EPA430-R-98-013
THE NATIONAL ALLOWANCE DATA BASE
VERSION 2.2
TECHNICAL SUPPORT DOCUMENT
1998 Revision
Prepared for:
U.S. Environmental Protection Agency
Office of Atmospheric Programs
Acid Rain Division
Washington, DC 20460
Prepared by:
Susy S. Rothschild
E.H. Pechan & Associates, Inc.
Springfield, VA 22151
Pechan Report No. 97.01.002/442.008
August 1998
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NOTICES
This document has been reviewed by the Acid Rain Division, Office of Atmospheric 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
Programs, U.S. Environmental Protection Agency.
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CONTENTS
Notices ii
Tables iv
Abbreviations and Acronyms v
Acknowledgements vi
1. Introduction 1
2. National Allowance Data Base 3
3. Description of Data Elements 7
4. Supplemental Data File 35
References 37
Appendices A-l
A. EPA Regions A-l
B. Multi-header Situations B-l
C. dBASE III Plus NADB Version 2.2 File Structure C-l
D. Calculations for TOTHT, SO2, and SO2RTE D-l
E. Enforceable SO2 Emission Limit Determinations E-l
F. Methodology for Annualization of SO2 Emission Limits F-l
G. Technical Documentation for the Supplemental Data File G-l
1. Introduction G-3
2. Structure of the Supplemental Data File G-5
3. Provision Descriptions G-9
4. Examples of SDF Data G-31
in
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TABLES
Number
1 NADBV22 Variable List 19
2 Sample NADBV22 Data 20
3 State Summaries for Selected Variables 21
4 EPA Region Summaries for Selected Variables 22
5 Operating Utility Summaries for Selected Variables 23
A-l EPA Regions — Grouped by Region A-l
A-2 EPA Regions -- Grouped by State A-2
B-l Hypothetical Multi-header Data B-l
C-l dBASE III Plus NADBV22 File Structure C-l
E-l Conversion Factors E-2
E-2 Averaging Period Codes E-3
F-l SO2 Emission Averaging Period Codes and Annualization Factors F-2
G-l SDF Fields G-6
G-2 SDF File Structure G-8
G-3 Sample SDF Data G-32
IV
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ABBREVIATIONS AND ACRONYMS
bbl - Barrel
Btu — British thermal unit
CAA - Clean Air Act
CEM — Continuous Emissions Monitoring
cf — Cubic feet
CFR — Code of Federal Regulations
DOE — U.S. 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
FR — Federal Register
GWh — Gigawatt-hour
kVA — Kilovolt-ampere
kW -- Kilowatt
kWh -- Kilowatt-hour
Ibs — Pounds
MMBtu - Million Btu
MMcf — Million cubic feet
MW — Megawatt
NADB — National Allowance Data Base
NADBV211 - National Allowance Data Base Version 2.11
NADBV22 - National Allowance Data Base Version 2.2
NAPAP — National Acid Precipitation Assessment Program
NERC — North American Electric Reliability Council
NURF - National Utility Reference File
NSPS — New Source Performance Standards
OAQPS - Office of Air Quality Planning and Standards (EPA)
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
SO2 - Sulfur dioxide
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ACKNOWLEDGEMENTS
The National Allowance Data Base and its supporting technical documentation were created
under the supervision of Dr. Susy S. Rothschild of E.H. Pechan & Associates, Inc. The
Supplemental Data File and its supporting technical documentation, presented as Appendix G of
this report, were created under the supervision of Adam Kreczko and John Blaney of ICF
Incorporated. The author would like to acknowledge the valuable support provided by 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 U.S. 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 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
the 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
Clean Air Act (CAA) were expanded in the NADB. Additional data for
determining allowances under specific provisions of Title IV are included in
the Supplemental Data File (SDF).
The NADB Version 2.11 (NADBV211) data underwent 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 (Pechan, 1991); by the
utilities, during a 45-day public review during summer 1991, which resulted in Version 2.1
(Pechan, 1992); and again by the utilities during a 60-day public review during summer 1992,
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culminating in the release of Version 2.11 (Pechan, 1993). The NADBV211 was used in 1993 to
calculate sulfur dioxide (SO2) emissions allowances, as provided by Title IV of the CAA (PL,
1990).
The NADB Version 2.2 (NADBV22) is an update to the NADBV211, necessitated by the
CAA Title IV requirement that the SO2 allowances be reallocated for 1998. The data base
structure (number and type of data elements) are identical in both files, as are the number of
records.
The new data base, NADB V22, is a result of identification variable changes (such as
operating utility name and code, boiler ID, and ORIS plant ID and plant name) as well as changes
to a few data elements for a small number of boilers due to EPA errors, court decisions, and
litigation settlements.
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. Specific information
about each of the data elements is contained in Section 3. Section 4 includes material pertaining
to the SDF. 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.
• 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 the nameplate capacity is greater than 25
MW and they can potentially sell more than one-third of their generation to a
utility.
• New utility units that failed to submit Form EIA-860 by December 31, 1991 are
not included.
• 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.
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 Emissions Inventory.
Form EIA-767 (EIA, 1982-1989) and Form FPC-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, 1989).
In July 1990, the data for each plant were submitted to the 10 EPA regions for review of the following
key elements: 1985 SO2 emissions and emission rate, 1985 total heat input, and 1985 SO2 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. EPA made a concerted effort 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).
EPA offered The NADB Version 2.0 for public review (FR, 1991) during a 45-day comment period
commencing July 19, 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.
EPA's responses to all the requested changes were submitted to the docket. Changes were made to the data
base, resulting in the NADB Version 2.1 (Pechan, 1992). Reported data for simple combustion turbine and
combined cycle units planned for construction through 2006 were also included in this data base.
In order to determine which units would qualify for certain special provisions of Title IV, and to
calculate allowances for those units, additional information was required beyond that contained in the
NADB. EPA prepared a Supplemental Data File (SDF) in 1992 to meet these requirements.
Also, in the course of finalizing the NADB Version 2.1, EIA identified a number of potentially
affected units under the Acid Rain Program in their data files that were not included in NADB Version 2.0.
These units were generally not owned by traditional utilities but possibly fit the definition of utility unit as
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defined in Title IV. EPA created an Adjunct Data File (ADF) containing the same data fields as the NADB
for these potentially affected sources.
The NADB Version 2.1 was then subject to a limited public review (FR, 1992) during a 60-day
comment period initiated by EPA as of July 7, 1992. Only three items were opened for comment: (1)
EPA's policy on outage hours, (2) comments on the SDF, and (3) comments on the ADF. Subsequent to
the September 8, 1992 close of the comment period, the documents submitted to the two EPA dockets were
reviewed by EPA. (One docket addressed issues raised regarding the NADB Version 2.1, the other docket
addressed issues raised in response to the Allowance Allocation Proposed Rule.) Determinations regarding
requested data changes on that notice were based on the following policy:
• Changes to outage hour fields were made to conform to the final policy contained in
the Federal Register notice supporting the NADBV211.
Necessary changes were made to the SDF in response to comments.
Units contained in the ADF that, after public comment, EPA believed to be affected
units under the Acid Rain program were added to the NADBV211 and documented
information added to NADBV211.
In addition, several comments contained requests to change data which was already subject to the
review in 1991. EPA made the following decisions regarding such requests:
• If the request was a reiteration of a previous request where EPA correctly resolved
the issue, the request was denied.
If the request was a reiteration of a previous request where EPA failed to correct
the error or the attempt to correct the error was incorrectly implemented, the
request was reviewed and, if appropriate, granted.
If the request was for a new data change that could have been previously submitted,
the request was denied.
This policy fairly implemented the intent of Congress to allow a limited (through December 31, 1991)
opportunity to correct data errors, and made sure that requests submitted within the timeframe were
handled correctly. For further details, see the Comment Responses available from the EPA docket for
public review (EPA, 1993).
Following the completion and implementation of these changes to the data base, the Core Rules
(including Acid Rain permitting, allowance trading, and monitoring requirements) were promulgated in
January 1993, the Technical Document was updated in February 1993 (Pechan, 1993), and the
NADBV211 was released in March 1993 along with the Final SO2 Allowance Allocation Regulations.
Following the final allowance allocations rule, a number of utilities initiated litigation regarding their
allowances and underlying data and a number of other utilities petitioned the Agency for data changes.
After litigation regarding the meaning of utility capacity under section 405(c) of the Act was remanded to
the Agency, EPA proposed to revise the utility capacity field (UCAPFSST) for three utilities affected by
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the provisions. (FR, 1996) In addition, based on the existing policy for reviewing petitions requesting data
changes (above), the Agency determined that data changes requested for three units were appropriate. (FR,
1996)
Also, units eligible for allowance allocations under section 405(g)(4) of the Act were required to
provide documentation to EPA no later than December 31, 1995 to confirm that the units had commenced
construction prior to December 31, 1990 and had commenced commercial operation from January 1, 1993
through December 31, 1995. Based on the submittals, EPA changed the relevant data fields in the SDF
andNADBV211. (FR, 1996)
NADB Version 2.2 (NADBV22) incorporated these limited changes to NADBV211 and was released
with the Proposed 1998 Reallocation of Allowances on January 7, 1998. (FR, 1998). No changes have
been made to NADBV22 since its release. Represented in the NADBV22 are 328 operating utilities,
956 plants, 2,757 generators, and 2,913 boilers. There are 2,468 records of one-to-one boiler-generator
correspondence and 1,548 multi-headered records. The NADBV22 includes 3,842 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. The NADBV22 is available in dBASE III Plus PC format, as well as
on the IBM mainframe in Statistical Analysis System (SAS) format.
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SECTION 3
DESCRIPTION OF DATA ELEMENTS
The NADBV22 has the same exact structure as that for the NADBV211: there are 3,842 records and
38 data elements. These data elements are 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 SO2 emission rate, and the third
category includes data elements numbered 14 through 18, which are associated with the determination of
the 1985 allowable SO2 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.
Five tables, 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. Because EPA has not updated all operating
utility information, the operating utility summarizes do not reflect recent utility industry restructuring. 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 NADBV22 data may have been obtained
from a different source as a result of the utility responses submitted during the comment periods or because
of a unique plant configuration or reporting method.
IDENTIFICATION OR FIXED VARIABLES
1. Boiler-generator Sequence Number (SEQ) ~
The boiler-generator records in this data file, NADBV22, have the unique identifier, SEQ, that
has the same value as that in the NADBV211 SEQ. This value was obtained after the
NADBV211 data were sorted by State name, plant name, boiler ID, and generator ID, and was
assigned a unique sequential number from 1 to 3,842. The NADBV22 is still sorted by SEQ,
although some plant names and boiler IDs, among other data elements, were updated.
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 identical names ("NA") but different plant codes (ORISPL)
were modified by appending the ORISPL in order to uniquely identify the plants.
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4. Boiler Identification Code (BLRID) -
This field identifies the boiler (in the fossil-fuel steam unit case) or gas- or oil-burning turbine (in
the new simple combustion turbine case). In the majority of cases, there is a one-to-one
correspondence with the generator ID. The source of the boiler identification code was Form
EIA-767 or a report from the utility (if there was no Form EIA-767 filled out). If small, planned,
or other units did not have an assigned boiler code, a default value of two asterisks followed by
the GENID was used.
5. Generator Identification Code (GENID) -
This field identifies the electrical generation unit (generator). In the majority of cases, there is a
one-to-one correspondence with the boiler identification code. The source of the generator
identification code was Form EIA-860.
6. Operating Utility Name (UTILNAME) -
The source of the data was Form EIA-861. This name will be different from that in the 1985
NURF if the name or operator changed between 1985 and 1989. 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 of regions and associated states.
9. County Name (CNTYNAME) ~
The county name was obtained from Form EIA-860. For planned units whose exact location
was unknown, the CNTYNAME is "NOT IN FILE."
10 DOE (ORIS) Plant Code (ORISPL) ~
This plant code was originally developed by ORIS, which is a part of the Federal Power
Commission. It is now used as a unique plant identification code assigned by EIA.
11. Total Phase 1 Allowances (TOTALPH1) ~
This field contains the total basic Phase 1 allowances, in tons, for units that appear in Table A of
the CAA (with multi-header situations taken into account). The allowances in Table A,
originally on the generator-level, were reallocated to the boiler-level and then adjusted for certain
units that receive additional allowances under §404(a)(3) and §404(h) of the CAA. These total
values are equal to the sum of Column A and Column B published in Table 1 of §73.10(a) in the
Federal Register (FR, 1993). Therefore, these total values do not reflect subsequent deductions
of allowances required under §416 to create the "auction and sales" allowance reserve that are
published in Table 1, Column B.
1985 ACTUAL SO, EMISSION RATE-RELATED VARIABLES
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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.
13. 1985 Boiler SO2 Emissions (SO2) -
This field contains SO2 emissions, in tons, from the 1985 NURF. See Appendix D for detailed
calculations.
1985 ALLOWABLE SO2 EMISSION RATE (LIMIT)-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 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 was 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). Scrubber
information was obtained from EIA (EIA, 1985) and updated. Information is provided for
planned units to the extent available. For planned units for which no information was available,
SCRUBBER=9. Units that showed a zero percent SO2 removal efficiency were assumed to be
unscrubbed.
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16. 1985 Boiler SO2 Emission Limit (FELIM85) -
This field is the federally enforceable SO2 emission limit (rounded to four decimal places) that
applied to each boiler in 1985, and converted to pounds of SO2 per million Btu of heat input
(Ibs/MMBtu), if necessary. For units with more than one limit, the most stringent federally
enforceable limit was used. For newer units subject to NSPS, and those that came on-line after
1985, the federally permitted limit was used. For units with no federally enforceable limit or
units not yet permitted, a code of 99.9 was used. The source of these data was 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 actualization factor that, when multiplied by the SO2 emissions limit
(FELIM85), produced 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, FELIM85, was applied. The source of these data was 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 existing (or planned) generator, in MW
and rounded to two decimal places. Form EIA-860 generally was the source of this value. If the
nameplate rating was expressed in kilovolt-amperes (kVA), the translation to MW was made by
using the formula:
MW = kVA * power factor/103
where kVA and power factor are specified by the manufacturer and stamped on the physical
nameplate attached to the generator. For combined cycle units with auxiliary firing, the gas
turbine MW and steam generating unit MW were combined for the nameplate capacity value.
For planned units, the NAMEPCAP value represents the planned nameplate capacity as reported
on Form EIA-860.
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20. 1989 Generator Summer Net Dependable Capability (SUMNDCAP) -
This field contains the 1989 summer net dependable capability of the existing generator, in MW
and rounded to two decimal places. The source of this data element was Form EIA-860. For
combined cycle units with auxiliary firing, the gas turbine MW and steam generating MW were
combined for the summer net dependable capability value. For planned units, the SUMNDCAP
value represents the planned summer net dependable capability as reported on Form EIA-860.
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 was not available, the default value is NAMEPCAP.
For units coming on-line after 1990, which may not have established a reliable value for summer
net dependable capability, the capability was determined from the following formula:
SUMNDCAP =NAMEPCAP * factor,
where factor varies (EIA, 1990a) based on the type of unit as described below:
Unit Type Factor
Combined Cycle .85
Combustion Turbine .85
Steam Turbine .94
Jet Engine .87
Internal Combustion .97
21. Generator Month On-line (GENMNONL) ~
This data value, from Form EIA-860, is the month portion of the generator startup date. For
existing units, this was the first electricity date (viz, the date when the unit began to produce
electricity, including electricity generated during a testing period). For units that repowered, it
was the repowered generator first electricity date. For planned units, it was the projected first
electricity date at the time of NADBV211 development.
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) -
Although the term "commenced commercial operation" is defined as having "begun to generate
electricity for sale, including the sale of test generation" (FR, 1993), the generation of electricity
occurs at the generator, thus potentially creating difficulty in determining the boiler on-line date
that is used to categorize affected units for Phase 2 allowance allocations. Therefore, the
following guidelines were complied with to determine boiler on-line dates:
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 (viz,
the date when both the boiler first consumes fuel and the associated generator first produces
generation).
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 on-line dates of 1990 and beyond, the boiler on-line date is the projected generator
first electricity date at the time of NADBV211 development.
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 the boilers feeding that generator, unless the
boiler was new or replaced.
If the boiler is new or was replaced, the date of the boiler's first consumption of fuel, or the date
of commercial operation of the new boiler, as reported to EIA, was used. These data have been
updated since NADBV211 publication when necessary for correct allocation of allowances.
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.
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 was 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 (in plants under 100 MW), data were obtained
elsewhere. The 1985 fuel use data were apportioned, based on MW, from Form EIA-759 plant-
level data. The associated 1985 heat content was 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) was used as the default value.
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For units with OUTAGEHR=26,280 (the entire 1985 to 1987 baseline time period), the value for
BASE8587 was an alternative representative baseline value assigned by EPA to correspond to 1
hour of fuel usage, as authorized by §402(4)(a) of the CAA. In this case, the value for
OUTAGEHR was correspondingly changed to 26,279 (to avoid division by zero when
calculating the adjusted baseline used 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 the boiler. When Form EIA-759 plant-level data were used, the data were 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 were 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) was 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 all 3 years, the baseline value is 0.
Note that outage hours do not affect the numerical value contained in this field. This
baseline value is therefore not adjusted for either outage hours or for units that came on-line
during the 1985 to 1987 time period.
13
-------
26. Consecutive Planned and Forced Outage Hours (OUTAGEHR) -
This field represents the number of continuous hours a unit was out of service between 1985 and
1987 due to a planned or forced outage for non-routine maintenance or for specified outage
classifications accepted by EPA.
The majority of the data were 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." For utilities that did not
report to GADS, unit outages were allocated if they were well-documented planned or forced
outages for non-routine maintenance reported to EIA.
The following list contains the outage classifications that were accepted by EPA.
! Forced/planned non-routine maintenance and accidents, longer than or equal to 4
months.
! Outages of 3 months or longer caused by accidents (natural phenomena or incidents
unrelated to the operation of the unit that are unpreventable, unforeseeable, and not
caused by worker error).
! Discontinuous but related outages for forced/planned non-routine maintenance, where
total duration was 4 months or longer.
! Discontinuous but related outages for accidents, where total duration was 3 months or
longer.
! Outages of 4 months or longer, which were not caused by forced/ planned non-routine
maintenance or accidents, in which the unit's emission rate was less than 1.2
Ibs/MMBtu and the allowance impact by not providing allowances to the operating
utility was severe.
If there were individual unrelated outages each totaling less than 4 months (2,920 hours) during
the period from 1985 to 1987, the value of OUTAGEHR is 0.
27 Primary Fuel Indicator (PRIMFUEL) -
This field, for those units with fuel use, has a value of 1 if the coal heat input was 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
was used to determine the value of PRIMFUEL (the value was set at 1 if the primary fuel was
reported as coal, and was set at 2 otherwise).
14
-------
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 was:
GAS8089=100*(1980-1989 gas 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 were used. This field was 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 were 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.
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 was 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 was 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).
30. 1985 Generator Generation (GENER) -
Whenever possible, generator generation for 1985, in GWh, was obtained from Form EIA-767.
Generator-level generation data were 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 were
apportioned, by MW, from Form EIA-759 plant-level data. For existing combined cycle units
with auxiliary firing, the gas turbine generation and the steam generating unit generation were
combined for the generator generation value. For units not operating in 1985, the generation
value is 0.
31. Total Capacity of the Fossil-steam Units of the Operating Utility
(UCAPFSST) ~
This field is the sum, in MW, to the nearest integer, of the Form EIA-860 reported 1989
nameplate 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 operated capacity was less than
0.5 MW, this field value is 0. As a result of litigation, three utilities had this data element
modified.
15
-------
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 3 consecutive years reported on Form EIA-767
between 1980 and 1989. It was calculated similarly to BASE8587, but only for units subject to
§405(i) of Title IV of the CAA; the value is 0 otherwise.
33. Representative Year SO2 Emission Rate (RY_ER) -
The representative year SO2 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 was assigned the 1985 (or 1986 or 1987) SO2 emission rate calculated from EIA data.
The EIA emission rate was calculated using Form EIA-767 fuel quantity and quality data, EPA's
AP-42 emission factors (EPA, 1985), and the SO2 control efficiency. See Appendix D for the
formula.
If a unit had a positive baseline value, an SO2RTE value of 0, all EIA emission rates calculated
to be 0, and was more than 90 percent gas for either the 1980 to 1989 (GAS8089>90) or the
1985 time period, then this field was assigned a default value of 0.0006, 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 was necessary for allowance calculations and was approved, it
was included.
34. Municipally Operated Flag (FLAGMUNI) -
If an operating utility is a municipal utility as of December 1989, this field has a value of 1, and
0 otherwise. The source of this data element was Form EIA-861.
CALCULATED VARIABLES
35. 1985 Boiler SO2 Emission Rate (SO2RTE) -
The actual SO2 emission rate, in Ibs/MMBtu and rounded to four decimal places, was calculated
from the boiler SO2 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 was:
SO2RTE=(2 *SO2)/(1000 *TOTHT).
36. 1985 Annualized Boiler SO2 Emission Limit (ANNLIM85) -
The "allowable 1985 SO2 emission rate," in Ibs/MMBtu and rounded to four decimal places, is
defined in the CAA as an annual equivalent SO2 emission limit. ANNLIM85 was calculated
using the equation:
ANNLM85=ANNFACT*FELM85.
16
-------
37. Generator Heat Input at 60 Percent Capacity (HT60) ~
This field, in 1012 Btu, was calculated on an annual basis using the formula as shown, where
5,256 is a conversion factor (60 percent of 8,760 hrs/yr):
HT60=(HEATRATE*SUMNDCAP *5256)/l O9.
The net summer capability was used because the nameplate capacity for many units was not a
good measure of the maximum MW a generator can produce. Most utility 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, was calculated from HT60 for multi-header units. For each generator
with multiple boilers, based on BASE8587, HT60 was apportioned among the boilers. If the
BASE8587 value for the multiple boilers are all 0, HT60 was shared equally among the boilers.
If there is a single boiler associated with a generator, HT60SHR is equal to HT60.
17
-------
Table 1
NADBV22 Variable List
Field
Number
Variable
Name
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
SEQ Boiler-generator sequence number (same as in NADBV211)
STATNAM State name
PNAME Plant name
BLRID Boiler identification code
GENID Generator identification code
UTILNAME Operating utility name
UCODE Operating utility code
EPARGN EPA region
CNTYNAME County name
ORISPL DOE ORIS plant code
TOTALPH1 Total basic Phase 1 allowances (tons)
TOTHT 1985 boiler total heat input (1012 Btu) from NURF
SO2 1985 boiler SO2 emissions (tons) from NURF
SO2CATEG 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)
SCRUBBER Boiler SO2 scrubber flag (1 =yes, 0=no, 9=no information)
FELIM85 1985 boiler SO2 emission limit (Ibs/MMBtu)
ANNFACT 1985 SO2 emission limit annualization factor
AVGPD 1985 SO2 emission limit averaging period
NAMEPCAP 1989 existing and planned generator nameplate capacity (MW)
SUMNDCAP 1989 generator summer net dependable capability (MW)
GENMNONL Generator month on-line
GENYRONL Generator year on-line
BLRMNONL Boiler month on-line
BLRYRONL Boiler year on-line
BASE8587 1985-1987 boiler-generator average total heat input, "baseline"
(1012Btu)
OUTAGEHR Consecutive planned and forced outage time during 1985-1987
>= 2,920 hours (hours)
PRIMFUEL Primary fuel indicator based on greatest fuel heat share during
1985-1987 (1=coal>50%, 2=oil/gas)
GAS8089 1980-1989 gas share (%)
HEATRATE 1989 generator full load heat rate (Btu/kWh)
GENER 1985 generator generation (GWh)
UCAPFSST Total capacity of the fossil-steam units of the operating utility (MW)
MXBS8089 Maximum of the average heat inputs for any combination of three
consecutive years from 1980-1989 for selected units (1012 Btu)
RY_ER Representative year SO2 emission rate (Ibs/MMBtu)
FLAGMUNI Municipally operated flag (1=yes, 0=no)
SO2RTE 1985 boiler SO2 emission rate (Ibs/MMBtu)
ANNLIM85 1985 annualized boiler SO2 emission limit (Ibs/MMBtu)
HT60 Generator heat input at 60 percent capacity (1012 Btu)
HT60SHR Boiler-generator share of generator heat input at 60 percent
capacity (1012 Btu)
18
-------
Table 2
Sample NADBV22 Data
SEQ
1281
1282
1283
1284
1285
1286
1287
1288
1289
1290
SEQ
1281
1282
1283
1284
1285
1286
1287
1288
1289
1290
SEQ
1281
1282
1283
1284
1285
1286
1287
1288
1289
1290
SEQ
1281
1282
1283
1284
1285
1286
1287
1288
1289
1290
STATNAM
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
KANSAS
CNTYNAME
WYANDOTTE
SEDGWICK
SEDGWICK
SEDGWICK
CHEROKEE
CHEROKEE
CHEROKEE
CHEROKEE
CHEROKEE
GRAHAM
PNAME
QUINDARO
RIPLEY
RIPLEY
RIPLEY
RIVERTON
RIVERTON
RIVERTON
RIVERTON
RIVERTON
ROSS BEACH
ORISPL
1295
1244
1244
1244
1239
1239
1239
1239
1239
1228
NAMEPCAP SUMNDCAP
157.50
23.00
31.30
33.00
10.00
12.50
37.50
50.00
25.00
11.50
135.00
26.90
30.40
34.50
11.00
9.00
38.10
53.20
31.50
12.00
128.96
0.00
0.00
0.00
0.00
0.00
177.81
286.59
3.41
0.04
661.00
961.00
961.00
961.00
344.00
344.00
344.00
344.00
344.00
62.00
0.000000
0.000000
0.000000
0.000000
0.000000
0.000000
0.000000
0.000000
0.000000
0.000000
BLRID
2
"1
"2
"3
LP
LP
39
40
41
1
GENID
ST2
1
2
3
3
4
7
UTILNAME
KANSAS CITY CITY OF
KANSAS GAS & ELECTRIC CO.
KANSAS GAS & ELECTRIC CO.
KANSAS GAS & 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.
UCODE
GENMNONL
11
7
4220
0
0
0
0
0
0
0
0
0
GENYRONL
1971
1938
1948
1949
1923
1941
1950
1954
1939
1954
RY_ER
0.0000
0.0006
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0006
1.523439
0.002388
0.003250
0.003426
0.001118
0.001118
2.187371
3.603229
0.082823
0.002100
BLRMNONL
11
7
9
8
5
5
5
5
5
0
3254.71
0.00
0.00
0.00
0.00
0.00
4877.00
8035.00
0.00
0.00
BLRYRONL
1971
1938
1948
1949
1923
1923
1950
1954
1939
1954
FLAGMUNI
1
0
0
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
BASE8587
3.381038
0.000796
0.001083
0.001142
0.000241
0.000302
1.978993
3.358551
0.045559
0.001847
SO2RTE
4.2728
0.0000
0.0000
0.0000
0.0000
0.0000
4.4592
4.4599
0.0000
0.0000
SCRUBBER
0
0
0
0
0
0
0
0
0
0
OUTAGEHR
3833
0
0
0
0
0
0
0
0
0
2.6700
3.0000
3.0000
3.0000
3.0000
3.0000
2.6700
2.6700
3.0000
99.9000
FELIM85
3.0000
3.0000
3.0000
3.0000
3.0000
3.0000
3.0000
3.0000
3.0000
99.9000
PRIMFUEL
1
2
2
2
2
2
1
1
2
2
HT60
6.740820
1.413864
1.597824
10.565672
1.734480
1.442772
2.503170
3.551164
3.145716
0.788400
10005
10005
10005
5860
5860
5860
5860
5860
12524
ANNFACT
0.89
1.00
1.00
1.00
1.00
1.00
0.89
0.89
1.00
1.00
GAS8089
0.000
81.170
81.170
81.170
3.610
3.610
0.000
0.000
3.610
94.080
HT60SHR
6.740820
1.413864
1.597824
10.565672
1.734480
1.442772
2.503170
3.551164
3.145716
0.788400
EPARGN
7
7
7
7
7
7
7
7
7
7
3
0
0
0
0
0
3
3
0
0
HEATRATE
9500.00
10000.00
10000.00
58267.00
30000.00
30500.00
12500.00
12700.00
19000.00
12500.00
-------
Table 3
State Summaries for Selected Variables
St.
AL
AR
AZ
CA
CO
CT
DC
DE
FL
GA
IA
ID
IL
IN
KS
KY
LA
MA
MD
ME
Ml
MN
MO
MS
MT
NC
ND
NE
NH
NJ
NM
NV
NY
OH
OK
OR
PA
Rl
SC
SD
TN
TX
UT
VA
VT
WA
Wl
WV
WY
US
Num. SO2RTE SO2
Blr. (Ibs/MMBtu) (tons)
51
22
47
151
57
28
2
16
167
50
73
0
114
115
88
72
91
45
52
16
118
77
85
43
9
51
24
36
8
61
47
27
124
171
51
1
92
5
35
13
37
295
19
34
5
22
114
33
19
2,913
2.04
0.66
0.68
0.01
0.58
0.95
1.10
1.35
1.43
2.95
1.75
0.00
3.11
3.62
0.99
2.49
0.34
1.67
2.06
0.95
1.32
1.07
4.02
1.31
0.35
1.40
1.26
0.87
2.80
1.08
0.50
0.59
1.22
4.02
0.44
0.80
2.12
0.69
1.57
2.25
3.26
0.49
0.32
1.35
0.25
1.67
2.41
2.48
0.74
1.75
534,467.6
72,860.4
112,376.4
4,425.1
82,110.4
60,339.0
820.3
68,334.0
531,260.1
998,292.0
197,527.5
0.0
1 ,044,936.9
1 ,496,251 .0
133,480.3
783,331 .7
79,232.9
245,541.1
215,678.4
10,261.7
408,838.7
111,135.3
961 ,359.7
102,033.3
16,152.1
343,326.6
144,763.0
47,915.2
75,853.0
101,783.7
73,778.7
40,584.6
413,061.3
2,217,423.1
90,925.1
2,777.1
1,173,882.9
2,343.0
155,863.4
33,699.3
802,030.0
559,165.0
23,290.0
131,224.5
1,212.1
68,772.9
379,745.0
951 ,464.5
137,424.0
16,243,354.1
TOTHT
(1012 Btu)
523.3
222.4
330.1
685.3
285.5
127.7
1.5
101.3
743.1
677.6
226.1
0.0
672.7
826.2
269.5
629.8
473.6
294.1
209.6
21.6
620.2
207.0
478.8
156.2
93.1
490.7
230.1
110.8
54.3
189.2
294.9
138.8
678.7
1,103.2
417.5
6.9
1,106.1
6.8
198.5
29.9
492.9
2,266.5
148.0
194.1
9.8
82.2
315.1
766.9
370.7
18,578.8
GENER
(GWh)
51 ,445.0
21,231.8
31,583.1
66,286.7
26,393.9
12,368.5
90.0
8,102.7
72,600.0
68,989.2
20,308.8
0.0
74,006.4
79,006.9
23,341.1
60,127.6
41 ,573.3
28,664.3
20,622.6
2,060.7
60,856.6
18,990.6
45,895.9
14,710.0
8,524.9
63,362.3
21,715.4
10,282.2
5,074.1
20,244.4
27,221 .4
12,465.1
62,345.8
109,888.6
40,787.0
641.2
109,332.9
580.5
19,929.5
2,523.0
50,345.8
213,577.7
13,483.7
19,062.6
326.5
8,171.5
29,620.6
79,302.1
34,590.6
1,812,655.3
Num. NAMEPCAP
Gen. (MW)
51
22
45
126
59
25
2
16
164
49
74
0
98
98
96
69
90
40
49
14
109
80
81
42
9
47
21
37
7
54
48
27
104
165
49
1
83
6
35
13
37
286
22
33
5
10
107
33
19
2,757
13,404.5
6,609.1
8,498.1
22,558.2
6,068.2
3,382.2
580.0
1,914.9
30,572.7
13,534.3
6,760.9
0.0
21,439.1
22,910.9
8,010.5
17,821.0
15,823.8
6,282.9
9,519.7
1 ,069.0
16,346.1
6,628.8
14,028.9
5,804.6
2,589.8
12,556.3
4,536.0
3,919.9
1 ,048.2
7,737.9
5,750.8
4,986.4
18,617.7
27,155.2
12,852.8
560.5
23,859.6
242.9
6,838.2
882.0
10,020.4
67,584.5
5,354.1
7,457.8
84.0
1 ,678.2
10,129.2
14,958.3
5,894.7
516,864.3
Num.
Unit
53
22
47
202
104
37
2
22
182
50
110
0
207
153
115
75
139
68
57
16
204
125
109
57
9
51
27
46
8
70
56
27
182
266
53
1
124
9
35
21
37
328
26
34
5
53
166
33
19
3,842
BASE8587
(1012 Btu)
517.3
233.6
292.8
598.2
285.2
129.3
2.5
103.6
848.4
668.3
230.2
0.0
673.0
829.8
267.0
654.9
433.9
308.2
231.3
25.3
662.8
208.7
479.4
156.8
121.4
482.3
232.0
109.6
54.3
177.5
284.2
165.0
687.8
1,140.0
408.4
2.3
1,102.8
8.5
208.7
22.2
497.7
2,234.2
188.0
217.1
2.6
78.9
329.9
763.1
352.8
18,711.5
20
-------
Table 4
EPA Region Summaries for Selected Variables
EPA
Rgn
1
2
3
4
5
6
7
8
9
10
US
Num. S02RTE SO2
Blr. (Ibs/MMBtu) (tons)
107
185
229
506
709
506
282
141
225
23
2,913
1.54
1.19
2.14
2.17
3.02
0.48
2.47
0.76
0.27
1.61
1.75
395,549.9
514,845.0
2,541 ,404.6
4,250,604.8
5,658,330.1
875,962.0
1 ,340,282.8
437,438.7
157,386.2
71,550.1
16,243,354.1
TOTHT
(1012 Btu)
514.4
867.9
2,379.4
3,912.0
3,744.4
3,675.0
1 ,085.2
1,157.3
1,154.3
89.1
18,578.8
GENER
(GWh)
49,074.6
82,590.2
236,513.0
401 ,509.3
372,369.7
344,391 .3
99,828.1
107,231.4
110,334.9
8,812.7
1,812,655.3
Num.
Gen.
97
158
216
494
657
495
288
143
198
11
2,757
NAMEPCAP
(MW)
12,109.3
26,355.6
58,290.3
110,552.0
104,609.4
108,621.1
32,720.2
25,324.8
36,042.8
2,238.7
516,864.3
Num.
Unit
143
252
272
540
1,121
598
380
206
276
54
3,842
BASE8587
(1012 Btu)
528.3
865.4
2,420.2
4,034.3
3,844.2
3,594.5
1 ,086.2
1,201.5
1 ,055.9
81.2
18,711.5
21
-------
Table 5
Operating Utility Summaries for Selected Variables
to
to
Operating Utility
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 CITY OF
AUSTIN CITY OF (MN)
AUSTIN CITY OF (TX)
BALTIMORE GAS & ELECTRIC CO
BANGOR HYDRO-ELECTRIC CO
BASIN ELECTRIC POWER COOP
BIG RIVERS ELECTRIC CORP
BLACK HILLS CORP
BLUE EARTH CITY OF
BOSTON EDISON CO
BRAZOS ELECTRIC POWER COOP INC
BREESECITYOF
BROWNSVILLE PUBLIC UTILS BOARD
BRYAN CITY OF
BURBANKCITYOF
BURLINGTON CITY OF
CAJUN ELECTRIC POWER COOP INC
CAMBRIDGE ELECTRIC LIGHT CO
CANAL ELECTRIC CO
CARDINAL OPERATING COMPANY
S02RTE
(Ibs/MMBtu)
1.13
1.93
0.00
0.00
4.43
1.25
1.13
0.66
0.51
0.00
0.61
4.73
2.49
0.00
2.68
0.00
1.54
2.28
0.64
2.26
1.01
0.00
0.82
0.00
0.00
0.00
0.02
0.01
0.25
0.94
0.24
2.35
3.79
S02
(tons)
14,205.0
354,319.0
1.0
0.0
22,283.0
1 ,458.0
163,634.0
5,599.0
47,605.0
0.0
58,375.0
258,941 .0
43,151.0
0.0
1 ,078.0
7.0
49,584.0
603.0
52,886.0
126,000.0
4,723.0
0.0
30,634.0
3.0
0.0
0.0
39.0
7.0
1,212.0
41 ,465.0
459.0
69,049.0
159,563.0
TOTHT
(1012 Btu)
25.0
367.0
2.0
0.0
10.0
2.0
290.0
17.0
185.0
0.0
192.0
109.0
35.0
0.0
1.0
24.0
64.0
1.0
166.0
111.0
9.0
0.0
75.0
18.0
0.0
0.0
4.0
2.0
10.0
89.0
4.0
59.0
84.0
GENER
(GWh)
2,341.0
36,362.0
142.0
0.0
0.0
217.0
30,865.0
1,581.0
17,567.0
23.0
18,388.0
10,654.0
2,856.0
0.0
60.0
2,184.0
6,263.0
39.0
15,541.0
10,418.0
604.0
0.0
7,280.0
1,671.0
0.0
16.0
314.0
150.0
327.0
7,290.0
177.0
5,923.0
8,752.0
UCAPFSSr
(MW)
572.0
8,775.0
175.0
8.0
200.0
98.0
5,722.0
464.0
4,059.0
315.0
5,636.0
2,335.0
784.0
5.0
32.0
1 ,534.0
2,693.0
57.0
3,286.0
2,004.0
115.0
0.0
1 ,804.0
437.0
2.0
47.0
221.0
167.0
50.0
1 ,909.0
86.0
1 ,072.0
1 ,880.0
Num.
Unit
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
BASE8587
(1012 Btu)
26.0
352.0
2.0
0.0
10.0
3.0
275.0
13.0
194.0
0.0
205.0
105.0
36.0
0.0
1.0
22.0
77.0
1.0
180.0
108.0
9.0
0.0
84.0
16.0
0.0
1.0
4.0
3.0
3.0
70.0
4.0
58.0
90.0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
to
OJ
Operating Utility
CARLYLE CITY OF
CAROLINA POWER & LIGHT CO
CEDAR FALLS CITY OF
CENTELCORP
CENTRAL ELECTRIC POWER COOP
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
CHANUTE CITY OF
CHILLICOTHE MUNICIPAL UTILS
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
COLUMBIA CITY OF
COLUMBUS CITY OF
COLUMBUS SOUTHERN POWER CO
COMMONWEALTH EDISON CO
COMMONWEALTH EDISON CO IN INC
COMMONWEALTH ELECTRIC CO
CONNECTICUT LIGHTS POWER CO
CONSOLIDATED EDISON CO-NY INC
CONSUMERS POWER CO
S02RTE
(Ibs/MMBtu)
0.00
1.32
3.66
0.38
5.93
1.47
1.28
4.10
4.90
0.46
0.92
0.01
1.46
0.15
0.00
0.00
6.50
2.52
0.00
0.00
0.00
4.46
0.00
1.29
0.64
6.31
1.23
3.44
2.19
0.86
0.33
0.86
0.16
1.76
S02
(tons)
0.0
162,756.0
129.0
1 ,486.0
8,373.0
52,498.0
32,809.0
232,344.0
7,803.0
17,063.0
9,647.0
1.0
29,245.0
12,240.0
0.0
0.0
1 ,323.0
177,256.0
0.0
0.0
0.0
312,472.0
0.0
333.0
9,089.0
1 ,952.0
1 ,784.0
169,299.0
273,639.0
9,651.0
250.0
31 ,075.0
13,298.0
142,740.0
TOTHT
(1012 Btu)
0.0
246.0
0.0
8.0
3.0
71.0
51.0
113.0
3.0
74.0
21.0
0.0
40.0
168.0
0.0
0.0
0.0
141.0
0.0
0.0
0.0
140.0
0.0
1.0
29.0
1.0
3.0
98.0
250.0
23.0
2.0
72.0
169.0
162.0
GENER
(GWh)
0.0
36,888.0
5.0
528.0
281.0
7,070.0
5,047.0
1 1 ,042.0
261.0
7,096.0
2,022.0
22.0
4,182.0
16,547.0
0.0
3.0
17.0
14,314.0
1.0
16.0
0.0
13,536.0
34.0
20.0
2,704.0
96.0
694.0
9,432.0
32,381 .0
2,262.0
151.0
6,804.0
12,020.0
16,932.0
UCAPFSSr
(MW)
0.0
5,545.0
52.0
356.0
59.0
1 ,774.0
1,221.0
3,154.0
63.0
2,520.0
993.0
109.0
1,106.0
3,804.0
0.0
14.0
11.0
3,269.0
24.0
10.0
160.0
3,063.0
80.0
11.0
552.0
74.0
90.0
2,281.0
10,479.0
614.0
63.0
2,172.0
5,628.0
4,430.0
Num.
Unit
1
24
2
9
2
6
10
15
2
9
11
1
5
24
1
11
2
25
6
3
10
31
13
3
17
9
24
11
26
2
3
22
69
23
BASE8587
(1012 Btu)
0.0
241.0
0.0
7.0
2.0
72.0
52.0
106.0
3.0
87.0
25.0
0.0
38.0
160.0
0.0
0.0
0.0
139.0
0.0
0.0
0.0
141.0
0.0
0.0
30.0
1.0
4.0
87.0
257.0
21.0
2.0
72.0
178.0
175.0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
S02RTE
Operating Utility (Ibs/MMBtu)
COOP POWER ASSN
CORN BELT POWER COOP
CRAWFORDSVILLE ELEC LGT&PWR CO
CRISP COUNTY POWER COMM
CULPEPERTOWNOF
DAIRYLAND POWER COOP
DAYTON POWER & LIGHT CO
DELMARVA POWER & LIGHT CO
DENISONCITYOF
DENTON CITY OF
DESERET GENERATION & TRAN COOP
DETROIT CITY OF
DETROIT EDISON CO
DOVER CITY OF (DE)
DOVER CITY OF (OH)
DUKE POWER CO
DUQUESNE LIGHT CO
EAST KENTUCKY POWER COOP INC
EASTON UTILITIES COMM
EL PASO ELECTRIC CO
ELECTRIC ENERGY INC
EMPIRE DISTRICT ELECTRIC CO
FAIRBURY CITY OF
FAIRFIELDCITYOF
FAIRMONT PUBLIC UTILITIES COMM
FARMINGTON CITY OF
FLORIDA POWER & LIGHT CO
FLORIDA POWER CORP
FORT PIERCE UTILITIES AUTH
FREMONT CITY OF
GAINESVILLE REGIONAL UTILITIES
GARLAND CITY OF
GEORGIA POWER CO
GLENDALE CITY OF
1.10
5.04
4.82
1.27
0.00
2.90
2.08
1.33
0.00
0.04
0.00
0.38
1.18
2.01
3.58
1.49
1.59
2.21
0.00
0.00
3.32
8.42
0.00
0.00
1.82
0.00
0.37
1.30
0.02
0.88
0.98
0.01
3.00
0.04
S02
(tons)
38,294.0
498.0
1 ,970.0
285.0
0.0
57,917.0
167,147.0
66,456.0
0.0
34.0
0.0
606.0
221 ,496.0
3,748.0
3,105.0
190,216.0
45,223.0
73,274.0
0.0
2.0
108,384.0
81,681.0
0.0
0.0
315.0
0.0
34,580.0
112,412.0
17.0
1,310.0
9,427.0
38.0
980,798.0
25.0
TOTHT
(1012 Btu)
70.0
0.0
1.0
0.0
0.0
40.0
161.0
100.0
0.0
2.0
0.0
3.0
377.0
4.0
2.0
256.0
57.0
66.0
0.0
14.0
65.0
19.0
0.0
0.0
0.0
0.0
186.0
174.0
2.0
3.0
19.0
7.0
654.0
1.0
GENER
(GWh)
6,020.0
12.0
46.0
5.0
0.0
3,755.0
16,208.0
8,014.0
0.0
119.0
59.0
243.0
37,135.0
263.0
62.0
27,627.0
5,275.0
6,357.0
0.0
1 ,320.0
6,250.0
1 ,729.0
0.0
0.0
9.0
16.0
18,167.0
17,739.0
115.0
254.0
1 ,757.0
709.0
66,838.0
126.0
UCAPFSSr
(MW)
1,012.0
97.0
24.0
13.0
0.0
962.0
3,521.0
1 ,782.0
0.0
174.0
400.0
154.0
9,775.0
151.0
20.0
7,573.0
1 ,487.0
1,310.0
0.0
671.0
1,100.0
344.0
19.0
5.0
23.0
32.0
9,388.0
4,570.0
106.0
130.0
420.0
441.0
12,927.0
108.0
Num.
Unit
2
5
2
1
1
21
33
20
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
BASE8587
(1012 Btu)
65.0
0.0
1.0
0.0
0.0
40.0
182.0
103.0
0.0
1.0
12.0
3.0
406.0
4.0
1.0
253.0
56.0
69.0
0.0
16.0
55.0
18.0
0.0
0.0
0.0
0.0
240.0
191.0
1.0
3.0
18.0
7.0
645.0
2.0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
Operating Utility
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
HAMILTON CITY OF
HASTINGS CITY OF
HENDERSON CITY UTILITY COMM
HIBBING 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
IOLACITYOF
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
S02RTE
(Ibs/MMBtu)
0.00
0.32
0.98
0.69
0.53
1.82
3.59
0.19
0.00
1.19
0.91
4.66
1.24
1.27
0.58
2.14
0.00
1.90
0.27
4.44
0.02
4.56
2.97
5.61
3.08
3.24
0.00
3.90
1.00
0.94
1.79
1.36
1.44
2.20
S02
(tons)
0.0
600.0
1,521.0
1 1 ,732.0
14.0
1 ,078.0
129,375.0
19,680.0
0.0
1,719.0
1 ,052.0
1 ,589.0
912.0
2,942.0
234.0
9,805.0
0.0
57,071 .0
65,769.0
358,627.0
44.0
14,839.0
156,911.0
268,862.0
178,887.0
46,860.0
0.0
28,474.0
20,058.0
29,275.0
35,285.0
16,389.0
17,776.0
2,920.0
TOTHT
(1012 Btu)
0.0
4.0
3.0
34.0
0.0
1.0
72.0
209.0
0.0
3.0
2.0
1.0
1.0
5.0
1.0
9.0
0.0
60.0
480.0
162.0
4.0
7.0
106.0
96.0
116.0
29.0
0.0
15.0
40.0
62.0
39.0
24.0
25.0
3.0
GENER
(GWh)
0.0
340.0
260.0
3,123.0
29.0
73.0
6,901.0
18,703.0
0.0
232.0
157.0
37.0
42.0
339.0
2.0
1 ,037.0
0.0
5,544.0
46,318.0
16,563.0
333.0
306.0
10,479.0
9,777.0
10,196.0
2,511.0
8.0
955.0
3,848.0
5,903.0
3,654.0
1 ,888.0
2,257.0
382.0
UCAPFSSr
(MW)
0.0
80.0
208.0
1,010.0
99.0
54.0
1 ,667.0
6,987.0
35.0
111.0
115.0
44.0
31.0
62.0
25.0
136.0
0.0
1,313.0
12,307.0
3,749.0
189.0
148.0
4,196.0
1 ,304.0
3,071.0
762.0
11.0
494.0
1,091.0
1 ,686.0
938.0
879.0
3,123.0
58.0
Num.
Unit
1
3
4
2
3
18
11
82
12
8
3
2
9
5
12
1
1
4
68
59
4
5
7
6
61
14
3
42
6
5
5
10
13
8
BASE8587
(1012 Btu)
0.0
3.0
3.0
40.0
1.0
1.0
78.0
204.0
0.0
3.0
2.0
1.0
1.0
4.0
0.0
11.0
0.0
56.0
475.0
169.0
4.0
5.0
103.0
96.0
134.0
29.0
0.0
16.0
40.0
54.0
42.0
33.0
42.0
3.0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
S02RTE
Operating Utility (Ibs/MMBtu)
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
LAKE WORTH CITY OF
LAKELAND CITY OF
LAMAR CITY OF
LANSING BOARD OF WATER & LIGHT
LARNEDCITYOF
LAWRENCE PARK HEAT LGT&PWR CO
LEA COUNTY ELECTRIC COOP INC
LITCHFIELD PUBLIC UTILITY COMM
LOGANSPORTCITYOF
LONG ISLAND LIGHTING CO
LOS ANGELES CITY OF
LOUISIANA POWER & LIGHT CO
LOUISVILLE GAS & ELECTRIC CO
LOWER COLORADO RIVER AUTHORITY
LUBBOCKCITYOF
LUVERNECITYOF
MADISON GAS & ELECTRIC CO
MAINE PUBLIC SERVICE CO
MANITOWOC CITY OF
MARQUETTE CITY OF
MARSHALL CITY OF
MARSHFIELDCITYOF
5.07
0.08
2.19
2.44
0.00
0.71
1.95
2.94
2.41
0.00
0.00
0.00
0.02
0.45
0.00
1.17
0.00
0.00
0.00
0.00
1.85
1.74
0.01
0.01
3.09
0.62
0.00
0.00
1.78
2.73
2.29
0.58
5.97
3.19
S02
(tons)
3,514.0
897.0
28,397.0
172,021.0
3.0
53,612.0
41 ,549.0
171,706.0
5,892.0
0.0
0.0
0.0
12.0
6,235.0
0.0
14,361.0
0.0
0.0
0.0
0.0
1 ,487.0
108,906.0
440.0
979.0
130,182.0
32,637.0
0.0
0.0
1 ,826.0
11.0
2,393.0
929.0
3,360.0
1 ,959.0
TOTHT
(1012 Btu)
1.0
24.0
26.0
141.0
11.0
152.0
43.0
117.0
5.0
0.0
0.0
7.0
1.0
28.0
1.0
25.0
0.0
0.0
0.0
0.0
2.0
125.0
66.0
151.0
84.0
106.0
7.0
0.0
2.0
0.0
2.0
3.0
1.0
1.0
GENER
(GWh)
82.0
4,800.0
2,137.0
13,075.0
994.0
13,353.0
4,278.0
10,802.0
350.0
0.0
0.0
335.0
76.0
2,616.0
4.0
2,244.0
10.0
0.0
0.0
0.0
117.0
12,075.0
6,199.0
14,041.0
8,001.0
10,492.0
566.0
0.0
168.0
0.0
39.0
234.0
94.0
64.0
UCAPFSSr
(MW)
15.0
668.0
661.0
3,458.0
961.0
3,426.0
1 ,097.0
3,404.0
97.0
0.0
0.0
379.0
67.0
670.0
33.0
611.0
13.0
0.0
49.0
3.0
43.0
2,731.0
5,017.0
4,697.0
3,075.0
2,775.0
143.0
3.0
436.0
19.0
79.0
77.0
27.0
35.0
Num.
Unit
1
31
6
19
12
16
2
24
8
1
1
5
4
9
3
19
5
1
2
1
2
15
23
16
13
7
7
1
23
2
25
3
5
5
BASE8587
(1012 Btu)
1.0
21.0
25.0
142.0
8.0
152.0
48.0
125.0
5.0
0.0
0.0
6.0
1.0
22.0
1.0
27.0
0.0
0.0
0.0
0.0
1.0
128.0
100.0
134.0
87.0
103.0
7.0
0.0
2.0
0.0
3.0
3.0
1.0
1.0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
S02RTE
Operating Utility (Ibs/MMBtu)
MCPHERSON CITY OF
MEDINA ELECTRIC COOP INC
MENASHA CITY OF
METROPOLITAN EDISON CO
MICHIGAN SOUTH CENTRAL PWR AGY
MIDWEST ENERGY INC
MINDENCITYOF
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
MOORHEAD CITY OF
MORGAN CITY CITY OF
MT PLEASANT CITY OF
MULVANE CITY OF
MUSCATINE CITY OF
MUSCODA CITY OF
NATCHITOCHES CITY OF
NEBRASKA PUBLIC POWER DISTRICT
NEVADA POWER CO
NEW ENGLAND POWER CO
NEWORLEANS PUBLIC SERVICE INC
NEWULM PUBLIC UTILITIES COMM
NEW YORK STATE ELEC & GAS CORP
NIAGARA MOHAWK POWER CORP
NORTHERN INDIANA PUB SERV CO
NORTHERN STATES POWER CO
NORTHWESTERN PUBLIC SERVICE CO
OHIO EDISON CO
OHIO POWER CO
0.00
0.00
2.05
2.53
0.37
0.00
0.03
0.82
1.29
0.02
2.19
2.91
0.33
1.30
1.67
1.77
0.00
1.87
0.00
1.82
0.00
0.00
0.76
0.27
1.88
0.00
2.22
1.69
1.98
2.54
1.06
0.00
3.51
5.67
S02
(tons)
0.0
0.0
703.0
28,306.0
513.0
0.0
13.0
22,415.0
29,654.0
588.0
89,757.0
398,008.0
14,870.0
23,128.0
11,812.0
1.0
0.0
7.0
0.0
10,703.0
0.0
0.0
22,957.0
6,530.0
120,415.0
58.0
1 ,464.0
81 ,247.0
117,502.0
119,200.0
72,529.0
0.0
326,619.0
877,044.0
TOTHT
(1012 Btu)
0.0
1.0
1.0
22.0
3.0
0.0
1.0
55.0
46.0
50.0
82.0
274.0
91.0
36.0
14.0
0.0
0.0
0.0
0.0
12.0
0.0
0.0
61.0
49.0
128.0
30.0
1.0
96.0
119.0
94.0
137.0
0.0
186.0
310.0
GENER
(GWh)
0.0
77.0
44.0
2,151.0
219.0
0.0
1.0
5,478.0
4,021.0
4,479.0
7,968.0
27,380.0
8,341.0
3,018.0
1,313.0
20.0
29.0
0.0
0.0
1,121.0
0.0
0.0
5,785.0
4,559.0
12,523.0
2,703.0
73.0
10,860.0
1 1 ,042.0
8,578.0
12,532.0
0.0
18,222.0
32,637.0
UCAPFSSr
(MW)
49.0
66.0
22.0
652.0
55.0
62.0
25.0
1,311.0
734.0
2,733.0
2,160.0
5,173.0
2,533.0
600.0
300.0
25.0
70.0
11.0
0.0
276.0
2.0
43.0
1 ,735.0
884.0
2,648.0
1 ,092.0
21.0
1 ,429.0
3,576.0
3,768.0
4,284.0
0.0
3,604.0
6,475.0
Num.
Unit
4
3
4
5
1
9
2
10
4
10
12
14
6
15
9
1
4
4
2
5
1
3
21
18
17
5
3
20
20
17
56
3
37
13
BASE8587
(1012 Btu)
0.0
1.0
1.0
24.0
3.0
0.0
0.0
54.0
46.0
42.0
90.0
279.0
119.0
33.0
13.0
0.0
0.0
0.0
0.0
11.0
0.0
0.0
57.0
41.0
136.0
29.0
1.0
89.0
122.0
99.0
142.0
0.0
187.0
320.0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
to
oo
Operating Utility
OHIO VALLEY ELECTRIC CORP
OKLAHOMA GAS & ELECTRIC CO
OMAHA PUBLIC POWER DISTRICT
OPELOUSAS CITY OF
ORANGE & ROCKLAND UTILS INC
ORLANDO UTILITIES COMM
ORRVILLE CITY OF
OTTAWA CITY OF
OTTER TAIL POWER CO
OWATONNA CITY OF
OWENSBORO CITY OF
PACIFIC GAS & ELECTRIC CO
PACIFICORP
PAINESVILLE CITY OF
PASADENA CITY OF
PEABODY CITY OF
PELLACITYOF
PENNSYLVANIA ELECTRIC CO
PENNSYLVANIA POWER & LIGHT CO
PENNSYLVANIA POWER CO
PERU CITY OF (IL)
PERU CITY OF (IN)
PHILADELPHIA ELECTRIC CO
PIQUACITYOF
PLAINS ELEC GEN&TRANS COOP INC
PLAQUEMINECITYOF
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
S02RTE
(Ibs/MMBtu)
5.76
0.38
1.02
0.00
0.14
0.24
5.60
0.00
2.37
0.00
5.21
0.01
0.88
3.73
0.01
0.00
3.65
2.66
2.27
0.72
0.00
5.79
0.33
3.92
0.28
0.00
0.14
0.00
0.80
1.45
2.14
0.06
0.00
0.81
S02
(tons)
222,543.0
42,947.0
21 ,074.0
0.0
3,723.0
1 ,700.0
8,850.0
0.0
36,387.0
0.0
36,931 .0
968.0
217,498.0
2,953.0
12.0
0.0
2,570.0
505,453.0
328,875.0
58,453.0
0.0
1 ,727.0
9,710.0
5,729.0
2,353.0
0.0
1 ,399.0
0.0
2,777.0
3,273.0
177,943.0
633.0
0.0
104.0
TOTHT
(1012 Btu)
77.0
226.0
41.0
0.0
52.0
14.0
3.0
0.0
31.0
0.0
14.0
281.0
494.0
2.0
4.0
0.0
1.0
381.0
290.0
163.0
0.0
1.0
59.0
3.0
17.0
0.0
21.0
0.0
7.0
5.0
166.0
23.0
0.0
0.0
GENER
(GWh)
7,924.0
20,964.0
3,805.0
0.0
4,810.0
1 ,337.0
126.0
0.0
2,648.0
1.0
1 ,393.0
27,864.0
46,016.0
99.0
320.0
0.0
72.0
38,637.0
29,122.0
15,781.0
0.0
39.0
4,999.0
125.0
1,751.0
0.0
1 ,925.0
0.0
641.0
407.0
16,260.0
2,098.0
8.0
4.0
UCAPFSSr
(MW)
1 ,086.0
6,159.0
1,261.0
39.0
1 ,737.0
1,103.0
85.0
0.0
593.0
26.0
416.0
7,335.0
8,305.0
55.0
215.0
0.0
42.0
6,835.0
5,699.0
3,166.0
8.0
32.0
2,410.0
45.0
278.0
44.0
285.0
68.0
561.0
1,411.0
4,980.0
883.0
22.0
8.0
Num.
Unit
5
22
10
2
7
7
11
1
4
2
2
85
28
5
7
1
8
29
27
10
1
2
15
5
5
2
1
2
1
2
25
1
3
8
BASE8587
(1012 Btu)
75.0
219.0
44.0
0.0
55.0
20.0
2.0
0.0
22.0
0.0
16.0
235.0
454.0
2.0
4.0
0.0
1.0
387.0
289.0
162.0
0.0
1.0
53.0
2.0
14.0
0.0
20.0
0.0
2.0
5.0
171.0
24.0
1.0
0.0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
Operating Utility
PUBLIC SERV COMM OF YAZOO CITY
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 ELECTRIC&GAS CO
PUGET SOUND POWER & LIGHT CO
RATON PUBLIC SERVICE CO
REEDY CREEK IMPROVEMENT DIST
RICHLAND CENTER CITY OF
RICHMOND CITY OF
ROCHELLE MUNICIPAL UTILITIES
ROCHESTER GAS & ELECTRIC CORP
ROCHESTER PUBLIC UTILITIES
RUSSELL CITY OF
RUSTON CITY OF
SALT RIVER PROJ AG 1 & P DIST
SAN ANTONIO CITY OF
SAN DIEGO GAS & ELECTRIC CO
SAN MIGUEL ELECTRIC COOP INC
SAVANNAH ELECTRIC & POWER CO
SEATTLE CITY OF
SEBRING UTILITIES COMM
SEMINOLE ELECTRIC COOP INC
SHELBY CITY OF
SIERRA PACIFIC POWER CO
SIKESTON CITY OF
SLEEPY EYE PUBLIC UTILITY COMM
SOUTH CAROLINA ELECTRIC&GAS CO
SOUTH CAROLINA GENERTG CO INC
SOUTH CAROLINA PUB SERV AUTH
SOUTH MISSISSIPPI EL PWR ASSN
SOUTH TEXAS ELECTRIC COOP INC
S02RTE
(Ibs/MMBtu)
0.00
0.73
4.17
2.80
0.61
0.40
0.87
0.00
1.56
0.00
3.66
4.06
0.00
3.23
2.52
0.00
0.00
0.75
0.47
0.07
1.40
1.50
0.00
0.00
0.51
4.95
0.58
1.07
1.50
2.10
1.35
1.18
0.91
0.00
S02
(tons)
0.0
46,649.0
557,014.0
75,853.0
42,375.0
27,094.0
55,602.0
0.0
399.0
0.0
1 ,034.0
10,991.0
0.0
32,334.0
4,936.0
0.0
0.0
80,664.0
26,455.0
1,418.0
20,325.0
17,209.0
0.0
0.0
14,819.0
3,063.0
9,617.0
3,338.0
171.0
77,789.0
17,901.0
50,528.0
10,610.0
0.0
TOTHT
(1012 Btu)
0.0
127.0
267.0
54.0
139.0
136.0
128.0
0.0
1.0
0.0
1.0
5.0
0.0
20.0
4.0
0.0
1.0
215.0
112.0
44.0
29.0
23.0
0.0
0.0
59.0
1.0
33.0
6.0
0.0
74.0
27.0
86.0
23.0
1.0
GENER
(GWh)
0.0
1 1 ,765.0
26,403.0
5,074.0
12,294.0
14,686.0
12,410.0
0.0
25.0
0.0
26.0
473.0
0.0
1 ,990.0
343.0
0.0
41.0
20,692.0
10,630.0
3,944.0
2,534.0
2,147.0
0.0
3.0
6,005.0
83.0
3,278.0
553.0
4.0
7,353.0
3,058.0
8,365.0
2,190.0
43.0
UCAPFSSr
(MW)
18.0
2,475.0
6,219.0
1 ,048.0
2,010.0
3,570.0
4,400.0
88.0
11.0
44.0
0.0
93.0
12.0
334.0
99.0
0.0
81.0
3,760.0
3,476.0
1 ,946.0
410.0
595.0
0.0
13.0
1 ,304.0
38.0
974.0
261.0
2.0
1 ,903.0
633.0
2,425.0
577.0
22.0
Num.
Unit
2
68
40
8
13
16
19
6
3
1
4
2
2
35
4
2
3
16
25
16
2
8
42
1
2
6
7
2
2
18
1
12
9
1
BASE8587
(1012 Btu)
0.0
127.0
255.0
54.0
119.0
129.0
118.0
0.0
1.0
0.0
0.0
5.0
1.0
17.0
4.0
0.0
1.0
195.0
113.0
45.0
28.0
23.0
0.0
0.0
67.0
1.0
29.0
9.0
0.0
76.0
30.0
90.0
24.0
0.0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
OJ
o
S02RTE
Operating Utility (Ibs/MMBtu)
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 (IL)
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
TOLEDO EDISON CO
TRAVERSE CITY CITY OF
TRI-STATEG&TASSNINC
TRINIDAD CITY OF
TUCSON ELECTRIC POWER CO
TWO HARBORS CITY OF
U S ERDA-LOS ALAMOS AREA OFF
U S STEEL
UGICORP
UNION ELECTRIC CO
0.15
2.14
4.72
0.80
0.53
5.59
2.55
3.16
1.73
5.13
5.58
0.00
0.00
0.27
0.00
0.00
0.12
2.71
1.25
2.96
0.00
0.91
0.68
0.00
1.70
1.14
0.28
0.76
0.00
0.00
0.00
0.00
1.05
3.59
S02
(tons)
25,949.0
15,181.0
128,966.0
73,277.0
44,273.0
4,162.0
18,807.0
22,185.0
6.0
6,963.0
2,301.0
0.0
0.0
2,174.0
0.0
0.0
694.0
198,225.0
1,871.0
1,147,792.0
0.0
12,474.0
285,952.0
0.0
36,337.0
615.0
9,769.0
70.0
1.0
0.0
0.0
0.0
2,579.0
400,015.0
TOTHT
(1012 Btu)
341.0
14.0
55.0
184.0
168.0
1.0
15.0
14.0
0.0
3.0
1.0
0.0
0.0
16.0
0.0
0.0
12.0
146.0
3.0
775.0
2.0
28.0
840.0
0.0
43.0
1.0
70.0
0.0
5.0
0.0
1.0
0.0
5.0
223.0
GENER
(GWh)
31 ,977.0
1 ,250.0
5,013.0
17,043.0
16,619.0
112.0
1 ,280.0
1,172.0
0.0
91.0
44.0
5.0
0.0
1,414.0
0.0
0.0
1,012.0
14,163.0
220.0
77,792.0
112.0
2,278.0
76,484.0
0.0
4,633.0
73.0
6,469.0
6.0
411.0
0.0
50.0
0.0
300.0
21,881.0
UCAPFSSr
(MW)
10,470.0
272.0
1 ,268.0
4,786.0
3,999.0
22.0
443.0
447.0
7.0
151.0
19.0
23.0
55.0
469.0
25.0
50.0
464.0
3,325.0
123.0
17,647.0
79.0
444.0
18,510.0
236.0
947.0
32.0
1,918.0
8.0
585.0
0.0
20.0
0.0
50.0
6,126.0
Num.
Unit
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
10
7
2
11
1
9
1
1
63
BASE8587
(1012 Btu)
339.0
15.0
57.0
168.0
157.0
1.0
17.0
16.0
0.0
3.0
1.0
1.0
0.0
15.0
0.0
0.0
13.0
149.0
3.0
805.0
2.0
29.0
819.0
0.0
43.0
1.0
70.0
0.0
4.0
0.0
1.0
0.0
4.0
225.0
-------
Table 5 (continued)
Operating Utility Summaries for Selected Variables
S02RTE S02
Operating Utility (Ibs/MMBtu) (tons)
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
WINFIELDCITYOF
WINNETKA VILLAGE OF
WISCONSIN ELECTRIC POWER CO
WISCONSIN POWER & LIGHT CO
WISCONSIN PUBLIC SERVICE CORP
WOLVERINE PWR SUPPLY COOP INC
WYANDOTTE MUNICIPAL SERV COMM
UNITED STATES
1.06
1.36
1.75
5.71
0.15
1.59
1.21
2.05
0.47
0.00
0.00
0.00
3.01
0.01
0.84
0.98
1.65
0.00
2.55
2.36
2.15
1.97
2.04
1.08
1.75
29,258.0
10,783.0
3,080.0
35,663.0
97.0
2,134.0
1 ,357.0
215,270.0
6.0
0.0
0.0
0.0
195,284.0
96.0
9,152.0
3,355.0
757.0
0.0
984.0
179,151.0
115,574.0
34,693.0
2,608.0
1 ,497.0
16,243,354.1
TOTHT
(1012 Btu)
55.0
16.0
4.0
12.0
1.0
3.0
2.0
210.0
0.0
0.0
0.0
0.0
130.0
37.0
22.0
7.0
1.0
0.0
1.0
152.0
107.0
35.0
3.0
3.0
18,578.8
GENER
(GWh)
5,563.0
2,815.0
191.0
1,174.0
101.0
177.0
43.0
20,448.0
2.0
0.0
282.0
12.0
13,067.0
3,863.0
2,009.0
619.0
41.0
0.0
81.0
14,313.0
10,443.0
3,157.0
186.0
153.0
1,812,655.3
UCAPFSSr
(MW)
1 ,247.0
218.0
42.0
524.0
117.0
71.0
36.0
6,549.0
23.0
0.0
51.0
20.0
2,718.0
1 ,647.0
779.0
210.0
30.0
45.0
26.0
3,721.0
2,248.0
880.0
37.0
73.0
474,598.0
Num.
Unit
6
5
3
5
5
9
23
25
9
1
1
2
14
31
7
3
7
6
20
40
18
13
5
10
3,842
BASE8587
(1012 Btu)
57.0
15.0
3.0
15.0
1.0
2.0
1.0
249.0
0.0
0.0
4.0
0.0
127.0
54.0
20.0
7.0
1.0
0.0
1.0
159.0
111.0
39.0
2.0
3.0
18,711.5
NOTES: All fossil-fuel steam utility generators on-line in 1989 are included in this variable summary.
-------
32
-------
SECTION 4
SUPPLEMENTAL DATA FILE
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 an
additional data file, the Supplemental Data File (SDF). As was done with the NADB 2.1 Version, the SDF
corresponding to the NADBV211 was available for public comment from July 7, 1992 to September 8,
1992 (FR, 1992). Following the same procedure as that for reviewing the NADB, the SDF-related
documents submitted to the two EPA dockets were reviewed by EPA and the recommendations were
implemented.
The SDF for the NADBV22 (SDFV22) contains the same boiler-generator records that are in the
NADBV211. It is linked to the NADB through the variable SEQ which is in both files. Including SEQ,
there are 38 variables in the SDF, 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 complete information, see
Appendix G.
33
-------
34
-------
REFERENCES
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, 1982-1989.
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.
EIA, 1989b: Energy Information Administration, "Annual Electric Utility Report,"
FormEIA-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.
EPA, 1993: U.S. Environmental Protection Agency, "EPA Responses to Public Comments on Proposed
Allocation Rule and Notice of Availability of the NADB Version 2.1," March 1993.
FERC, 1985-1989: Federal Energy Regulatory Commission, "Monthly Report of Cost and Quality of
Fuels for Electric Plants," Form FERC-423, 1985-1989.
FPC, 1980-1981: Federal Power Commission, "Steam Electric Plant Air and Water Quality Control Data,"
FormFPC-67, 1980-1981.
FR, 1991: Federal Register, "Notice of Availability of the NADB Version 2.0," 56 FR 33278, July 19,
1991.
35
-------
FR, 1992: Federal Register, "Notice of Availability of the NADB Version 2.1," 57 FR 29939, July 7,
1992.
FR, 1993: Federal Register, "Acid Rain Program Final Rules," 58 FR3590, January 11, 1993.
FR, 1996: Federal Register, "Acid Rain Program: Permits, Allowance System, Sulfur Dioxide Opt-Ins,
Continuous Emission Monitoring, Excess Emissions, and Appeal Procedures," 61 FR 68340,
December 27, 1996.
FR, 1998: Federal Register, "Acid Rain Program: Proposed 1998 Reallocation of Allowances," 63 FR
0714,
January 7, 1998.
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," prepared for U.S. Environmental Protection Agency's Office of
Atmospheric and Indoor Air Programs, June 1991.
Pechan, 1992: E.H. Pechan & Associates, Inc., "The National Allowance Data Base Version 2.1:
Technical Support Document," prepared for U.S. Environmental Protection Agency's Office of
Atmospheric and Indoor Air Programs, May 1992.
Pechan, 1993: E.H. Pechan & Associates, Inc., "The National Allowance Data Base Version 2.11:
Technical Support Document," prepared for U.S. Environmental Protection Agency's Office of
Atmospheric Programs, March 1993.
PL, 1990: Public Law 101-549, 42 U.S.C. §7651a(4)(c), November 15, 1990.
Radian, 1991: Radian Corporation, "Development of Annualized SO2 Emission Conversion Factors,"
Contract No. 68-DO-0125, prepared for U.S. Environmental Protection Agency's Office of
Atmospheric and Indoor Air Programs, June 1991.
SAIC, 1990: Science Applications International Corporation, "Analysis of State and Federal Sulfur
Dioxide Site Specific Emission Regulations for Combustion Sources," Contract No. 68-02-4397,
Work Assignment 28, prepared for U.S. Environmental Protection Agency's Office of Air Quality
Planning and Standards, August 1990.
36
-------
APPENDIX A
EPA REGIONS
-------
-------
Table A-1
EPA Regions
Grouped By Region
(48 Contiguous States and District of Columbia)
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-1
-------
Table A-2
EPA Regions
Grouped By State
(48 Contiguous States and District of Columbia)
State
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
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 were
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 (boiler(s) feeding multiple generators and/or
generator(s) being fed by multiple boilers), the data handling was 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, so that plant records with the same boiler ID will
have the same value for those data elements.
Regardless of the type of boiler-generator correspondence, there are three variables whose value is
specific to each record in the NADBV22. These are the sequence number, SEQ (field 1), the 1985 to 1987
baseline, BASE8587 (field 25), and the shared heat input, HT60SHR (field 38). The specific baseline
value for each boiler-generator, for example, was obtained by apportioning the boiler based fuel data to
each generator, depending upon its fractional share of the total generation (or, if that was not reported, the
nameplate capacity) associated with that boiler. When Form EIA-759 plant-level data were apportioned to
each generator, these data were 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
SEQ
PNAME
BLRID
GENID
NAMEPCAP
S02
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 SEQs 9991 and
9992 because they have the same GENID, but it would be different for SEQs 9993 and 9994, since they
have different GENIDs. Conversely, boiler-related data (such as SO2 emissions) would be the same for
SEQs 9993 and 9994, but different for SEQs 9991 and 9992. The 1985 to 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 have be included. Whether the data element
was 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 SO2 emissions ~ boiler based data ~ it would
not be appropriate to sum the five records with SEQs 9991 through 9995, since the
boiler-level data for BLRID=3 appears in both the SEQ=9993 and SEQ=9994
records. Thus, the SO2 data from the four records with SEQs 9991 through 9993
and 9995 would be totaled for the plant SO2 emissions. The other non-
identification boiler based variables in addition to SO2 are TOTALPH1, TOTHT,
SO2CATEG, SCRUBBER, FELIM85, ANNFACT, AVGPD, BLRMNONL,
BLRYRONL, GAS8089, MXBS8089, RY_ER, SO2RTE, and ANNLIM85.
To calculate the plant's total nameplate capacity (including planned units) ~
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 SEQ=9991 and SEQ=9992, so the
plant capacity would be determined by totaling the NAMEPCAP data for the four
records with SEQs 9992 through 9995. The other non-identification generator
based variables in addition to NAMEPCAP are: SUMNDCAP, GENMNONL,
GENYRONL, HEATRATE, GENER, FLAGMUNI, and HT60.
B-2
-------
APPENDIX C
DBASE III PLUS NADBV22 FILE STRUCTURE
-------
-------
Field
Table C-1
DBASE III Plus NADBV22 File Structure
(File: NADBV22.DBF)
Name
Type
Width
Description
1
2
3
4
5
6
7
8
9
10
11
12
13
14
GG
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
SEQ
STATNAM
PNAME
BLRID
GENID
UTILNAME
UCODE
EPARGN
CNTYNAME
ORISPL
TOTALPH1
TOTHT
SO2
SO2CATEG
SCRUBBER
FELIM85
ANN FACT
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
5
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 (same as in NADBV211)
State name
Plant name
Boiler identification code
Generator identification code
Operating utility name
Operating utility code
EPA region
County name
DOE ORIS plant code
Total basic Phase 1 allowances (tons)
1985 boiler total heat input (1012 Btu)
1985 boiler SO2 emissions (tons)
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
for existing gas turbine, combined cycle with auxiliary firing)
Boiler SO2 scrubber flag (1=yes, 0=no, 9=no information)
1985 boiler SO2 emission limit (Ibs/MMBtu)
1985 SO2 emission limit annualization factor
1985 SO2 emission limit averaging period
1989 existing and planned generator nameplate capacity (MW)
1989 generator summer net dependable capability (MW)
Generator month on-line
Generator year on-line
Boiler month on-line
Boiler year on-line
1985-1987 boiler-generator average total heat input,
"baseline" (1012 Btu)
Consecutive planned and forced outage time during
1985-1987 >=2,920 hours (hours)
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 operated
by the operating utility in 1989 (MW)
Maximum of the average heat inputs for any
combination of three consecutive years from
1 980-1 989 for selected units (1 012 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)
C-1
-------
C-2
-------
APPENDIX D
CALCULATIONS FOR TOTHT, SO2, AND SO2RTE
-------
-------
APPENDIX D
CALCULATIONS FOR TOTHT, SO2, AND SO2RTE
The NADB 1985 SO2 emission rate (SO2RTE) was calculated from NADB 1985 SO2 emissions
(SO2) and NADB 1985 heat input (TOTHT). However, both TOTHT and SO2 were 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 utilized to calculate TOTHT and SO2, in addition to SO2RTE, 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) were recorded on a monthly (or daily) basis. In order to calculate on a yearly basis, these data
were converted to yearly data using the following method:
For each fuel, the total amount of fuel used for the year was calculated by adding
the monthly fuel used.
• The yearly heat and sulfur contents for each fuel were determined on a fuel use
weighted average. This weighted average was calculated by multiplying each
month's fuel use and associated heat (or sulfur) content, and then adding 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 + gas heat input (1)
(in!012Btu) 1012
Each fuel type heat input was calculated on a yearly basis using the following equation:
fuel heat = (fuel burned) * (wtd. av. heat content) * (conver. fact.) (2)
(in Btu)
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
-------
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 SO2 emissions (SO2) is as follows:
SO2 = (coal SO2 emissions) + (oil SO2 emissions) (3)
(in tons)
If gas is the only fuel, the SO2 gas emissions were assumed to be 0.
Each fuel type SO2 emissions was calculated on a yearly basis, using the equation:
fuel (fuel (yrly wtd. (AP-42 (1 - scrb. (units (4)
SO2 emissions = use) * av. fuel * fact-) * effic- 0//0 * 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 SO2/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/yr. If it is in bbl/yr, convert using 42 gal/bbl oil. The AP-42
factor (which accounts for the oil density), in Ibs SO2/thousand gal oil, is by oil type:
Oil Type AP-42 Factor
distillate (light) 142.6 lbs/1000 gal
residual (heavy) 159.3 lbs/1000 gal
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 was known, the equation for calculating the SO2
emission rate (SO2RTE) is as follows:
SO2RTE = 2 * (total SO, emissions in tons) (5)
(in Ibs/MMBtu) 1000 * (total heat input in 1012 Btu)
If the emission rate was known only for coal (from continuous emissions monitoring, for example), yet
oil was also burned, the following steps were taken to calculate the emissions rate for all the fuels:
D-2
-------
Use the coal SO2 rate (in Ibs/MMBtu) and coal heat input (in 1012 Btu) to "back
calculate" the coal SO2 emissions with the formula:
coal SO2 emissions = 1000 * (SO^ coal em. rate) * (coal heat input) (6)
(in tons) 2
Calculate the oil SO2 emissions using equation (4).
Sum the coal and oil SO2 emissions using equation (3).
Calculate the coal and oil heat inputs using equation (2) and sum them using
equation (1).
Calculate overall SO2 emission rate using equation (5).
D-3
-------
D-4
-------
APPENDIX E
ENFORCEABLE SO, EMISSION LIMIT DETERMINATIONS
-------
-------
APPENDIX E
ENFORCEABLE SO2 EMISSION LIMIT DETERMINATIONS
The source of federally enforceable limits was the preliminary SIP limit data base developed by
OAQPS. This data base (developed after a comprehensive review of all Federal, State, and local
regulations affecting combustion boilers was conducted) provided Federal emission limit information for
units in 1985, usually expressed in pounds of SO2 per million Btu. In certain cases, these limits were not
expressed in Ibs/MMBtu and were converted using the factors shown in Table E-l. Limits were rounded to
four decimal places.
In addition to emission limits, the data base provided the averaging periods over which these limits
were enforced. (These averaging periods were essential to EPA in its determination of annual allowable
1985 SO2 emission rates.) The 17 codes for the averaging period are listed in Table E-2. The data base
also includes the SO2 regulatory category affecting each unit. For further information, see the
documentation for the SIP database (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 SO2 (64). Limits expressed as a 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 were 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 were 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 were generally cases in which either the State never submitted the limits as
part of its SIP and/or EPA never approved the limits; these units were therefore considered not to have a
federally enforceable limit.
E-l
-------
Table E-1
Conversion Factors
(Emission Limits Converted to Ibs SO/MMBfu
by Multiplying as Below)
Plant Fuel Type
Unit Measurement
Bituminous
Coal
Subbituminous
Coal
Lignite
Coal
Oil
Ibs Sulfur/MMBtu 2.0 2.0 2.0 2.0
% Sulfur in fuel 1.66 2.22 2.86 1.07
ppmS02 0.00287 0.00384 - 0.00167
ppm Sulfur in fuel - - - 0.00334
tons S02/hour 2,000,000/(HEATRATE*SUMNDCAP*capacity factor)1
Ibs SO2/hour 1,000/(HEATRATE*SUMNDCAP*capacity factor)1
1 In these cases, if the limit was specified as the "site" limit, the summer net dependable capability for
the entire plant was used; otherwise, the summer net dependable capability for the unit was used.
Capacity factor was based on 1985 utilization [=(1985 EIA total heat input in 1012 Btu)/
(HEATRATE*SUMNDCAP*8760/109)]. For post-1985 units, a capacity factor of 0.65 was assumed.
The annualization factor for these cases was assumed to be 1.0.
Assumed Average Energy Content Conversion
Fuel Type Average Heat Content
Bituminous Coal 24.0 MMBtu/ton
Subbituminous Coal 18.0 MMBtu/ton
Lignite Coal 14.0 MMBtu/ton
Residual Oil 6.2 MMBtu/bbl
E-2
-------
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 specified
16 at all times
99.9 no Federal limit for coal units or unknown
E-3
-------
E-4
-------
APPENDIX F
METHODOLOGY FOR ANNUALIZATION
OF SO2 EMISSION LIMITS
-------
-------
APPENDIX F
METHODOLOGY FOR ANNUALIZATION OF SO2 EMISSION LIMITS
Annualization factors are used to develop annual equivalent SO2 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 than a year and at a specified statutory emissions level would require
a lower annual average SO2 emission rate (or annual equivalent SO2 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 was established by multiplying
each federally enforceable limit by an annualization factor that is determined by the averaging period and
whether unit the unit was scrubbed.
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 (CEM) 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
-------
Table F-1
SO2 Emission Averaging Period Codes and Annualization Factors
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 units 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
-------
APPENDIX G
TECHNICAL DOCUMENTATION
FOR THE
SUPPLEMENTAL DATA FILE
Prepared for:
U.S. Environmental Protection Agency
Office of Atmospheric Programs
Acid Rain Division
Washington, DC 20460
Prepared by:
ICF Incorporated
Fairfax, VA 22031
August 1998
-------
F-4
-------
-------
CONTENTS
1. Introduction G-3
2. Structure of the Supplemental Data File G-5
Introduction G-5
Variable Types G-5
List of Fields in Supplemental Data File G-6
Structure of the Supplemental Data File G-8
3. Provision Descriptions G-9
Introduction G-9
Section 404(h) G-10
Section 405(b)(3) G-12
Section 405(b)(4) G-14
Section 405(c)(3) G-16
Section 405(c)(5) G-17
Section 405(d)(5) G-19
Section 405(f)(2) G-20
Section 405(g)(4) G-22
Section 405(g)(5) G-23
Section 405(i)(l) G-25
Section 405(i)(2) G-26
Special Multi-headers G-30
4. Examples of SDF Data G-31
TABLES
Number
G-l SDF Data Fields G-6
G-2 SDF File Structure G-8
G-3 Sample SDF Data G-32
G-l
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ABBREVIATIONS AND ACRONYMS
BkWh Billion kilowatt-hours
Btu British thermal unit
CAA Clean Air Act
CFR Code of Federal Regulations
DOE U.S. Department of Energy
EIA Energy Information Administration
EPA U.S. Environmental Protection Agency
FERC Federal Energy Regulatory Commission
FGD Flue gas desulfurization
FPC Federal Power Commission
FR Federal Register
kW Kilowatt
kWh Kilowatt-hour
Ib Pound
MMBtu Million Btu
MW Megawatt
MWh Megawatt-hour
NADB National Allowance Data Base
PC personal computer
SDF Supplemental Data File
SO2 Sulfur dioxide
U.S.C. United States Code
G-2
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SECTION 1
INTRODUCTION
The Supplemental Data File (SDF) Version 2.2 was developed by the U.S. Environmental Protection
Agency (EPA) as an extension of the National Allowance Data Base (NADB) Version 2.2 to provide data
that were not included in the NADB that are needed to determine Phase 2 allowance allocations as specified
by the Clean Air Act (CAA).1
For more information regarding the methods of calculating Phase 2 allowances, please refer to
Technical Documentation for the 1998 Reallocation of Allowances, prepared for the U.S. Environmental
Protection Agency by ICF Incorporated.
While the NADB contains sufficient information to calculate Phase 2 allowance allocations for the
vast majority of affected units, there are some provisions in the CAA that require data not contained in the
NADB because they were typically only needed for a few units in order to determine eligibility or calculate
sulfur dioxide (SO2) allowances.
To ensure consistency and ease of overall calculations, the SDF is structured similarly to the NADB.
Accordingly, each record (or unit) in the SDF corresponds exactly to a record in the NADB. The SDF
contains several data elements from the NADB Version 2.2, referred to as "identification fields," which are
included to ease the task of matching information for specific units from the two files. Like the NADB, the
SDF also contains three other types of fields: data fields, calculated fields, and flag fields.
This appendix is presented in four sections, the first of which is this Introduction. Section 2 describes
the four different types of variables used in the SDF and includes a summary table showing content,
source, and type for each SDF data item. It also includes a table showing the dBASE III Plus format file
structure of the SDF. Section 3 describes each CAA provision that requires supplemental data for
allowance calculations, the specific eligibility requirements for each of the applicable provisions, and the
sources of the data. Section 4 presents sample data for all the fields in the SDF.
Note that all interpretations in this document regarding definitions of statutory terms and provisions,
unit eligibility, and the suitability of data sources were made by EPA and are consistent with the final acid
rain rules.
'PL, 1990: Public Law 101-549, 42 U.S.C. §7651a(4)(c), November 15, 1990.
G-3
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G-4
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SECTION 2
STRUCTURE OF THE SUPPLEMENTAL DATA FILE
INTRODUCTION
As noted in Section 1 of this appendix, the SDF is structured similarly to the NADB, with one record
for each boiler-generator combination. The file contains 3,842 records and 38 fields (variables). Each
record in the SDF corresponds exactly to a record in the NADB, facilitating the matching of data between
the two files. This section describes the structure of the SDF in three ways. First, the four SDF variable
types are described, and examples of each type are given. Second, an alphabetical list of variables is
presented, including the field name, a brief description, the source of the data, and the variable type.
Finally, the actual dBASE III Plus PC format file structure is listed.
VARIABLE TYPES
There are four types of data elements or variables included in the SDF — identification, data,
calculated, and flag variables:
! Identification variables are fields from the NADB that are used to identify units in the SDF.
These fields are mostly intended to ease the identification and selection of records during the
allowance allocation calculations. Examples of identification variables are SEQ (boiler-
generator sequence number) and PNAME (plant name).
! Data variables contain information collected by EPA's Energy Information Administration (EIA)
and EPA from forms, reports, or other documentation. These also include variables that EIA
calculated from data supplied by utilities on various forms. Examples include CMIN80 (1980
utility commercial/industrial sales in BkWh) and SPOP8088 (State population percentage
increase, 1980 to 1988).
! Calculated variables contain information calculated from the values in other NADB and SDF
fields, such as SMCOPCT (utility percent of capacity as small coal units).
! Flag variables are numeric fields with a width of 1 that hold one of two possible values. A value
of 1 indicates "Yes" or "the unit/utility meets the condition," while a value of 0 indicates "No" or
"the unit/utility does not meet the condition." For example, in the CONTUTIL field, a value of 1
indicates that the unit was owned by a utility that furnishes electricity, electric energy, steam, and
natural gas within an area consisting of a city and one contiguous county as stipulated under
§405(f)(2) of the CAA. A value of 0 indicates that the unit was not owned by such a utility.
G-5
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LIST OF FIELDS IN SUPPLEMENTAL DATA FILE
Table G-l shows a list of fields in the SDF, listed alphabetically by field name. For each field, the
field name, a brief description (including the applicable CAA provisions), the source of the data, and the
type of variable are listed.
Table G-1
SDF Data Fields
Field
Description
Source
Type
ATTAIN §405(b)(3): States with no nonattainment
areas
BIGUHARD §405(c)(5): "System" with big, hard-to-
scrub units.
BLRID Boiler ID
CCTGRNT §405(d)(5): Oil/gas unit awarded CCT grant
CMIN80 §405(i)(2): 1980 utility
Commercial/industrial sales
CMIN90 §405(i)(2): 1990 utility
commercial/industrial sales
CONSTYR §405(g)(4): Construction start year
CONTAUTH §405(f)(2): State authority serving
contiguous area
CONTUTIL §405(f)(2): Utility serving contiguous area
G2C8587 §405(g)(5): Units converting gas to coal,
1/85-12/87
GENID Generator ID
LIGNTPCT §405(b)(3): Unit fuel use, 1985-1987 lignite
percent share
O2C8085 §405(b)(4): Units converting oil to coal,
1/80-12/85
ORISPL DOE ORIS plant code
PNAME Plant name
PROHIBJD §405(b)(4): Units issued prohibition order
from burning oil
PROPIFUA §405(g)(5): Units received proposed or final
prohibition order
SEQ Record sequence number (Link to NADB)
SMCOPCT §405(c)(5): Utility percent of capacity as
coal units <75 MW
SO22000 §405(i)(2): SO2 emission rate as of
1/1/2000
SO2LIM80 §405(i)(2): 1980 SO2 limit
SO2LIM87 §405(g)(5): 1987 SO2 limit
40CFRPart81, SubpartC Flag
EVA Report on FGD Retrofit Flag
Cost Factors
NADB Identification
Office of Clean Coal Tech. Flag
Form EIA-412, FERC-1 Data
Form EIA-861 Data
Utility-Supplied Equipment Data
and/or Construction Contracts
Form EIA-767, Directory of Flag
Electric Utilities
Directory of Electric Utilities Flag
Inventory of Power Plants, Flag
1985 & 1987/Utility-Supplied
Documentation
NADB Identification
Calculated by EIA from Data
Form EIA-767
Inventory of Power Plants, Flag
1980 and 1985
NADB Identification
NADB Identification
Office of Coal and Electricity Flag
Prohibition Order Data Base
Office of Coal and Electricity Flag
Prohibition Order Data Base
NADB Identification
Calculated from NADB Data Calculated
Assumed <1.2, per EPA's Data
interpretation
Utility-Supplied Data
Documentation of
Regulations/Permits
Utility-Supplied Data
Documentation of
Regulations/Permits
G-6
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Field
Description
Source
Type
SO2LIM90 §405(i)(2): 1990 SO2 limit
SO2RTE80 §404(h)&405(i)(2): 1980 SO2 rate
SO2RTE89 §404(h): 1989 SO2 rate
SO2RTE90 §404(h)&405(i)(2): 1990 SO2 rate
SO2SYS80 §405(i)(2): 1980 "System" SO2 rate
SO2SYS88 §404(i)(2): 1988 "System" SO2 rate
SO2SYS90 §404(h): 1990 Weighted average "system"
SO2 rate
SPECMULT Flag: boiler feeding <25 MW generator that
also feeds >25 MW generator
SPOP8088 §405(i)(1): State population increase, 1980-
1988
STATNAM State name
STCAP88 §405(b)(4)&(i)(1): State gen. capacity, 1988
UCODE Operating utility code from Form EIA-861
UCUST90 §405(c)(3): Utility's ultimate consumers,
1990
UPCTSCRB §405(c)(5): Utility percentage scrubbed
UTILNAME Utility name
UTILSYS Utility "system"
Utility-Supplied Data
Documentation of
Regulations/Permits
Calculated by EIA from Data
Form FPC-67
Calculated by EIA from Data
Form EIA-767
Calculated by EIA from Data
Form EIA-767
Calculated by EIA from Data
Form FPC-67
Calculated by EIA from Data
Form EIA-767
Calculated by EIA from Data
Form EIA-767
Calculated from NADB Data Flag
Dept. of Commerce Census Data
Report
NADB Identification
Form EIA-860 Data
NADB Identification
Form EIA-861 Data
Calculated from NADB Data Calculated
NADB Identification
Directory of Electric Utilities Data
G-7
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STRUCTURE OF THE SUPPLEMENTAL DATA FILE
Table G-2 shows the structure of the SDF in dBASE III Plus PC format. For each field, the order of
the field in the SDF, the field name, field type (character or numeric), width and position in the record are
given. The name of the file is SDFV22.DBF. There are a number of common variables that exist both in
the NADB and SDF files. The widths of data fields for these variables may not be consistent in both files.
Table G-2
SDF File Structure
(File: SDFV22.DBF)
Field Field Name Type Position Width
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
STATNAM
PNAME
BLRID
GENID
UCODE
ORISPL
SEQ
UTILNAME
SO2SYS80
SO2SYS90
UCUST90
CMIN80
CMIN90
SO2SYS88
STCAP88
SPO8088
LIGNTPCT
SO2RTE80
SO2RTE89
SO2RTE90
SO22000
SMCOPCT
SPECMULT
UTILSYS
UPCTSCRB
ATTAIN
BIGUHARD
CCTGRNT
CONTUTIL
CONTAUTH
PROHIB O
O2C8085
G2C8587
PROPIFUA
SO2LIM80
SO2LIM90
SO2LIM87
CONSTYR
Char
Char
Char
Char
Num
Num
Num
Char
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Char
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
Num
4
25
46
53
59
67
75
83
114
122
130
138
146
154
162
170
178
186
194
202
210
218
226
234
265
273
281
289
297
305
313
321
329
337
345
353
361
369
21
21
7
6
8
8
8
31
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
31
8
8
8
8
8
8
8
8
8
8
8
8
8
8
G-8
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SECTION 3
PROVISION DESCRIPTIONS
INTRODUCTION
This section describes each provision of the CAA that requires information that is not included in the
NADB to calculate Phase 2 allowance allocations. For each of the applicable provisions (or subsections in Title
IV), the following information is provided:
• A summary of the provision;
A section listing and describing the supplemental data elements required (in
addition to those elements already in the NADB), including the field name and the
purpose of the field (i.e., whether the data element is needed to determine eligibility
for the provision or to calculate allowances under the provision);
• A table summarizing the data elements and the source of the data; and
• The methods used to determine which units satisfy the eligibility criteria.
In some cases, the number of potentially eligible units was narrowed down by taking each separate
eligibility requirement for a given provision in turn, starting with the most easily identifiable requirements
and moving to the more specific criteria as the number of potentially eligible units was reduced. This
"winnowing" process, which was conducted in order to limit the amount of additional information required,
is described more fully in each of these cases, where applicable. Note that each section of the CAA
discussed in this appendix is presented on a new page for ease of reference.
G-9
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SECTION 404(h)
Provision Summary
§404(h)(l):
§404(h)(2):
Phase 1 affected units with an SO2 emission rate below 1.0 Ib/MMBtu as of enactment,
whose SO2 rate declined by 60 percent or more between 1980 and enactment, and which
were part of a "utility system" whose weighted average SO2 emission rate as of enactment
for all fossil units was less than 1.0 Ib/MMBtu, may use an alternate baseline (i.e., fuel
consumption at a 60 percent capacity factor) in determining their Phase 2 allowance allocations.
Units eligible for §404(h)(l) that choose the alternate baseline described therein must use
the lesser of a 1.0 Ib/MMBtu rate or their actual 1989 SO2 emission rate in determining
their Phase 2 allowance allocations.
Supplemental Data Elements Required
\ SO2 Emission Rate as of Enactment ~ The boiler's SO2 rate as of enactment, which EPA has
interpreted to mean the boiler's annual average SO2 rate for 1990. This information was
calculated by EIA from Form EIA-767.
! 1980 SO2 Emission Rate ~ The boiler's annual average 1980 SO2 emission rate, calculated by
EIA from Form FPC-67.
! Utility System Weighted Average SO2 Emission Rate for All Fossil Units as of Enactment ~
The weighted average SO2 rate for all fossil units owned by the utility system as of enactment,
which EPA has interpreted to mean the annual weighted average SO2 rate as of 1990, where the
units' SO2 rates were weighted by 1990 fuel consumption using the following formula:
Utility System's
Weighted Average
SO2 Rate
# Units
53 (SO2 Rate.x Fuel Consumption. (MMBtu\
i=\
# Units
Fuel Consumption. (MMBtu)
Consistent with EPA's interpretation, "utility system" has been defined as the operating utility,
identified by the utility name (UTILNAME) field in the NADB. Boiler-level emissions data for
these units were calculated by EIA from Form FPC-67 and Form EIA-767.
1989 SO2 Emission Rate ~ The boiler's annual average 1989 SO2 emission rate, calculated by
EIA from Form EIA-767.
G-10
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Summary of Supplemental Data Elements
Data Element
1980 Unit SO2 emission rate
(Ibs/MMBtu)
1989 Unit SO2 emission rate
(Ibs/MMBtu)
1990 Unit SO2 emission rate
(Ibs/MMBtu)
1990 Utility weighted average
SO2 emission rate (Ibs/MMBtu)
Field Name
SO2RTE80
SO2RTE89
SO2RTE90
SO2SYS90
Source
Calculated by EIA from
Form FPC-67
Calculated by EIA from
Form EIA-767
Calculated by EIA from
Form EIA-767
Calculated by EIA from SO2RTE90
and 1990 Fuel Consumption
Purpose of Field
Eligibility
Calculation
Eligibility
Eligibility
Determination of Eligibility
The following process was used to narrow down the list of potentially eligible units:
(1) First, units must have Phase 1 allowances greater than 0, according to the NADB.
(2) Next, units must have a 1990 boiler SO2 emission rate below 1.0 Ib/MMBtu.
(3) An eligible unit's SO2 emission rate also must have declined by at least 60 percent between 1980
and enactment; that is, the quotient
Unit's Actual 1990
SO2 Emission Rate
Unit's Actual 1980
SO2 Emission Rate
must be less than 0.4.
(4) Finally, eligible units must be part of a utility system whose weighted average SO2 emission rate
as of enactment (i.e., 1990) was less than 1.0 Ib/MMBtu.
G-ll
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SECTION 405(b)(3)
Provision Summary
§405(b)(3): An existing unit subject to §405(b)(l) and/or §405(b)(2), whose "annual average fuel
consumption during 1985, 1986, and 1987 on a Btu basis exceeded 90 percent in the form
of lignite coal which is located in a state in which, as of July 1, 1989, no county or portion
of a county was designated nonattainment under §107" of the CAA, receives allowances
based on the lesser of their actual or allowable 1985 SO2 rate.
Supplemental Data Elements Required
\ States With No County or Portion of a County Designated Nonattainment ~ States of which
no part was listed as a nonattainment area in "Subpart C ~ Section 107 Attainment Status
Designations," 40 CFR, Part 81, Subpart C, §81.301 through §81.351, July 1, 1989. The states
satisfying this criterion were North Dakota, Arkansas, and Mississippi.
! Percentage of Average Annual Fuel Consumption in the Form of Lignite Coal ~ The
percentage of average annual fuel consumption (in Btu) that was consumed in the form of lignite
coal. This percentage was calculated using the following formula:
Dec, 1987
E
!=Ja«,1985
Dec, 1987
E
i-Jan, 1985
Lignite
Consumed
in Montht
Total Fuel
Consumed
in Montht
X
Heat Content
of Lignite
in Montht
(Heat Content of\
X 1 1
1 Fuelin Month . 1
= x 100
Fuel consumption and heat content data were calculated by EIA from Form EIA-767.
Summary of Supplemental Data Elements
Data Element
Units in states with no nonattainment
areas as of July 1, 1989 (Flag Field)
1985-1987 average unit-level proportion
of lignite to total fuel used (Percentage,
Oto 100)
Field Name
ATTAIN
LIGNTPCT
Source
40 CFR Part 81, Subpart C
Calculated by EIA from
Form EIA-767
Purpose of Field
Eligibility
Eligibility
Determination of Eligibility
The following process was used to narrow down the list of potentially eligible units:
G-12
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(1) First, units must be located in states that have no portion designated as nonattainment.
(2) Next, a unit must satisfy the following criteria for §405(b)(l):
(a) The unit must serve a generator with a nameplate capacity 75 MW or greater, and
(b) The unit's actual 1985 SO2 emission rate must be greater than or equal to 1.2 Ibs/MMBtu.
(3) Finally, units must have consumed more than 90 percent of their fuel in the form of lignite coal in
the 1985 to 1987 period.
G-13
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SECTION 405(b)(4)
Provision Summary
§405(b)(4):
Any unit subject to §405(b)(l), "located in a State with an installed electrical generating
capacity of more than 30,000,000 kW in 1988 and for which was issued a prohibition order
or proposed prohibition order (from burning oil), which unit subsequently converted to coal
between January 1, 1980 and December 31, 1985," is allocated additional basic allowances
based on the difference between allowances calculated under §405(b)(l) and allowances
calculated based on the unit's fuel consumption at a 65 percent capacity factor, up to a
maximum of 5,000 additional basic allowances.
Supplemental Data Elements Required
\ State's Installed Electrical Generating Capacity in 1988 ~ The sum of nameplate capacities
reported on Form EIA-860 for all generators physically located in the state in 1988.
! Issued a Prohibition Order from Burning Oil ~ Units that were issued a proposed and/or final
prohibition order from burning oil, as identified by the U.S. Department of Energy (DOE) Office
of Coal and Electricity.
! Converted from Oil-burning to Coal-burning Between 1980 and 1985 ~ Units that burned oil
as their primary energy source in 1980 and then converted to coal as their primary energy source
by the end of 1985. A unit's "primary energy source" is defined for this section as the fuel
reported as such on Form EIA-860, "Annual Electric Generator Report," according to the
"Inventory of Power Plants in the United States, 1980 Annual," DOE/EIA-0095(80), U.S.
Department of Energy, 1980; and "Inventory of Power Plants in the United States: 1985,"
DOE/EIA-0095(85), Energy Information Administration, 1986.
Summary of Supplemental Data Elements
Data Element
1988 state installed electric
generating capacity (MW)
Unit issued a prohibition order from burning
oil (Flag Field)
Unit converted from oil to coal, 1980-1985
(Flag Field)
Field
Name
STCAP88
PROHIBJD
O2C8085
Source
Form EIA-860
DOE, Office of Coal &
Electricity
Inventory of Power Plants,
1980 and 1985
Purpose of Field
Eligibility
Eligibility
Eligibility
G-14
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Determination of Eligibility
The following process was used to narrow down the list of potentially eligible units:
(1) First, a unit must satisfy the following criteria for §405(b)(l):
(a) The unit must serve a generator with a nameplate capacity 75 MW or greater, and
(b) The unit's actual 1985 SO2 emission rate must be greater than or equal to 1.2 Ibs/MMBtu.
(2) Next, units must be located in a state that had installed generating capacity greater than 30
million kW in 1988.
(3) Potentially eligible units also must have been issued a prohibition order from burning oil.
(4) Finally, units must have switched their primary fuel from oil to coal between 1980 and 1985.
G-15
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SECTION 405(c)(3)
Provision Summary
§405(c)(3):
An existing unit serving a generator "with a nameplate capacity below 75 MW and an
actual 1985 emissions rate equal to, or greater than, 1.2 Ibs/MMBtu which became
operational on or before December 31, 1965, which is owned by a utility operating
company with, as of December 31, 1989, a total fossil steam-electric generating capacity
greater than 250 MW, and less than 450 MW which serves fewer than 78,000 electrical
customers" as of enactment, receives basic allowances calculated based on the lesser of the
unit's actual 1985 SO2 rate or allowable 1985 SO2 limit, times baseline, for the 2000 to
2009 period only.
Supplemental Data Element Required
\ Utility Customers as of Enactment ~ EPA interpreted this to be the number of ultimate
consumers (i.e., end users, as opposed to distribution and/or transmission entities) served by each
utility in 1990, according to Form EIA-861 or, for rural electrical cooperatives, the number of
customers of the distribution cooperatives served by the generating cooperative.
Summary of Supplemental Data Element
Data Element
Utility customers, 1990 (number in thousands)
Field Name
UCUST90
Source
Form EIA-861
Purpose of Field
Eligibility
Determination of Eligibility
The following procedure was used to narrow down the list of potentially eligible units:
(1) First, units must have become operational on or before December 31, 1965.
(2) Next, they must have a nameplate capacity less than 75 MW.
(3) Units must also have an actual 1985 SO2 emission rate greater than or equal to 1.2 Ibs/MMBtu.
(4) Potentially eligible units must also be owned by a utility whose fossil steam capacity is greater
than 250 MW and less than 450 MW.
(5) Finally, units must also be owned by a utility that served fewer than 78,000 customers in 1990.
G-16
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SECTION 405(c)(5)
Provision Summary
§405(c)(5): An existing unit serving a generator "with a nameplate capacity below 75 MW and an
actual 1985 emissions rate equal to, or greater than, 1.20 Ibs/MMBtu which is part of an
electrical utility system which, as of the date of the enactment of the Clean Air Act
Amendments of 1990, (A) has at least 20 percent of its fossil-fuel capacity controlled by
flue gas desulfurization devices, (B) has more than 10 percent of its fossil-fuel capacity
consisting of coal-fired units of less than 75 MW, and (C) has large units (greater than 400
MW) all of which have difficult or very difficult FGD Retrofit Cost Factors" receives basic
allowances based on the unit's baseline times 2.5, for the period from 2000 to 2009 only.
Supplemental Data Elements Required
\ Electric Utility System ~ Consistent with EPA's interpretation, an "electric utility system" has
been defined for this section as one utility operating company and its wholly owned subsidiaries,
as listed in Electrical World's "Directory of Electric Utilities," 98th Edition, McGraw-Hill, Inc.,
New York, 1990.
! Electric Utility System Percent Scrubbed ~ The percent of the electric utility system's total
electrical generating capacity that was scrubbed as of enactment (1990), as determined by the
following equation:
\Total Scrubbed Capacity]
\pfElectric Utility System\ ,„„
[ Total Capacity of 1
\Electric Utility System\
\ Small Coal Units as a Percent of Fossil Capacity ~ The percent of the electric utility's fossil
capacity that was made up of coal-fired units that serve generators with nameplate capacity less
than 75 MW (i.e., "small"), calculated by the following equation:
Total Capacity of
Electric Utility System's
Small Coal Generators
\ Total Capacity of
^lectric Utility System
100
G-17
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System with Big, Hard-to-scrub Units ~ Electric utility systems that owned units serving
generators with nameplate capacity greater than 400 MW, all of which (if unscrubbed) were
rated difficult or very difficult to scrub in the report, "Evaluation of SO2 Emissions and the FGD
Retrofit Feasibility at the 200 Top Generating Stations," prepared for EPA by Energy Ventures
Analysis, Inc., 1985.
Summary of Supplemental Data Elements
Data Element
Electric utility system as defined for
§405(c)(5) (Name of System)
"System" >20 percent scrubbed
"System" with small coal units >10 percent of
capacity (Flag Field)
"System" with big, hard-to-scrub units (Flag
Field)
Field Name
UTILSYS
UPCTSCRB
SMCOPCT
BIGUHARD
Source
Directory of Electric
Utilities
Calculated
Calculated
EVA Report on FGD
Retrofit Cost Factors
Purpose of Field
Eligibility
Eligibility
Eligibility
Eligibility
Determination of Eligibility
The following criteria were used to narrow down the list of potentially eligible units:
(1) First, units must serve generators with nameplate capacity less than 75 MW.
(2) Next, units must have an actual 1985 SO2 emission rate greater than or equal to 1.2 Ibs/MMBtu.
(3) Units must be part of an electric utility system that has big, hard-to-scrub units.
(4) Potentially eligible units must also be part of an electric utility system that has more than 10
percent of its fossil capacity made up of small coal units.
(5) Finally, units must be part of an electric utility system that was at least 20 percent scrubbed as of
1990.
G-18
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SECTION 405(d)(5)
Provision Summary
§405(d)(5): "An oil- and gas-fired unit that has been awarded a clean coal technology demonstration
grant as of January 1, 1991," receives basic allowances based on its baseline times a 1.2
Ibs/MMBtu rate.
Supplemental Data Element Required
\ Awarded a Clean Coal Technology Grant ~ A unit that was awarded a Clean Coal
Technology grant as of January 1, 1991. DOE's Office of Clean Coal Technology supplied a list
of clean coal technology programs established as of January 1, 1991.
Summary of Supplemental Data Element
Data Element
Unit awarded a CCT grant as of
1/1/91 (Flag Field)
Field Name
CCTGRNT
Source
DOE, Office of Clean Coal
Technology
Purpose of Field
Eligibility
Determination of Eligibility
The following criteria were used to narrow down the list of potentially eligible units:
(1) First, the unit must be an oil/gas unit.
(2) Next, the unit must have been awarded a Clean Coal Technology grant as of January 1, 1991.
G-19
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SECTION 405(f)(2)
Provision Summary
§405(f)(2): Any unit "operated by a utility that furnishes electricity, electric energy, steam, and natural
gas within an area consisting of a city and 1 contiguous county, and in the case of any unit
owned by a state authority, the output of which unit is furnished within that same area
consisting of a city and 1 contiguous county," receives 7,000 and 2,000 basic allowances,
respectively, allocated pro rata based on the total of basic and bonus allowances otherwise
received by such units.
Supplemental Data Elements Required
\ Utility Furnishing Electricity, Gas, and Steam Within a City and One Contiguous County ~
A utility that (a) sold steam in the period from 1985 to 1987 (according to Form EIA-767), (b)
sold electricity and gas during this period (according to the Electrical World's "Directory of
Electric Utilities," 98th Edition, McGraw-Hill, Inc., New York, 1990), and (c) served a city and
one contiguous county. The Directory was consulted to determine what geographic area each
eligible utility served. The only utility that satisfied all the above criteria served New York City
and Westchester County.
! State Authority Serving the Same Area as the Utility Identified Above ~ The State authority
that, according to the Directory, served the same area as that served by a utility satisfying the
criteria above; that is, New York City and Westchester County.
Summary of Supplemental Data Element
Data Element
Utility furnishing electricity, gas, and steam
within a city and one contiguous county (Flag
Field)
State Authority serving the same area (Flag
Field)
Field Name
CONTUTIL
CONTAUTH
Source
Form EIA-767,
Directory of Electric
Utilities
Directory of Electric
Utilities
Purpose of Field
Eligibility
Eligibility
Determination of Eligibility
The following process was used to narrow down the list of potentially eligible units:
(1) First, units must be owned by utilities that sold steam in the period from 1985 to 1987.
(2) Next, the unit must be owned by utilities that also sold electricity and gas in the period from
1985 to 1987.
(3) Potentially eligible units must also be owned by either of the following:
G-20
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(a) A utility that serves a city and one contiguous county, or
(b) A State authority that, according to the Directory, serves the area identified in (3)(a) above.
G-21
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SECTION 405(g)(4)
Provision Summary
§405(g)(4):
A unit that has "commenced construction before December 31, 1990 and that commences
commercial operation between January 1, 1993 and December 31, 1995" receives
allowances based on the unit's fuel consumption at a 65 percent capacity factor, multiplied
by the lesser of 0.3 or the unit's allowable SO2 emission limit.
Supplemental Data Element Required
\ Construction Start Year ~ The year in which a unit's construction commenced. The utilities
owning units that were scheduled to commence commercial operation between January 1, 1993
and December 31, 1995 (according to the NADB) provided copies of equipment and/or
construction contracts documenting the dates when they commenced construction. Under the
final rule, utilities must have submitted documentation of the commencement of construction no
later than December 31, 1995.
Summary of Supplemental Data Elements
Data Element
Construction start year (Year - four digits)
Field Name
CONSTYR
Source
Equipment/Construction
Contracts
Purpose of Field
Eligibility
Determination of Eligibility
The following process was used to narrow down the list of potentially eligible units:
(1) First, units must be scheduled to go on-line between January 1, 1993 and December 31, 1995.
(2) Next, units must have commenced construction on or before December 31, 1990.
Note: For programming purposes, units that did not commence operation between January 1, 1993 and
December 31, 1995 are assigned the value "9999" for the CONSTYR field. Units that were originally
scheduled to commence operation between January 1, 1993 and December 31, 1995 but that were canceled
are assigned the value "0" for the CONSTYR field. For all other units, the CONSTYR field contains the
actual year that construction commenced.
G-22
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SECTION 405(g)(5)
Provision Summary
§405(g)(5):
A unit that "has completed conversion from predominantly gas fired existing operation to
coal fired operation between January 1, 1985 and December 31, 1987, for which there has
been allocated a proposed or final prohibition order pursuant to §301(b) of the Powerplant
and Industrial Fuel Use Act of 1978 (42 U.S.C. 8301 et seq, repealed 1987)," receives
basic allowances based on fuel consumption at a 65 percent capacity factor and the lesser
of 1.2 or the unit's 1987 SO9 limit.
Supplemental Data Elements Required
! Units Converting from Gas to Coal, 1985-1987 ~ This includes units that converted from
predominantly gas-fired operation in 1985 to coal-fired operation by the end of 1987.
"Predominantly gas-fired existing operation" means for this section that natural gas was the fuel
reported as "primary energy source" on Form EIA-860, "Annual Electric Generator Report,"
according to utility-supplied documentation, or was the primary fuel reported in the "Inventory of
Power Plants in the United States, 1985," DOE/EIA-0095(85), Energy Information
Administration, 1986; and "Inventory of Power Plants in the United States: 1987," DOE/EIA-
0095(87), Energy Information Administration, 1988. A similar definition was used for "coal-
fired" operation.
! Issued a Proposed and/or Final Prohibition Order under PIFUA ~ Units that were issued a
proposed or final prohibition order according to the DOE's Office of Coal and Electricity.
! 1987 SO2 Emission Limit ~ The unit's allowable federally enforceable emission rate in 1987. In
accordance with the final rule, this limit was not subject to annualization. Electric utilities with
eligible units supplied information documenting the applicable federally enforceable 1987 SO2
emission limit regulations and/or permits for their units.
Summary of Supplemental Data Elements
Data Element
Units converting from gas to coal,
1985-1 987 (Flag Field)
Units issued proposed or final prohibition
order under PIFUA (Flag Field)
1987 Unit SO2 emission limit (Ibs/MMBtu)
Field Name
G2C8587
PROPIFUA
SO2LIM87
Source
Inventory of Power Plants,
1 985 & 1987 /Utility Letters
DOE, Office of Coal &
Electricity
Utility-Supplied
Documentation of
Regulations/Permits
Purpose of Field
Eligibility
Eligibility
Calculation
Determination of Eligibility
G-23
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The following criteria were used to narrow down the list of potentially eligible units:
(1) First, units must have been issued a "proposed or final prohibition order."
(2) Next, units must have used gas as their primary fuel in 1985 and then converted to using coal as
their primary fuel by the end of 1987.
G-24
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SECTION 405(i)(l)
Provision Summary
§405(i)(l): A Phase 2 affected unit "located in a State that (A) has experienced a growth in population
in excess of 25 percent between 1980 and 1988 . . . and (B) had an installed electrical
generating capacity of more than 30,000,000 kW in 1988" receives up to a total of 40,000
additional allowances, based on the difference between each eligible unit's baseline and its
maximum fuel consumption in any consecutive 3-year period from 1980 to 1989.
Supplemental Data Elements Required
\ State Population Increase ~ The percentage increase in the state's population between 1980 and
1988. Data concerning state-level population growth rates were taken from Table 9: Percent
Change in the Resident Population of States, by Age; April 1, 1980 to July 1, 1988, Current
Population Reports, Populations, Estimates, and Projections, Series P-25 #1044, U.S.
Department of Commerce, Bureau of the Census, August 1989, as stipulated in §405(i)(l).
! State's Installed Electrical Generating Capacity in 1988 ~ EPA has defined this as the sum of
the nameplate capacities reported on Form EIA-860 for all generators physically located in the
state in 1988.
Summary of Supplemental Data Elements
Data Element
State population increase, 1980-1988
(percentage, 0 to 100)
1988 State installed generating capacity (MW)
Field Name
SPOP8088
STCAP88
Source
Dept. of Commerce
Census Report
Form EIA-860
Purpose of Field
Eligibility
Eligibility
Determination of Eligibility
The following criteria were used to narrow down the list of potentially eligible units:
(1) First, units must be located in states that had an installed generating capacity greater than 30
million kW in 1988.
(2) Next, eligible units must be located in a state that had at least a 25 percent increase in population
between 1980 and 1988.
(3) Finally, the units must be Phase 2 affected.
G-25
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SECTION 405(i)(2)
Provision Summary
§405(i)(2): A unit subject to §405(b)(l), "(A) the lesser of whose actual or allowable 1980 emissions
rate has declined by 50 percent or more as of the date of enactment of the Clean Air Act
Amendments of 1990, (B) whose actual emissions rate is less than 1.2 Ibs/MMBtu as of
January 1, 2000, (C) which commenced [commercial] operation after January 1, 1970, (D)
which is owned by a utility company whose combined commercial and industrial kilowatt-
hour sales have increased by more than 20 percent between calendar year 1980 and the date
of enactment of the Clean Air Act Amendments of 1990, and (E) whose company-wide
fossil-fuel sulfur dioxide emissions rate has declined 40 percent or more from 1980 to
1988," receives additional allowances equal to the difference between allowances calculated
based on a baseline consisting of any 3 consecutive calendar years from 1980 to 1989 and
allowances under §405(b)(l).
Supplemental Data Elements Required
\ 1980 SO2 Emission Rate ~ The boiler's annual average 1980 SO2 emission rate, calculated by
EIA from Form FPC-67.
! 1980 SO2 Emission Limit ~ The unit's allowable federally enforceable emission rate in 1980.
Electric utilities with eligible units supplied information documenting the applicable federally
enforceable 1980 SO2 emission limitation regulations and/or permits for their units. This limit
was not subject to annualization.
! SO2 Emission Rate as of Enactment ~ The boiler's SO2 rate as of enactment, which EPA has
interpreted to mean the boiler's annual average SO2 emission rate in 1990. This information was
calculated by EIA from Form EIA-767.
! SO2 Emission Limit as of Enactment ~ The unit's allowable federally enforceable emission rate
as of enactment, which EPA has interpreted to mean the limit as of 1990. Electric utilities with
eligible units supplied information documenting the applicable federally enforceable 1990 SO2
emission limitation regulations and/or permits for their units. This limit was not subject to
annualization.
! 2000 Actual SO2 Emission Rate ~ The boiler's actual average SO2 emission rate for 2000.
Based on comments on the Proposed 1998 J^allocation of Allowances (63 FR 0714, January 7,
1998), this field will reflect the unit's actual SO2 emission rate rom 1996 through 1999,
whichever year the emission rate is below 1.2 Ib/mmBtu, as calculated from data submitted with
the Emissions Tracking System. 1996 and 1997 data from potentially eligible units have been
received and quality assured. For two of the potentially eligible units, the 1997 data were lower
than 1.2 Ib/mmBtu and have been entered in to this field. However, until 1998 and 1999 data are
received and quality assured for the other potentially eligible units, this value will be assumed to
be less than 1.2 Ibs/MMBtu.
G-26
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1980 Utility Commercial/Industrial Sales ~ The utility's combined commercial and industrial
sales in 1980, from Form EIA-412, Annual Report of Public Electric Utilities, U.S. Department
of Energy, Energy Information Administration, 1980; and Form FERC-1, Annual Report of
Major Electric Utilities, Licensees, and Others, Federal Energy Regulatory Commission, 1980.
1990 Utility Commercial/Industrial Sales ~ The utility's combined commercial and industrial
sales in 1990, from Form EIA-861.
1980 Utility SO2 Emission Rate ~ The utility's average SO2 emission rate in 1980. The utility-
level SO2 rates were calculated by EIA from Form FPC-67.
1988 Utility SO2 Emission Rate ~ The utility's average SO2 emission rate in 1988. The utility-
level SO2 rates were calculated by EIA from Form EIA-767.
Summary of Supplemental Data Elements
Data Element
1980 Utility commercial/ industrial sales (BkWh)
1990 Utility commercial/ industrial sales (BkWh)
1980 Unit actual SO2 emission rate (Ibs/MMBtu)
1980 Unit SO2 emission limit (Ibs/MMBtu)
1980 Utility SO2 emission rate (Ibs/MMBtu)
1988 Utility SO2 emission rate (Ibs/MMBtu)
1990 Unit actual SO2 emission rate (Ibs/MMBtu)
1990 Unit SO2 emission limit (Ibs/MMBtu)
2000 Unit actual SO2 emission rate (Ibs/MMBtu)
Field Name
CMIN80
CMIN90
SO2RTE80
SO2LIM80
SO2SYS80
SO2SYS88
SO2RTE90
SO2LIM90
SO22000
Source
Form EIA-412, FERC
Form 1
Form EIA-861
Calculated by EIA
from Form FPC-67
Utility-Supplied
Documentation of
Regulations/Permits
Calculated by EIA
from Form FPC-67
Calculated by EIA
from Form EIA-767
Form EIA-767
Utility-Supplied
Documentation of
Regulations/Permits
Currently Assumed to
be < 1.2
Purpose of Field
Eligibility
Eligibility
Eligibility
Eligibility
Eligibility
Eligibility
Eligibility
Eligibility
Eligibility
G-27
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Determination of Eligibility
The following process was used to narrow down the list of potentially eligible units:
(1) First, a unit must satisfy the following criteria for §405(b)(l):
(a) The unit must serve a generator with nameplate capacity 75 MW or greater, and
(b) The unit's actual 1985 SO2 emission rate must be greater than or equal to 1.2 Ibs/MMBtu.
(2) Next, units must have come on-line after January 1, 1970.
(3) Potentially eligible units must also be owned by a utility whose combined commercial and
industrial sales (MWh) increased by more than 20 percent between 1980 and 1990; that is, the
quotient
Utility's 1990 Commercial
and Industrial Sales
Utility's 1980 Commercial
and Industrial Sales
must be greater than 1.2.
(4) Units must also be owned by a utility whose SO2 rate decreased by 40 percent or more from
1980 to 1988; that is, the quotient
Utility's 1988
SO2 Emission Rate
Utility's 1980
SO2 Emission Rate
must be less than or equal to 0.6.
(5) If an eligible unit's 1980 SO2 emission rate was less than its 1980 emission limit, then its rate
must have decreased by at least 50 percent from 1980 to 1990; that is, the quotient
Unit's Actual 1990
SO2 Emission Rate
Unit's Actual 1980
SO2 Emission Rate
must be less than or equal to 0.5.
G-28
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However, if the eligible unit's 1980 SO2 emission limit was less than its 1980 emission rate, then
the unit's limit must have decreased by at least 50 percent from 1980 to 1990; that is, the
quotient
Unit's 1990 SO2
Emission Limit
Unit's 1980 SO2
Emission Limit
must be less than or equal to 0.5.
(6) Finally, as of the year 2000, the units must have an actual SO2 emission rate that is less than 1.2
Ibs/MMBtu. As noted above, all units that satisfy conditions (1) through (5) were assumed by
EPA to have a rate of less than 1.2 Ibs/MMBtu for the year 2000.
G-29
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SPECIAL MULTI-HEADERS
While not called for by any specific provision, there is one additional calculated field required to
identify records with boilers that serve existing generators with nameplate capacity greater than 25 MW
and also serve at least one generator with nameplate capacity less than or equal to 25 MW. The addition of
this field is necessary to ensure that boilers are not "partially affected" in accordance with the final rule.
To ensure that all boilers are either affected or unaffected, the flag variable SPECMULT was created and
set equal to 1 for these special multi-header boilers, indicating that the specified boiler-generator
combination is classified as an "affected" unit, and is therefore subject to the SO2 emission limit, as
provided in Title IV §405.
Supplemental Data Elements Required
Data Element
Special Multi-header Unit (Flag Field)
Field Name
SPECMULT
Source
Calculated
G-30
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SECTION 4
EXAMPLES OF SDF DATA
Table G-3 is a sample of SDF data. It shows the complete data for the first five records in the file.
Data for each field or variable are labeled with the appropriate field name, with the first value in each row
representing the boiler-generator sequence number, SEQ. To find the value for a given variable, for
instance the Barry plant's boiler 5, generator 5 record, look at the appropriate SEQ value in the first
column and follow that row to the appropriate variable. For example, to find the SPOP8088 value for the
state in which the Barry 5,5 boiler-generator combination is located, find the SEQ value "5" in the first
column of the third group of rows, and follow that row (shaded in the table) across until you reach the
SPOP8088 column (also shaded). There the value "5.40" indicates a state population growth rate of 5.4
percent during the period from 1980 to 1988 for Barry's state, Alabama. Note that a value of 0 is entered
in a number of fields for the records shown, indicating either that the true value of the variable is in fact 0,
or that the unit and/or its operating utility was not eligible for the applicable provision (see text for a
complete description of each data element and its eligibility requirements).
G-31
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Table G-3
Sample SDF Data
SEQ
STATNAM
PNAME
1
2
3
4
5
ALABAMA
ALABAMA
ALABAMA
ALABAMA
ALABAMA
BARRY
BARRY
BARRY
BARRY
BARRY
BLRID
1
2
3
4
5
GENID UCODE
195
195
195
195
195
ORISPL
SEQ
UTILNAME
1 ALABAMA POWER CO
2 ALABAMA POWER CO
3 ALABAMA POWER CO
4 ALABAMA POWER CO
5 ALABAMA POWER CO
S02SYS80 S02SYS90 UCUST90
CMIN80
CMIN90
S02SYS88
2.3135
2.3135
2.3135
2.3135
2.3135
2.1411 1127593
2.1411 1127593
2.1411 1127593
2.1411 1127593
2.1411 1127593
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
0.0000 0.0000 0.0000
9
OJ
to
SEQ
1
2
3
4
5
STCAP88
19910.00000
19910.00000
19910.00000
19910.00000
LIGNTPCT S02RTE80 SO2RTE89 SO2RTE90 SO22000 SMCOPCT SPECMULT
S.40 0.00
S.40 0.00
S.40 0.00
S.40 0.00
S.40 0.00
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000
0.0000 0.0000
0.0000 0.0000
0.0000 0.0000
0.0000 0.0000
2.
2.
2.
2.
2.
SEQ
1
2
3
4
5
SEQ
1
2
3
4
5
UTILSY
UPCTSCRB ATTAIN BIGUHARD CCTGRNT CONTUTIL CONTAUTH
0 0
0 0
0 0
0 0
0 0
S02LIM87 CONSTYR
0.0000 9999
0.0000 9999
0.0000 9999
0.0000 9999
0.0000 9999
ALABAMA POWER CO
ALABAMA POWER CO
ALABAMA POWER CO
ALABAMA POWER CO
ALABAMA POWER CO
PROHIB_0 02C8085
0 0
0 0
0 0
0 0
0 0
0.00
0.00
0.00
0.00
0.00
G2C8587 PROPIFUA
0
0 0
0
0
0
0
0
0
0
0
0
0
0
0
0
S02LIM80
0
0
0
0
0.0000
0.0000
0.0000
0.0000
0.0000
0
0
0
0
0
S02LIM90
0.0000
0.0000
0.0000
0.0000
0.0000
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