506
0.347
1599
1258
0.865
2.797
1.076
0.500
0.585
1217
4.048
0.436
0.804
2.123
0.685
1571
2254
3255
0.493
0515
1552
0247
1.674
2.410
2.481
0.741
; 1.749
72,860.4
112576.4
4.425.1
82,110.4
60,339.0
8205
68.334.0
531260.1
998292.0
1975275
1,044.936.9
1,496251.0
133.480.3
783,331.7
79,232.9
245,541.1
215,678.4
10.261.7
408,838.7
111.952.1
961559.7
102.033.3
16.152.1
343.326.6
144.763.0
47.9152
75.853.0
101.783.7
73,778.7
40.584.6
413,0615
2217,423.1
90.925.1
2.777.1
1.173,882.9
2543.0
155,863.4
33.699.3
802,030.0
559,165.0
23,290.0
1312245
1212.1
68.772.9
379.745.0
951,4645
137,424.0
'"IS.244,170* "'">
222.40
330.13
685.31
285.49
127.70
1.49
10127
743.14
67755
226.07
672.73
826.15
269.49
629.82
473.62
294.13
20957
21.62
62021
207.06
478.79
15622
93.08
490.70
230.09
110.80
54.25
189.15
294.94
138.82
678.71
1.095.70
41750
6.91
1.106.06
6.84
198.45
29.90
492.87
2266.48
148.04
194.12
9.81
82.19
315.12
766.90
370.70
1«£71:3ff
51,443.0
21,2315
31,583.1
65,878.3
26,393.9
12.367.4
90.0
8.102.7
72,600.0
68,9892
20.2182
73,9415
78.969.0
23,338.3
60,127.6
41,573.3
28,5002
20,622.6
2,060.7
60.7392
18,897.1
45.895.9
14,7022
8,524.9
63,3625
21,715.4
10,2822
5.074.1
20,244.4
27,186.8
12,465.1
61.198.3
109.172.3
40,784.3
6412
. 109,332.9
5805
19,9295
2.492.9
50,345.8
213,088.4
13,4815
19.062.6
3265
8.1715
29,446.4
79.302.1
34.590.6
1,809,068,6
51
22
45
126
59
25
2
17
164
49
74
98
100
96
69
90
40
49
14
109
82
81
42
9
47
21
37
7
54
48
27
104
166
49
1
82
6
35
11
37
286
22
33
5
10
107
33
19
^"276$ -'-.
13,404.5
6,609.1
8,498.1
22,5582
6,0682
35822
580.0
2,074.9
30.537.7
13.534.3
6.760.9
21,439.1
23.170.9
8.0105
17,821.0
15.823.8
6282.9
9,519.7
1,069.0
16,346.1
6,828.8
14,028.9
5.804.6
2589.8
12,556.3
4.536.0
3,919.9
1,0482
7,737.9
5,750.8
4,986.4
18.617.7
27.2252
12,852.8
560.5
23.617.0
242.9
6.8382
682.0
10,020.4
67,5845
5,354.1
7,457.8
84.0
1.6782
10,1292
14.9585
5594.7
53
22
47
202
104
37
2
23
182
50'
110
207
153
115
75
139
63
57
16
198
127
109
57
9
51
27
46
8
70
56
27
182
266
53
1
123
9
35
19
37
328
26
34
5
53
166
33
19
383$ '
517.28
233.61
292.76
598.19
285.18
12951
2.45
10355
848.41
66828
230.83
673.03
829.82
266.95
654.94
433.61
30822
23125
25.32
66253
20851
47958
156.75
12155
48251
231.95
109.64
5428
17754
28423
164.96
67151
1,134.41
408.44
250
1,102.50
8.54
208.66
22.23
497.65
223424
187.95
217.06
2.61
78.85
328.75
763.07
352.78
•^•iwar
20
-------
Table 4
EPA Region Summaries for Selected Variables
Rgn Blrs S02RTE
S02
TOTHT
QENER Gens MAMEPCAP Units BASE8587
1
2
3
4
5
6
7
8
9
10
107
185
229
506
710
506
282
141
225
23
1.538
1.186
2.136
2.173
3.029
0.477
2.470
0.756
0.273
1.606
395.549.9
514,845.0
2,541,404.6
4.250,604.8
5,659,146.8
875.962.0
1,340,282.8
437,438.7
157,386.2
71.550.1
514.35
867.87
2,379.42
3.912.00
3,736.97
3.674.95
1,085.15
1,157.30
1.154.27
89.09
48,909.4
81,442.7
236,513.0
401,500.3
371,165.4
343.864.6
99.734.6
107,199.4
109.926.4
8.812.7
97
158
216
494
662
495
288
141
198
11
12,109.3
26,355.6
68.207.7
110517.0
105,139.4
108,621.1
32,720.2
25,124.8
36.042.8-
2,238.7
143
252
272
540
1117
598
380
204
276
54
528.3
849.1
2,419.9
4.034.3
3337.3
35942
1,086.8
1,201.5
1,055.9
81.2
•fis.'Sttitf wr* iTltsmsr'"'''^
21
-------
Table 5
Operating Utility Summaries for Selected Variables
Operating Utility
Blrs
SO2RTE
SO2
TOTHT
GENER Gent NAMEPCAP Units BASE8587
ALABAMA ELECTRIC COOP INC
ALABAMA POWER CO
ALEXANDRIA CITY OF
ALLIANCE CITY OF
AMERICAN MUN POWER-OHIO INC
AMES CITY OF
APPALACHIAN POWER CO
ARIZONA ELECTRIC PWR COOP INC
ARIZONA PUBLIC SERVICE CO
ARKANSAS ELECTRIC COOP CORP
ARKANSAS POWER & LIGHT CO
ASSOCIATED ELECTRIC COOP INC
ATLANTIC CITY ELECTRIC CO
ATLANTIC CfTY OF
AUSTIN CITY OF (MN)
AUSTIN CITY OF (TX)
BALTIMORE GAS & ELECTRIC CO
BANGOR HYDRO-ELECTRIC CO
BASIN ELECTRIC POWER COOP
BIO RIVERS ELECTRIC CORP
BLACK HILLS CORP
BLUE EARTH CfTY OF
BOSTON EDISON CO
BRAZOS ELECTRIC POWER COOP INC
BREESE CITY OF
BROWNSVILLE PUBLIC UTILS BOARD
BRYAN CITY OF
BURBANK CITY OF
BURLINGTON CITY OF
CAJUN ELECTRIC POWER COOP INC
CAMBRIDGE ELECTRIC LIGHT CO
CANAL ELECTRIC CO
CARDINAL OPERATING COMPANY
CARLYLE CITY OF
CAROLINA POWER & LIGHT CO
CEDAR FALLS CITY OF
CENTEL CORP
CENTRAL ELECTRIC POWER COOP
13
25
4
1
4
3
12
3
22
4
18
5
11
2
2
11
20
3
9
9
10
1
6
11
2
2
5
4
4
5
7
2
3
1
24
2
9
2
. 1.125
1.933
0.001
0.000
17.720
1.254
1.129
0.658
0.514
0.000
0.608
4.730
2.490
0.000
2.679
0.001
1.540
2.283
0.637
2.262
1.012
0.000
0.817
0.000
0.000
0.000
0.021
0.008
0.247
0.936
0.239
2.345
3.789
0.000
1.321
3.657
0.382
5.928
14,205
354,319
1
0
22,283
1,458
163,634
5,599
47,605
0
58,375
258,941
43,151
0
1,078
7
49,584
603
52,886
126,000
4.723
0
30,634
3
0
0
39
7
1,212
41,465
459
69,049
159,563
0
162,756
129
1,486
8,373
25
367
2
0
3
2
290
17
185
0
192
109
35
0
1
24
64
1
166
111
9
0
75
18
0
0
4
2
10
89
4
59
84
0
246
0
8
3
2,340
38,362
142
0
0
217
30,865
1.581
17,567
23
18,388
10,654
2,856
0
60
2.184
6,263
39
15.541
10,418
574
0
7,280
1,671
0
16
314
150
327
7,290
57
5,923
8.752
0
36,888
5
528
281
13
25
4
1
4
3
11
3
22
4
18
5
9
2
5
11
20
3
9
9
10
1
6
12
2
2
5
4
4
5
8
2
3
' 1
21
2
9
2
1.242
8,844
175
8
200
111
5.722
474
4.734
415
5,666
2,335
784
9
59
1,534
4,059
58
3,286
2,004
155
2
1.804
1,261
3
47
221
167
80
1,909
86
1,072
1,880
3
5,545
52
356
59
15
25
4
1
8
3
12
3
22
4
18
5
11
2
5
11
20
3
9
9
16
1
6
12
2
2
5
4
4
5
21
2
3
1
24
2
9
• 2
26
352
2
0
5
3
275
13
194
0
205
105
36
0
1
22
77
1
180
108
9
0
64
16
0
1
4
3
3
70
4
58
90
0
241
0
7
2
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
Operating Utility
Blrs SO2RTE
SO2
TOTHT
GENER Qen» NAMEPCAP Units BASE8587
CENTRAL HUDSON GAS & ELEC CORP
CENTRAL ILLINOIS LIGHT CO
CENTRAL ILLINOIS PUB SERV CO
CENTRAL IOWA POWER COOP
CENTRAL LOUISIANA ELEC CO INC
CENTRAL MAINE POWER CO
CENTRAL NEBRASKA PUB P&l DIST
CENTRAL OPERATING CO
CENTRAL POWER & LIGHT CO
CENTRAL VERMONT PUB SERV CORP
CENTURY POWER CORP
CHANUTE CITY OF
CHILUCOTHE MUNICIPAL UTtLS
CINCINNATI GAS & ELECTRIC CO
CLARKSDALE CITY OF
CLAY CENTER CITY OF
CLEVELAND CITY OF
CLEVELAND ELECTRIC ILLUM CO
COFFEYVILLE CITY OF
COLDWATER BOARD OF PUBLIC UTIL
COLORADO SPRINGS CITY OF
COLORADO-UTE ELECTRIC ASSN INC
COLUMBIA CITY OF
COLUMBUS CITY OF
COLUMBUS SOUTHERN POWER CO
COMMONWEALTH EDISON CO
COMMONWEALTH EDISON CO IN INC
COMMONWEALTH ELECTRIC CO
CONNECTICUT LIGHT & POWER CO
CONSOLIDATED EDISON CO-NY INC
CONSUMERS POWER CO
COOP POWER ASSN
CORN BELT POWER COOP
CRAWFORDSVILLE ELEC LGT&PWR CO
CRISP COUNTY POWER COMM
CULPEPER TOWN OF
DAIRYLAND POWER COOP
6
10
15
2
9
11
1
5
24
1
3
5
2
25
4
3
4
19
3
2
11
6
3
9
11
26
2
3
19
39
17
2
5
2
1
1
13
1.471
1.278
4.102
4.900
0.459
0.915
0.007
1.463
0.146
0.000
0.704
0.000
6.497
2.517
0.000
0.000
0.000
4.461
0.001
1.285
0.636
0.456
6.310
1.228
3.444
2.193
0.858
0.327
0.859
0.157
1.757
1.099
5.043
4.820
1.272
0.000
2.904
52,498
32,809
232,344
7.803
17.063
9.647
1
29,245
12,240
0
7,149
0
1,323
177,258
0
0
0
312.472
0
333
9,089
23,419
1,952
1.784
169,299
273,639
9,651
250
31.075
13,298
142,740
38,294
498
1,970
285
0
57,917
71
51
113
3
74
21
0
40
168
0
20
0
0
141
0
0
0
140
0
1
29
103
1
3
98
250
23
2
72
169
162
70
0
1
0
0
40
7,070
5.047
11.042
261
7.096
2,022
22
4,182
16,547
0
2,040
1
17
14.314
1
16
0
13,536
34 •
20
2,704
9,587
98
116
9,432
32,381
2,262
108
6,804
12,020
16,932
6.020
12
46
5
0
3.733
6
9
12
2
9
9
1
5
24
1
3
6
2
24
4
3
4
19
7
3
13
9
3
5
11
22
2
2
16
29
17
2
' 5
2
1
1
13
1,774
1,526
3.154
63
2,586
993
109
1.108
4,521
4
1,191
19
11
5,469
24
10
160
3,296
80
11
627
1,918
74
111
2.513
10,479
614
63
2,172
5,949
4,430
1,012
97
24
13
2
976
6
10
15
2
9
11
1
5
24
1
3
11
2
25
6
. 3
10
31
13
3
17
9
9
24
11
26
2
3
22
69
23
2
5
2
1
1
21
72
52
106
3
87
25
0
38
160
0
18
0
0
139
0
0
0
141
0
0
30
103
1
4
87
257
21
2
72
161
175
65
0
1
0
0
40
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
Operating Utility
Blrs
SO2RTE
S02
TOTHT
GENER Gent NAMEPCAP Units BASE8S87
DAYTON POWER & LIGHT CO
DELMARVA POWER & LIGHT CO
DENISON CITY OF
DENTON CITY OF
DESERET GENERATION & TRAN COOP
DETROIT CITY OF
DETROIT EDISON CO
DOVER CITY OF (DE)
DOVER CITY OF (OH)
DUKE POWER CO
DUOUESNE LIGHT CO
EAST KENTUCKY POWER COOP INC
EASTON UTILITIES COMM
EL PASO ELECTRIC CO
ELECTRIC ENERGY INC
EMPIRE DISTRICT ELECTRIC CO
FAIRBURY CITY OF
FAIRFIELD CITY OF
FAIRMONT PUBLIC UTILITIES COMM
FARMINGTON CITY OF
FLORIDA POWER ft LIGHT CO
FLORIDA POWER CORP
FORT PIERCE UTILITIES AUTH
FREMONT CITY OF
GAINESVILLE REGIONAL UTILITIES
GARLAND CITY OF
GEORGIA POWER CO
GLENDALE CITY OF
GRAETTINGER CITY OF
GRAND HAVEN CITY OF
GRAND ISLAND CITY OF
GRAND RIVER DAM AUTHORITY
GREENVILLE CITY OF
GREENWOOD UTILITIES COMM
GULF POWER CO
GULF STATES UTILITIES CO
HAGERSTOWN CITY OF
17
15
1
5
2
3
52
4 •
5
31
11
9
3
12
6
9
1
1
4
4
38
27
3
3
7
8
41
3
1
3
4
2
3
6
11
34
7
2.076
1.334
0.000
0.040
0.000
0.382
1.176
2.013
3.584
1.486
1.587
2.213
0.000
0.000
3.323
8.424
0.000
0.000
1.819
0.000
0.371
1.296
0.021
0.882
0.980
0.010
2.999
0.042
0.000
0.320
0.975
0.693
0.533
1.816
3.589
0.189
0.000
167,147
66,456
0
34
0
606
221,496
3.748
3,105
190.216
45.223
73,274
0
2
108.384
81.681
0
0
315
0
34.580
112.412
17
1.310
9.427
38
980.798
25
0
600
1,521
11.732
14
1.078
129.375
19,680
0
161
100
0
2
0
3
377
4
2
256
57
66
0
14
65
19
0
0
0
0
186
174
2
3
19
7
654
1
0
4
3
34
0
1
72
209
0
16,208
8,014
0
119
59
243
37,038
263
56
27,627
5,275
6,357
0
1,320
6,250
1,729
0
0
2
15
18.167
17.739
115
254
1,757
709
66.838
126
0
340
260
3.123
29
65
6.901
18,703
0
IB
15
1
5
2
3
40
4
6
30
9
9
3
12
6
11
3 •
1
3
4
36
27
3
3
7
8
40
3
1
3
4
2
' 3
6
11
33
4
3,970
2,196
3
174
800
154
9,971
191
71
7,573
1,487
1,960
28
1,076
1.100
581
19
6
23
32
11.366
5.409
106
130
490
442
12.927
108
1
80
208
1.010
99
54
1.667
7.092
35
33
21
1
5
2
3
107
4
9
31
21
9
3
12
6
11
3
1
12
6
38
27
3
3
7
8
41
3
1
3
4
2
3
18
11
82
12
182
103
0
1
12
3
406
4
1
253
56
69
0
16
55
18
0
0
0
0
240
191
1
3
18
7
645
2
0
3
3
40
1
1
78
204
0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
Operating Utility
Blra SO2RTE
SO2
TOTHT
GENER Oena NAMEPCAP UnHa BASE8587
HAMILTON CITY O^
HASTINGS CITY OF
HENDERSON CITY UTILITY COMM
NIBBING PUBLIC UTILITIES COMM
HOLLAND CITY OF
HOLYOKE GAS & ELECTRIC CO
HOLYOKE WATER POWER CO
HOMESTEAD CITY OF
HOOSIER ENERGY R E C INC
HOUSTON LIGHTING & POWER CO
ILLINOIS POWER CO
IMPERIAL IRRIGATION DISTRICT
INDEPENDENCE CITY OF
INDIANA MICHIGAN POWER CO
INDIANA-KENTUCKY ELECTRIC CORP
INDIANAPOLIS POWER & LIGHT CO
INTERSTATE POWER CO
IOLA CITY OF
IOWA ELECTRIC LIGHT & POWER CO
IOWA POWER INC
IOWA PUBLIC SERVICE CO
IOWA SOUTHERN UTILITIES CO
IOWA-ILLINOIS GAS&ELECTRIC CO
JACKSONVILLE ELECTRIC AUTH
JAMESTOWN CITY OF
JASPER CITY OF
JERSEY CENTRAL POWER&LIGHT CO
KANSAS CITY CITY OF
KANSAS CITY POWER & LIGHT CO
KANSAS GAS & ELECTRIC CO
KANSAS POWER & LIGHT CO
KENTUCKY POWER CO
KENTUCKY UTILITIES CO
KEY WEST CITY OF
KINGMAN CITY OF
KISSIMMEE UTILITY AUTHORITY
LAFAYETTE CITY OF
6
3
2
3
5
4
1
1
4
44
21
4
5
7
6
37
14
3
14
6
5
5
7
13
4
1
23
6
19
12
15
2
21
8
1
1
5
1.191
0.909
4.660
1.235
1.271
0.584
2.142
0.000
1.900
0.274
4.436
0.021
4.562
2.971
5.609
3.078
3.241
0.000
3.898
0.999
0.944
1.791
1.360
1.439
2.203
5.068
0.075
2.190
2.441
0.001
0.707
1.952
2.936
2.407
0.000
0.000
0.000
1,719
1,052
1,589
912
2,942
234
9,805
0
57,071
65,769
358,627
44
14,839
156,911
268,862
178,887
46,860
0
28,474
20,058
29,275
35,285
16,389
17,776
2,920
3,514
897
28,397
172,021
3
53,612
41.549
171,706
5,892
0
0
0
3
2
1
1
5
1
9
0
60
480
162
4
7
106
96
116
29
0
15
40
62
39
24
25
3
1
24
26
141
11
152
43
117
5
0
0
7
232
157
37
14
339
0
1,037
0
6,544
45,860
16,563
333
306
10,479
9,777
10,158
2,511
8
911
3.848
5,903
3,654
1,888
2,257
95
82
4,800
2,137
13,075
994
13,353
4,278
10,802
350
0
0
335
6
3
2
3
5
3
1
1
4
43
18
4
5
7
6
25
14
3
18
6
5
5
5
13
2
1
19
6
19
12
18
2
18
8
1
1
5
128
115
44
31
145
25
136
6
1.313
14,781
3,749
189
148
4,196
1,304
3,544
844
11
521
1,091
1,740
1,060
950
3,123
58
15
2,383
661
4,940
1,068
3,460
1.097
3,872
116
6
37
379
8
3
2
9
5
12
1
1
4
68
59
4
5
7
6
61
14
3
42
8
S
6
10
13
8
1
31
6
19
12
18
2
24
8
1
1
. 5
3
2
1
1
4
0
11
0
56
475
169
4
5
103
98
134
29
0
16
40
54
42
33
42
3
1
21
25
142
8
152
48
125
5
0
0
6
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
Operating Utility
Bin SO2RTE
SO2
TOTHT
GENER Gent NAMEPCAP Units BASE8587
LAKE WORTH CITY OF
LAKELAND CITY OF
LAMAR CITY OF
LANSING BOARD OF WATER & LIGHT
LARNED CITY OF
LAWRENCE PARK HEAT LQT&PWR CO
LEA COUNTY ELECTRIC COOP INC
UTCHFIELD PUBLIC UTILITY COMM
LOOANSPORT CITY OF
LONG ISLAND LIGHTING CO
LOS ANGELES CITY OF
LOUISIANA POWER & LIGHT CO
LOUISVILLE GAS & ELECTRIC CO
LOWER COLORADO RIVER AUTHORITY
LUBBOCK CITY OF
LUVERNE CITY OF
MADISON GAS & ELECTRIC CO
MAINE PUBLIC SERVICE CO
MANITOWOC CITY OF
MARQUETTE CITY OF
MARSHALL CITY OF
MARSHRELD CITY OF
MCPHERSON CITY OF
MEDINA ELECTRIC COOP INC
MENASHA CITY OF
METROPOLITAN EDISON CO
MICHIGAN SOUTH CENTRAL PWR AGY
MIDWEST ENERGY INC
MINDEN CITY OF
MINNESOTA POWER & LIGHT CO
MINNKOTA POWER COOP INC
MISSISSIPPI POWER & LIGHT CO
MISSISSIPPI POWER CO
MONONGAHELA POWER CO
MONTANA POWER CO
MONTANA-DAKOTA UTILITIES CO
MONTAUP ELECTRIC CO
4
9
1
10
3
1
2
1
2
15
23
16
13
7
7
1
11
2
7
3
3
5
2
3
4
5
1
6
2
10
4
10
12
14
6
12
8
0.024
0.448
0.000
1.167
0.000
0.000
0.000
0.000
1.847
1.739
0.013
0.013
3.092
0.615
0.000
0.000
1.777
2.726
2.293
0.575
5.965
3.190
0.000
0.000
2.051
2.532
0.368
0.000
0.028
0.818
1.292
0.024
2.189
2.907
0.328
1.300
1.670
12
6,235
• 0
14,361
0
0
0
0
1,487
108,906
440
979
130,182
32.637
0
0
1,826
11
2,393
929
3,360
1,959
0
0
703
28,306
513
0
13
22,415
29,654
588
89,757
398,008
14,870
23,128
11,812
1
28
1
25
0
0
0
0
2
125
66
151
84
106
7
0
2
0
2
3
1
1
0
1
1
22
3
0
1
55
46
50
82
274
91
36
14
76
2,616
4
2,232
8
0
0
0
117
12,075
6,199
14,041
8,001
10,492
566
0
168
0
7
234
94
64
0
77
44
2,151
219
0
1
5,478
4,021
4,479
7,968
27,380
8,341
3,018
1,313
4
9
3
11
3
1
2
1
2
15
23
16
13
7
7
1
8
2
6
3
3
5
4
3
4
5
1
6
2
10
4
9
'12
14
8
10
6
74
842
33
615
13
1
49
3
43
2,774
5,388
4,697
3,450
2,775
172
3
320
19
139
77
27
54
49
66
30
652
55
62
25
1,311
751
2,733
2,160
5,173
2,533
623
300
4
9
3
19
5
1
2
1
2
15
23
16
13
7
7
1
23
2
25
3
5
5
4
3
4
5
1
9
2
10
4
10
12
14
6
16
9
1
22
1
27
0
0
0
0
1
128
100
134
87
103
7
0
2
0
2
3
1
1
0
1
1
24
3
0
0
54
46
42
90
279
119
33
13
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
Operating Utility
Bin SO2RTE
SO2
TOTHT
OENER Gem NAMEPCAP Units BASE8587
MOORHEAD CITY OF
MORGAN CITY CITY OF
MT PLEASANT CITY OF
MULVANE CITY OF
MUSCATINE CITY OF
MUSCODA CITY OF
NATCHITOCHES CITY OF
NEBRASKA PUBUC POWER DISTRICT
NEVADA POWER CO
NEW ENGLAND POWER CO
NEW ORLEANS PUBLIC SERVICE INC
NEW ULM PUBLIC UTILITIES COMM
NEW YORK STATE ELEC & GAS CORP
NIAGARA MOHAWK POWER CORP
NORTHERN INDIANA PUB SERV CO
NORTHERN STATES POWER CO
NORTHWESTERN PUBUC SERVICE CO
OHIO EDISON CO
OHIO POWER CO
OHIO VALLEY ELECTRIC CORP
OKLAHOMA GAS & ELECTRIC CO
OMAHA PUBLIC POWER DISTRICT
OPELOUSASCITYOF
ORANGE & ROCKLAND UTILS INC
ORLANDO UTILITIES COMM
ORRVILLE CITY OF
OTTAWA CITY OF
OTTER TAIL POWER CO
OWATONNA CITY OF
OWENSBORO CITY OF
PACIRC GAS & ELECTRIC CO
PACIFICORP
PAINESVILLE CITY OF •
PASADENA CITY OF
PEABODY CITY OF
PELLA CITY OF
PENNSYLVANIA ELECTRIC CO
1
4
2
2
5
1
3
13
18
13
5
3
20
20
14
34
3
27
13
5
22
10
2
7
7
4
1
4
2
2
55
27
3
7
1
4
23
1.774
0.000
1.867
0.000
1.820
0.000
0.000
0.757
0.267
1.884
0.004
2.216
1.689
1.979
2.535
1.068
0.000
3.508
5.666
5.758
0.381
1.016
0.000
0.143
0.243
5.603
0.000
2.365
0.000
5.212
0.007
0.880
3.728
0.007
0.000
3.645
2.656
1
0
7
0
10,703
0
0
22.957
6.530
120,415
58
1,464
81 .247
117,502
119,200
73,345
0
326,619
877,044
222,543
42.947
21,074
0
3,723
1,700
8,850
0
36,387
0
36,931
968
217,498
2,953
12
0
2,570
505,453
0
0
0
0
12
0
0
61
49
128
30
1
96
119
94
137
0
186
310
77
226
41
0
52
14
3
0
31
0
14
281
494
2
4
0
1
381
20
29
0
0
1.121
0
0
5.785
4,559
12.523
2,703
67
9,999
11.042
8.578
12,419
0
18,222
32,637
7,924
20,964
3,805
0
4,810
1.337
55
0
2,648
1
1,393
27,456
46,016
99
320
0
26
38,637
1
4
2
. 2
5
1
3
12
18
14
5
2
13
20
13
32
3
24
13
5
22
10
2
7
7 '
5
1
4
2
2
37
28
' 5
5
1
4
21
25
70
11
1
296
2
43
1,775
2.376
2,648
1.092
21
1,469
3.576
3.768
5.489
52
3,604
6,545
1,086
6,593
1.556
39
1.737
1,718
85
4
593
26
416
7,495
8.345
80
215
36
44
6,835
1
4
4
2
5
1
3
21
18
17
5
3
20
20
17
56
3
37
. 13
5
22
10
2
7
7
. 11
1
. 4
2
2
85
28
5
7
1
8
29
0
0
0
0
11
0
0
57
41
136
29
1
89
122
99
142
0
187
320
75
219
44
0
55
20
2
0
22
0
16
235
454
2
4
0
1
387
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
Operating Utility
Blrs SO2RTE
SO2
TOTHT
GENER Gens NAMEPCAP Unlit BASE8587
PENNSYLVANIA POWER & LIGHT CO
PENNSYLVANIA POWER CO
PERU CITY OF (IL)
PERU CITY OF ON)
PHILADELPHIA ELECTRIC CO
PIQUA CITY OF
PLAINS ELEC GEN&TRANS COOP INC
PLAOUEMINE CITY OF
PLATTE RIVER POWER AUTHORITY
PONCA CITY CITY OF
PORTLAND GENERAL ELECTRIC CO
POTOMAC EDISON CO
POTOMAC ELECTRIC POWER CO
POWER AUTHORITY OF STATE OF NY
PRATT CITY OF
PROVO CITY CORP
PUBLIC SERV COMM OF YAZOO CfTY
PUBLIC SERVICE CO OF COLORADO
PUBLIC SERVICE CO OF IN INC
PUBLIC SERVICE CO OF NH
PUBLIC SERVICE CO OF NM
PUBLIC SERVICE CO OF OKLAHOMA
PUBLIC SERVICE ELECTRICAGAS CO
PUOET SOUND POWER & LIGHT CO
RATON PUBLIC SERVICE CO
REEDY CREEK IMPROVEMENT DIST
RICHLAND CENTER CITY OF
RICHMOND CITY OF
ROCHELLE MUNICIPAL UTILITIES
ROCHESTER OAS & ELECTRIC CORP
ROCHESTER PUBLIC UTILITIES
RUSSELL CITY OF
RUSTONCITYOF
SALT RIVER PROJ AG 1 & P DIST
SAN ANTONIO CITY OF
SAN DIEGO OAS & ELECTRIC CO
SAN MIGUEL ELECTRIC COOP INC
16
8
1
2
15
3
5
2
1
2
1
2
25
1
3
2
2
30
29
8
13
16
19
3
2
1
4
2
2
11
- 4
2
3
18
25
18
2
2.269
0.718
0.000
5.790
0.330
3.016
0.275
0.000
0.136
0.000
0.804
1.448
2.144
0.055
0.000
0.812
0.000
0.733
4.167
2.797
0.609
0.399
0.870
0.000
1.560
0.000
3.658
4.064
0.000
3.233
2.515
0.000
0.000
0.751
0.471
0.065
1.400
328,875
58,453
0
1.727
9.710
5.729
2.353
0
1,399
0
2.777
3,273
177.943
1 633
0
104
0
46,649
557.014
75.853
42,375
27.094
55.602
0
399
0
1.034
10,991
0
32.334
4.936
0
0
80,664
26,455
1,418
20,325
290
163
0
1
59
3
17
0
21
0
7
6
166
23
0
0
0
127
267
54
139
136
128
0
1
0
1
5
0
20
4
0
1
215
112
44
29
29,122
15,781
0
39
4,999
99
1.751
0
1.925
0
641
407
16.260
2.098
8
2
' 0
11.765
26,403
5,074
12,294
14,688
12,410
0
25
0
26
473
0
1,990
343
0
41
20,692
10,630
3,944
2,534
15
8
1
2
12
3
5
2
1
2
1
2
25
1
3
4
2
25
27
7
13
14
17
2
3
1
4
2
1
10
4
2
' 3
14
25
14
2
5,699
3,166
8
32
2,944
40
511
44
285
68
561
110
6,071
883
22
14
18
3,122
6,869
1,048
2,055
4,380
4,400
88
11
9
14
93
12
398
99
7
81
3,760
5,034
1,946
860
27
10
1
2
15
5
5
2
1
2
1
2
25
1
3
8
2
66
40
8
13
18
19
6
3
1
4
2
2
35
4
2
3
16
25
16
2
289
162
0
1
53
2
14
0
20
0
2
5
171
24
1
0
0
127
255
54
119
129
118
0
1
0
0
5
1
17
4
0
1
195
113
45
28
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
Operating Utility
Blrs SO2RTE
SO2
TOTHT
QENER Gent NAMEPCAP Units BASE8587
SAVANNAH ELECTRIC & POWER CO
SEATTLE CITY OF
SEBRINQ UTILITIES COMM
SEMINOLE ELECTRIC COOP INC
SHELBY CITY OF
SIERRA PACIFIC POWER CO
SIKESTON CITY OF
SLEEPY EYE PUBLIC UTILITY COMM
SOUTH CAROLINA ELECTRIC&QAS CO
SOUTH CAROLINA OENERTO CO INC
SOUTH CAROLINA PUB SERV AUTH
SOUTH MISSISSIPPI EL PWR ASSN
SOUTH TEXAS ELECTRIC COOP INC
SOUTHERN CALIFORNIA EDISON CO
SOUTHERN ILLINOIS POWER COOP
SOUTHERN INDIANA GAS & ELEC CO
SOUTHWESTERN ELECTRIC POWER CO
SOUTHWESTERN PUBLIC SERVICE CO
SOYLAND POWER COOP INC
SPRINGFIELD CITY OF (ID
SPRINGFIELD CITY OF (MO)
SPRINGFIELD PUBLIC UTILS COMM
ST JOSEPH LIGHT & POWER CO
ST MARYS CITY OF
STILLWATER UTILITIES AUTHORITY
SUN COMPANY
SUNFLOWER ELECTRIC POWER CORP
SUPERIOR WATER LIGHT&POWER CO
TACOMA CITY OF
TALLAHASSEE CITY OF
TAMPA ELECTRIC CO
TAUNTON CITY OF
TENNESSEE VALLEY AUTHORITY
TERREBONNE PARISH CONSOL GOVT
TEXAS MUNICIPAL POWER AGENCY
TEXAS UTILITIES GENERATING CO
TEXAS-NEW MEXICO POWER CO
8
14
1
2
4
7
2
2
18
1
12
. 9
1
43
4
7
19
18
1
9
8
2
12
3
2
1
5
2
2
9
20
2
63
3
3
63
7
1.501
0.000
0.000
0.506
4.950
0.582
1.070
1.503
2.095
1.350
1.177
0.910
0.000
0.152
2.144
4.717
0.799
0.528
5.586
2.554
3.160
1.725
5.126
5.579
0.000
0.000
0.271
0.000
0.000
0.118
2.714
1.251
2.964
0.000
0.906
0.681
0.000
17,209
0
0
14,819
3,063
9,617
3,338
171
77,789
17,901
50,528
10,610
0
25,949
15,181
128,966
73,277
44.273
4,162
18,807
22,185
6
6,963
2,301
0
0
2,174
0
0
694
198,225
1.871
1,147,792
0
12.474
285,952
0
23
0
0
59
1
33
6
0
74
27
88
23
1
341
14
55
184
168
1
IS
14
0
3
1
0
0
16
0
0
12
146
3
775
2
28
840
.0
2,147
0
3
6,005
55
3,278
553
4
7.353
3.058
8,365
2,190
43
31,977
1.250
5,013
17.043
16.619
112
1,280
1,172
0
91
36
3
0
1,414
0
0
1,012
14,163
220
77,792
112
2,278
- 76,484
0
8
3
1
2
4
7
2
2
18
1
12
9
1
40
4
7
19
18
1
9
8
3
7
3
2
1
6
2
2
9
19
2
63
3
3
60
7
595
30
13
1,304
38
974
267
3
2,663
633
2,981
817
22
10.470
272
1.357
4.824
4,009
22
583
568
7
258
19
23
66
469
25
50
464
3,637 .
146
17,647
79
683
21,283
831
8
42
1
2
6
7
2
2
18
1
12
9
1
64
4
7
19
18
1
9
8
3
27
5
4
1
5
2
2
9
35
2
63
3
3
63
7
23
0
0
67
1
29
9
0
76
30
90
24
0
339
15
57
168
157
1
17
16
0
3
1
1
0
15
0
0
13
149
3
805
2
29
819
0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
Operating Utility
Blrs SO2RTE
S02
TOTHT
GENER Gent NAMEPCAP Units BASE8587
TOLEDO EDISON CO
TRAVERSE CITY CITY OF
TRINIDAD CITY OF
TUCSON ELECTRIC POWER CO
TWO HARBORS CITY OF
U S ERDA-LOS ALAMOS AREA OFF
UGI CORP
UNION ELECTRIC CO
UNITED ILLUMINATING CO
UNITED POWER ASSN
UPPER PENINSULA POWER CO
UTILICORP UNITED INC
VERO BEACH CITY OF
VINELANDCITYOF
VIRGINIA CITY OF
VIRGINIA ELECTRIC & POWER CO
WALLINGFORD TOWN OF
WAMEGO CITY OF
WASHINGTON WATER POWER CO
WELLINGTON CITY OF
WEST PENN POWER CO
WEST TEXAS UTILITIES CO
WESTERN FARMERS ELEC COOP INC
WESTERN MASSACHUSETTS ELEC CO
WILLMAR MUNICIPAL UTILS COMM
WINFIELDCrTYOF
WINNETKA VILLAGE OF
WISCONSIN ELECTRIC POWER CO .
WISCONSIN POWER & LIGHT CO
WISCONSIN PUBLIC SERVICE CORP
WOLVERINE PWR SUPPLY COOP INC
WYANDOTTE MUNICIPAL SERV COMM
tffiffEoswres^^^ <**?|w» f " *-^^^ «•>*"
12
4
2
8
1
3
1
23
8
5
3
5
5
8
5
25
3
1
1
2
11
23
7
3
3
4
5
40
16
13
3
4
^W2914x?ys3:
1.697
1.138
0.762
0.000
0.000
0.001
1.053
3.590
1.057
1.363
1.753
5.706
0.149
1.588
1.213
2.048
0.471
0.000
0.000
0.000
3.008
0.005
0.835
0.979
1.649
0.000
2.549
2.358
2.154
1.972
2.037
1.077
>F^-f:74«sTv^x
36,337
615
70
1
0
0
2,579
400,015
29,258
10.783
3,080
35,663
97
2,134
1,357
215,270
6
0
0
0
195,284
96
9,152
3,355
757
0
984
179.151
115.574
34,693
2.608
1.497
•v*^8,z«,in^!
43
1
0
5
0
1
5
223
55
16
4
12
1
3
2
210
0
0
0
0
130
37
22
7
1
0
1
152
107
35
3
3
*f ^ WJ571 ? yp'ws. v
4,633
73
8
411
0
17
300
21,881
5,563
2.815
191
1.174
101
177
9
20.448
1
0
282
12
13,067
3,833
2,009
619
32
0
16
14,313
10,438
3,157
148
181
t^Bosyws^
10
4
2
8
1
3
1
21
6
4
3
5
5
9
6
25
3
1
1
2
10
17
7 /
3
3
4
• 4
38
16
13
3
4
,,-4/t*'^W
947
32
8
609
4
20
50
6,351
1.188
218
42
568
158
172
36
7,554
23
2
51
28
2.718
1,745
779
210
30
45
26
5.281
2.638
1,180
37
73
?,w?jaw^
23
10
2
8
1
9
1
63
6
5
3
5
5
9
23
25
9
1
1
2
14
31
7
3
7
6
20
40
18
13
5
4
%?383&ff^$
43
1
0
. 4
0
1
4
225
57
15
3
.15
1
2
1
249
0
0
4
0
127
54
20
7
1
0
1
159
111
39
2
3
^•i.lS^M.i
-------
SECTION 4
ALLOWANCE-RELATED DATA
Although the NADB was originally conceived as a single data file from which all
allowance calculations could be made, the complexity of interpreting the CAA has resulted
in the creation of two additional data files: the Adjunct Data File (ADD (Pechan, 1992)
and the Supplemental Data File (SDF) (ICF, 1992). A schematic drawing depicting the
relationship among the three data bases is shown below in Figure 1.
Figure 1
Schematic of Data Relationship
NADB
ADF
SDF
THE ADF
The ADF contains qualifying and nonqualifying (under PURPA) generating units that
are greater than 25 MW and are at facilities ("plants") owned by a nontraditional utility.
These nontraditional utilities have filed a 1990 Form EIA-S67 (EIA, 1990c) which
indicates that they are connected to an electric utility through the selling of electricity.
Units included in the ADF are as follows:
• Existing, new, and planned fossil-fuel steam units.
• New and planned cogeneration units with potential sales of more than
one-third of their generation.
• New and planned simple combustion units.
Included in the current version of the ADF are 793 generating unit records covering
475 plants. Variables include 13 of those presently in the NADB. It is expected that
some of the nontraditional utilities will choose to provide data for the remaining fields
31
-------
once the comment period is announced in a Spring 1992 Federal Register Notice. After
that occurs, it is anticipated that these ADF records will be appended to the NAOB
records.
THESDF
The SDF contains the same boiler-generator records that are in the NADB Version
2.1. It is linked to the NADB through the variable SEQNUM which is in both files.
Including SEQNUM, there are 38 variables, 30 of which are different from those in the
NADB.
The SDF was created so that sufficient information would be available to calculate all
basic and bonus allowances. The data included in the SDF are used to classify'each
utility unit so that the appropriate provision(s) of the CAA can be applied to calculate
Phase 2 allowances. For further information, see the SDF support document (ICF, 1992).
32
-------
EIA, 1980-1989: Energy Information Administration, 'Monthly Power Plant Report,"
Form EIA-759,1980-1989.
EIA, 1982-1989: Energy Information Administration, "Steam-Electric Plant Operation and
Design Report," Form EIA-767,1981-1989.
EIA, 1985: Energy Information Administration, "Cost and Quality of Fuels for Electric
Utility Plants, 1985," 1985.
EIA, 1989a: Energy Information Administration, "Annual Electric Generator Report,"
Form EIA-860,1989. ,
S'
EIA, 1989b: Energy Information Administration, "Annual Electric Utility Report,"
Form EIA-861,1989.
EIA, 1990a: Energy Information Administration, "Annual Electric Generator Report,"
Form EIA-860,1990.
EIA, 1990b: Energy Information Administration, "Annual Outlook for U.S. Electric Power
1990: Projections Through 2010," 1990.
EIA, 1990c: Energy Information Administration, "Annual Nonutility Power Producers
Report, Form EIA-867,1990.
EPA, 1985: U.S. Environmental Protection Agency, "Compilation of Air Pollutant
Emission Factors," Volume I: Stationary Point and Area Sources, Fourth Edition,
September 1985 (with updates through 1988).
EPA, 1989: U.S. Environmental Protection Agency, "The 1985 NAPAP Emissions
Inventory (Version 2): Development of the National Utility Reference File,"
EPA-600/7-89-013a, November 1989.
FERC, 1985-1989: Federal Energy Regulatory Commission, "Monthly Report of Cost and
Quality of Fuels for Electric Plants," FERC Form 423,1985-1989.
FPC, 1980-1981: Federal Power Commission, "Steam Electric Plant Air and Water
Quality Control Data," Form 67,1980-1981.
FR, 1991: Federal Register, "Notice of Availability of the NADB Version 2.0," 56FR33278,
July 19,1991.
ICF, 1992: ICF Resources Incorporated, "The Supplemental Data File," Contract No.
68-DO-0102, prepared for EPA's Office of Atmospheric and Indoor Air Programs, May
1992.
83
-------
NERC, 1990: North American Electric Reliability Council, Generating Availability Data
System, "Generating Availability Report: 1985-1989," August 1990.
Pechan, 1991: E.H. Pechan & Associates, Inc., "The National Allowance Data Base
Version 2.0: Technical Support Document," Contract No. 68-D9-0168, prepared for
EPA's Office of Atmospheric and Indoor Air Programs, June 1991.
Pechan, 1992: E.H. Pechan & Associates, Inc., "The Adjunct Data File Technical Support
Document," Contract No. 68-D9-0168, prepared for EPA's Office of Atmospheric and
Indoor Air Programs, May 1992.
PL, 1990: Public Law 101-549, 42 U.S.C. §7651a(4)
-------
APPENDIX A
EPA REGIONS
-------
EPA REGIONS
Grouped By Region
(48 Contiguous States)
Region 1
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Region 2
New Jersey
New York
Region 3
Delaware
District of Columbia
Maryland .
Pennsylvania
Virginia
West Virginia
Region 4
Alabama
Florida
Georgia
Kentucky
Mississippi
North Carolina
South Carolina
Tennessee
Region 5
Illinois
Indiana
Michigan
Minnesota
Ohio
Wisconsin
Region 6
Arkansas
Louisiana
New Mexico
Oklahoma
Texas
Region 7
Iowa
Kansas
Missouri
Nebraska
Region 8
Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Region 9
Arizona
California
Nevada
Region 10
Idaho
Oregon
Washington
A-l
-------
EPA REGIONS
Grouped By State
(48 Contiguous States)
State
4 Alabama
9 Arizona
6 Arkansas
9 California
8 Colorado
1 Connecticut
3 Delaware
3 District of Columbia
4 Florida
4 Georgia
10 Idaho
5 Illinois
5 Indiana
7 Iowa
7 Kansas
4 Kentucky
6 Louisiana
1 Maine
3 Maryland .
1 Massachusetts
5 Michigan
5 Minnesota
4 Mississippi
7 Missouri
State
8 Montana
7 Nebraska
9 Nevada
1 New Hampshire
2 New Jersey
6 New Mexico
2 New York
4 North Carolina
8 North Dakota
5 Ohio
6 Oklahoma
10 Oregon
3 Pennsylvania
1 Rhode Island
4 South Carolina
8 South Dakota
4 Tennessee
6 Texas
8 Utah
1 Vermont
3 Virginia
10 Washington
3 West Virginia
5 Wisconsin
8 Wyoming
A-2
-------
APPENDIX B
MULTI-HEADER SITUATIONS
-------
APPENDIX B
MULTI-HEADER SITUATIONS
For boilers and generators with a configuration that is a one-to-one correspondence,
the data are handled in a straightforward manner. If data elements are at a plant level,
all records for that plant will have those same data element values.
In situations in which there are multi-header units (boilerfe) feeding multiple
generators and/or generator(s) being fed by multiple boilers), the data handling is more
complex. For data that are generator based, all plant records with the same generator ID
will have the same value for those data elements. This holds true for boiler based data as
well.
Regardless of the type of boiler-generator correspondence, there are three variables
whose value is specific to each record in the NADB Version 2.1. These are the sequence
number, SEQNUM (field 1), the 1985-1987 baseline, BASE8587 (field 25), and the shared
heat input, HT60SHR (field 38). The specific baseline value for each boiler-generator, for
example, is obtained by apportioning the boiler based fuel data to each generator,
depending upon its fractional share of the total generation (or, if that is not reported, the
nameplate capacity) associated with that boiler. When Form EIA-759 plant-level data
were apportioned to each generator, these data are divided equally among all of the
boilers connected to a multi-headered generator.
To illustrate this more concretely, consider a hypothetical plant in which boilers 1 and
2 feed generator 5, boiler 3 feeds generators 6 and 7, and boiler 4 feeds generator 8. The
following five NADB boiler-generator records for this plant are illustrated in Table B-l.
Table B-1
Hypothetical Multi-header Data
SEQNUM PNAME
BLRID
GENID
NAMEPCAP SO2
BASE8587
9991
9992
9993
9994
9995 .
Test
Test
Test
Test
Test
1
2
3
3
4
5
5
6
7
8
75
75
24
100
25
111
222
333
333
55
11.111111
2.222222
33.333333
4.444444
.555555
B-l
-------
The generator-related data (nameplate capacity, for example) would be the same for
SEQNUMs 9991 and 9992 because they have the same GENID, but it would be different
for SEQNUMs 9993 and 9994, since they have different GENIDs. Conversely, boiler-
related data (such as S02 emissions) would be the same for SEQNUMs 9993 and 9994,
but different for SEQNUMs 9991 and 9992. The 1985-1987 baseline data would be
specific to each of the five records.
Multi-headered situations must be taken into account when aggregating data. In
circumstances involving summing or averaging data, all the records may not be included.
Whether the data element is boiler or generator based will determine which set of unique
records to include. The following two cases involving the hypothetical plant depicted
above describe the aggregation of specified data:
• In order to compute the plant's total S02 emissions — boiler based
data - it would not be appropriate to sum the five records with
SEQNUMs 9991 through 9995, since the boiler-level data for
BLRID=3 appears in both the SEQNUM=9993 and SEQNUM=9994
records. Thus, the S02 data from the four records with SEQNUMs
9991 through 9993 and 9995 would be totaled for the plant S02
emissions.
• To calculate the plant's total nameplate capacity - generator based
data — it would not be correct to find the sum of either all of the
plant's five records or the four boilers described above. This is
because the capacity data for GENID=5 occurs in both
SEQNUM=9991 and SEQNUM=9992, so the plant capacity would be
determined by totaling the NAMEPCAP data for the four records with
SEQNUMs 9992 through 9995.
B-2
-------
APPENDIX C
DBASE m PLUS NADB VERSION 2.1 FILE STRUCTURE
-------
DBASE II! PLUS NADB VERSION 2.1 FILE STRUCTURE
(File: NADBV21.DBF)
Field Name
Type
Width
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
SEQNUM
STATNAM
PNAME
BLRID
GENID
UTILNAME
UCODE
EPARGN
CNTYNAME
ORISPL
PHASE1AL
TOTHT
SO2
SO2CATEG
SCRUBBER
FELIM85
ANNFACT
AVGPD
NAMEPCAP
SUMNDCAP
GENMNONL
GENYRONL
BLRMNONL
BLRYRONL
BASE8587
OUTAGEHR
PRIMFUEL
GAS8089
HEATRATE
GENER
UCAPFSST
MXBS8089
RY ER
FLAGMUNI
SO2RTE
ANNLIM85
HT60
HT60SHR
Num
Char
Char
Char
Char
Char
Num
Num
Char
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
4
20
20
6
4
30
5
2
20
4
9
11,6
10.2
2
1
8.4
4.2
2
7.2
7,2
2
4
2
4
11,6
6
1
7.3
8.2
8.2
8,2
11.6
8.4
1
8.4
8.4
11,6
11,6
*
Boiler-generator sequence number
State name
Plant name
Boiler identification code
Generator identification code
Operating utility name
Operating utility code
EPA region
County name
DOE ORIS plant code
Phase 1 allowances (tons) from Table A of the CAA
1985 boiler total heat input (10" Btu) from NURF
1985 boiler SO2 emissions (tons) from NURF
Boiler SO2 regulatory category (0-no information, 1-SIP,
2-NSPS D, 3-NSPS Da, 4-NSPS GG, 6-SIP for existing
gas turbine, combined cycle, with auxiliary firing, 9-NSPS GG
for existing gas turbine, combined cycle, with auxiliary firing)
Boiler SO2 scrubber flag (1-yes, 2-no, 9«no information)
1985 boiler S02 emission limit (Ibs/MMBtu)
1985 SO2 emission limit annualization factor
1985 SO2 emission limit averaging period (see
Technical Support Document)
1989 generator nameplate capacity (MW)
1989 generator summer net dependable capability (MW)
Generator month on-line (first electricity)
Generator year on-line (first electricity)
Boiler month on-line
Boiler year on-line
1985-1987 boiler-generator average total heat input,
•baseline' (10" Btu) from Form 767
Consecutive planned and forced outage time during
1985-1987 > -2,920 hours (hours) from GADS
Primary fuel indicator based on greatest fuel
heat share during 1985-1987 (1 -coal>50%. 2-oil/gas)
1 980-1 989 gas share (%)
1989 generator full load heat rate (Btu/kWh)
1985 generator generation (GWh)
Total capacity of the fossil-steam units operated
by the operating utility (MW)
Maximum of the average heat inputs for any
combination of three consecutive years from
1980-1989 for selected units (10" Btu)
Representative year SO2 emission rate (Ibs/MMBtu)
Municipally operated flag (1-yes, 0-no)
1985 boiler SO2 emission rate (ibs/MMBtu)
1985 annualized boiler S02 emission limit (Ibs/MMBtu)
Generator heat input at 60 percent capacity (10" Btu)
Boiler-generator share of generator heat input at
60 percent capacity (10" Btu)
C-l
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APPENDIX D
CALCULATIONS FOR TOTHT, SO2, AND SO2RTE
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APPENDIX D
CALCULATIONS FOR TOTHT, SO2, AND SO2RTE
The NADB 1985 SO2 emission rate (SO2RTE) is calculated from NADB 1985 S02
emissions (SO2) and NADB 1985 heat input (TOTHT). However, both TOTHT and SO2
are most often calculated by utilities at the boiler level from quantities of fuel burned and
fuel qualities such as heat and sulfur content.
The equations that EPA utilizes to calculate TOTHT and 802, in addition to
S02RTE, are described below.
MONTHLY TO YEARLY VALUES
Frequently, the data for fuel use and heat content (or heating value) and sulfur
content (or sulfur percent) are recorded on a monthly (or daily) basis. In order to
calculate on a yearly basis, these data are converted to yearly data using the following
method:
" • For each fuel, the total amount of fuel used for the year is calculated
by simply adding up the monthly fuel used.
• The yearly heat and sulfur contents for each fuel are determined by a
fuel use weighted average. This weighted average is calculated by
multiplying each month's fuel use and associated heat (or sulfur)
content, and then adding up these monthly values and dividing by the
yearly fuel used.
ACTUAL 1985 YEARLY TOTAL HEAT INPUT CALCULATION
The equation used to calculate the yearly total heat input (TOTHT) is as follows:
TOTHT = coal heat input + oil heat input + pas heat input (1)
(inl^Btu)
Each fuel type heat input is calculated on a yearly basis using the following equation:
fuel heat = (fuel burned) " (wtd. av. heat content) * (conver. fact.) (2)'
(inBtu)
For coal, fuel burned is usually in tons and heating value is usually in Btu/lbs. Thus,
the conversion factor is 2000 Ibs/ton.
D-l
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For oil, fuel burned is usually in barrels and heating value is usually in Btu/gal.
Thus, the conversion factor is 42 gal/bbl.
For gas, fuel burned is usually in cf, and heating value is usually in Btu/cf. Thus, the
conversion factor is 1.
ACTUAL 1985 YEARLY SO2 EMISSIONS CALCULATION
The equation used to calculate the yearly S02 emissions (802) is as follows:
SO2 » (coal SOS emissions) + (oil SOS emissions) (3)
(in tons)
If gas is the only fuel, gas emissions are defaulted to .0006.
Each fuel type S02 emissions is calculated on a yearly basis, using the equation:
fuel (yrlywtd. (AP-42 (1 - scrb. (units (4)
SO2 emissions = av. fuel * fact.) * efflc. % * conver.
(in tons) sulfur %) /100) fact.)
For coal, the yearly fuel burned is in tons/yr and the AP-42 factor (which accounts for
the ash retention of sulfur in coal), in Ibs SOa/ton coal, is by coal type:
Coal Type AP-42 Factor
bituminous, anthracite 39 Ibs/ton
subbituminous 35
lignite 30
For oil, the yearly fuel burned is in gal^r. If it is in bbl/yr, convert using 42 gal/bbl
oil. The AP-42 factor (which accounts for the oil density), in Ibs SO./thousand gal oil, is
by oil type:
Oil Type AP-42 Factor
distillate (light) 142 lbs/1,000 gal
residual Qieavy) 157
For all fuel, the units conversion factor is 1 ton/2000 Ibs.
ACTUAL 1985 YEARLY SO2 EMISSION RATE CALCULATION
When the SO2 tons and heat input for all fuels is known, the equation for calculating
the SO2 emission rate (S02RTE) is as follows:
SO2RTE * 2* (total SO, emissions in tons) (5)
(inlbs/MMBtu) 1000 * (total heat input in itf2Btu)
D-2
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If the emission rate is known only for coal (from continuous emissions monitoring, for
example), yet oil is also burned, the following steps should be taken to calculate the
emissions rate for all the fuels:
• Use the coal S02 rate (in Ibs/MMBtu) and coal heat input (in 1012 Btu)
to "back calculate" the coal S02 emissions with the formula:
coal SOS emissions = 1000 * (SO? coal em. rate) * (coal heat input) (6)
(in tons) . 2
• Calculate the oil S02 emissions using equation (4).
• Sum the coal and oil S02 emissions using equation (3).
• Calculate the coal and oil heat inputs using equation (2) and sum
them using equation (1).
• Calculate overall S02 emission rate using equation (5).
D-3
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APPENDIX E
ENFORCEABLE SO, EMISSION LIMIT DETERMINATIONS
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APPENDIX E
ENFORCEABLE SO2 EMISSION LIMIT DETERMINATIONS
The source of federally enforceable limits is the preliminary SIP limit data base
developed by OAQPS. This data base (developed alter a comprehensive review of all
Federal, State, and local regulations affecting combustion boilers was conducted) provides
Federal emission limit information for units in 1985, usually expressed in pounds of S02
per million Btu. In certain cases, these limits are not expressed in Ibs/MMBtu and have
been converted using the factors shown in Table E-l. Limits are rounded to four decimal
places.
In addition to emission limits, the data base provides the averaging periods over
which these limits were enforced. (These averaging periods are essential to EPA in its
determination of annual allowable 1985 S02 emission rates.) The 17 codes for the
averaging period are listed in Table E-2. The data base also includes the S02 regulatory
category affecting each unit. For further information, see the documentation for the SIP
data base (SAIC, 1990).
Following the development of this EPA SIP limit data base, the information was
reviewed by the EPA regional offices and some State agencies and utilities. Cases where
limits were still in question were followed up with telephone calls to resolve any conflicts
in information received.
The factor for converting pounds of sulfur to pounds of SO2 is based on the molecular
weights of sulfur (32) and S02 (64). Limits expressed as percentage of sulfur or parts per
million (ppm) depend on the energy content of the fuel and thus may vary, depending on
several factors such as fuel heat content and atmospheric conditions. Generic conversions
for these limits are based on the assumed average energy contents listed in Table E-l. In
addition, limits in ppm vary with boiler operation (e.g., load and excess air); generic
conversions for these limits assume, conservatively, very low excess air. The remaining
factors are based on site-specific heat rates and capacities to develop conversions for Btu
per hour. Standard conversion factors for residual oil are 42 gal/bbl and 7.88 Ibs/gal.
A limit of 99.9 appears for units which had no federally enforceable limit in 1985
and/or no permitted limit (for new units). These are generally cases in which either the
State never submitted the limits as part of its SIP and/or EPA never approved the limits;
therefore, these units are considered not to have a federally enforceable limit.
E-l
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Table E-1
Conversion Factors
(Emission limits converted to Ibs SO^MMBtu
by multiplying as below)
Plant Fuel Type
Unit Measurement
Bituminous
Coal
Subbituminous
Coal
Lignite
Coal
Oil
Ibs Sulfur/MMBtu
% Sulfur in fuel
ppm SO2
ppm Sulfur in fuel
tons SOj/hour
Ibs SOj/hour
2.0
1.66
0.00287
2.0
2.22
0.00384
2.0
2.86
2,000,000/(HEATRATE*SUMNDCAP*capacity factor)1
1,000/(HEATRATE*SUMNDCAP*capacity factor)1
2.0
1.07
0.00167
0.00334
1 In these cases, if the limit was specified as the "site* limit, the summer net dependable capability for
the entire plant is used; otherwise, the summer net dependable capability for the unit is used. Capacity
factor is based on 1985 utilization [=(1985 EIA total heat input in 1012 Btu)/
(HEATRATE*SUMNDCAP*8760/109)]. For post-1985 units, a capacity factor of .65 is assumed.
Annualization factors for these cases is assumed to be 1.0.
Assumed Average Energy Content Conversion
Fuel Type Average Heat Content
Bituminous Coal
Subbituminous Coal
Lignite Coal
Residual Oil
24 MMBtu/ton
18 MMBtu/ton
14 MMBtu/ton
6.2 MMBtu/bbl
E-2
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Table E-2
Averaging Period Codes
AVGPD Code Definition
0 oil/gas unit (no averaging period)
1 1 hour
•
2 2 hours
3 3 hours
4 1 day
5 24 hours
6 24 hours rolling
7 1 week
8 30 days
9 30 days rolling
10 90 days
11 90 days rolling
12 3 months
13 1 year
15 not specif led
16 at all times
99.9 no Federal limit for coal units or unknown
E-3
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APPENDIX F
METHODOLOGY FOR ANNUAUZATION OF SO, EMISSION LIMITS
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APPENDIX F
METHODOLOGY FOR ANNUALIZATION OF SO2 EMISSION LIMITS
Annualization factors are used to develop annual equivalent S02 limits as required by
§402(18) of the CAA. Many emission limits are enforced on a shorter term basis (or
averaging period) than annually. Because of the variability of sulfur in coal and, in some
cases, scrubber performance, meeting a particular limit with an averaging period of less
tha" a year and at a specified statutory emissions level would require a lower annual
average SO2 emission rate (or anp^ql equivalent S02 limit) than would the shorter term
statutory limit, EPA has selected a compliance level of one exceedance per 10 years. For
example, an SO2 emission limit of 1.2 Ibs/MMBtu, enforced for a scrubbed unit over a 7-
day averaging period, would result in an annualized SO2 emission limit of 1.16
Ibs/MMBtu. In general, the shorter the averaging period, the lower the annual equivalent
would be. Thus, the annualization of limits is established by multiplying each federally
enforceable limit by an annualization factor that is determined by the averaging period
and whether or not it's a scrubbed unit.
The annualization factors developed by EPA (Radian, 1991) are listed in Table F-l.
The development of these factors was based on accepted EPA statistical methods using a
data base containing the utility units' continuous emissions monitoring (OEM) system
results. This data base is a cross-sectional representation of utility plants with units of
different sizes, with or without flue gas desulfurization (FGD) systems (or scrubbers), and
different coals. Factors were developed using various averaging periods and two different
compliance levels.
For further information, see the annualization factors development report (Radian,
1991).
F-l
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Table F-1
SO2 Emission Averaging Period Codes and Annualization Factors
i
Annualization Factor
AVGPD Code
0
1-6
7
8-9
10-12
13
15
16
99.9
Definition
oil/gas unit
<« 1 day
1 week
30 days
90 days
1 year
not specified
at all times
no Federal limit for
coal limits or unknown
Scrubbed
Unit
1.00
0.93
0.97
1.00
1.00
1.00
0.93
0.93
1.00
Unscrubbed
Unit
1.00
0.89
0.92
0.96
1.00
1.00
0.89
0.89
1.00
F-2
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