### Atmospheric Sciences Group

Alpine Geophysics, LLC ▪ 387 Pollard Mine Road ▪ Burnsville, NC 28714 ▪ (828) 675-9045 ▪ (828) 675-5801 FAX 

# MEMORANDUM

To: VISTAS State Point Source Contacts a nd VISTAS EGU Special Interest Workgroup From: Gregory Stella, VISTAS Techni cal Advisor - Emission Inventories
Date: June 13, 2005

Re: EGU Emission Factors and Em ission Factor Assignment

Purpose

The purpose of this memorandum is to discuss th e differences currently known to exist in the base year (2002) and future year (2009 and 2018) forecasts of EGU emission factors for PM and NH3. In particular, it has been identified that E. H. Pechan & Associates, Inc. (Pechan) in their development of post-processed IPM output into NIF structure uses a set of PM and NH3

emission factors that are “the most recent EP A approved uncontrolled emission factors” and which are most likely not the same emission factors used by States and emission inventory preparation contractors for estim ating these emissions in 2002 for EGUs in the VISTAS domain. Additionally, through re view of the code used to post-proce ss the IPM parsed files, it has also been determined that emission factors are assigned in future years based on Pechan assigned SCCs and not necessarily initial base year SCCs as coded in the original VISTAS NIF files.

A second objective of this memorandum is to pr opose a resolution to the issues at hand and to

recommend a set of modifications to be made to the base year PM and NH3 emission estimates for this source category.

Background

VISTAS Base Year EGU Emissions Preparation

A major component to the development of the VI STAS point source sector of the inventory was the incorporation of data submitted by the VISTAS States and local (S/L) agencies to the United States Environmental Protection Agency (EPA) as part of the Consolidated Emissions Reporting Rule (CERR). Work on incorporating the CERR da ta into the revised base year involved: 1) obtaining the data from EPA or the S/L agenc y, 2) evaluating the em issions and pollutants reported in the submittal, 3) augmenting CERR da ta with annual emission estimates for PM10- PRI and PM25-PRI; 4) evaluating the emissi ons from electric generating units, and 5) completing quality assurance reviews for each component of the point source inventory.

Data from several sources were used: 1) the inventories that the S/L submitted to EPA from May through July 2004; 2) supplemental data supplied by the S/L agencies that may have been

revised or finalized after submitta l to EPA, and 3) the original VISTAS 2002 inventory in cases

where S/L CERR data were not available.

### Atmospheric Sciences Group

Alpine Geophysics, LLC ▪ 387 Pollard Mine Road ▪ Burnsville, NC 28714 ▪ (828) 675-9045 ▪ (828) 675-5801 FAX 

## Particulate matter emissions can be reporte d in many different forms, as follows:

PM Category Description PM-PRI Primary PM (include s filterable and condensable) PM-CON Primary PM, condensable por tion only (all less than 1 micron) PM-FIL Primary PM, filterable portion only PM10-PRI Primary PM10 (includes filterable and condensable) PM10-FIL Primary PM10, filterable portion only PM25-PRI Primary PM25 (includes filterable and condensable) PM25-FIL Primary PM25, filterable portion only

State/local agencies did not report PM emissi ons in a consistent manner. The State/local
inventories submitted for VISTAS included emissions data for either PM-FIL, PM-PRI, PM10-
FIL, PM10-PRI, PM25-FIL, PM25-PRI, and/or PM -CON. From any one of these pollutants, EPA has developed augmentation procedures to estimate PM10-PRI, PM10-FIL, PM25-PRI,
PM25-FIL, and PM-CON. If not included in a State/local inventory, PM10-PRI and PM25-PRI were calculated by adding PM10-FIL and PM-C ON or PM25-FIL and PM-CON, respectively. The procedures for augmenting point source PM em issions are documented in detail in Appendix

C of Documentation for the Final 1999 National Em issions Inventory (Version 3) for Criteria

Air Pollutants and Ammonia – Point Sources , January 31, 2004 1



## .

Briefly, the PM data augmentation proce dure includes the following five steps:

• 

## Step 1: Prepare S/L/T PM and PM10 Emi ssions for Input to the PM Calculator

• 

## Step 2: Develop and Apply Sour ce-Specific Conversion Factors

• 

## Step 3: Prepare Factor s from PM Calculator

• 

## Step 4: Develop and Apply Algorithms to Esti mate Emissions from S/L/T Inventory Data

• 

## Step 5: Review Results and Update the NEI with Emission Estimates and Control

Information.

Ammonia (NH3) emissions from these sources were assigned using direct incorporation of S/L/T provided emission estimates or via the applica tion of emission factors using ratios of NH3 emission factors to other reported pollutants (e.g., VOC, CO, etc.).

IPM Post Processing

ICF via VISTAS contracts provided an initial sp readsheet file containi ng unit-level records of both (1) “existing” units and (2) committed or new generic aggregates. All records have unit and fuel type data; exis ting, retrofit (for SO 2 

## and NO

x 

## ), and separate NO

x 

## control information; annual

SO 2 

## and NO

x 

## emissions and heat input; summer season (May-September) NO

x 

## and heat input; July day NO

x 

## and heat input; coal heat input by coal type; nameplate capacity (MW), and State FIPS code. Existing units also have county FIPS code, a unique plant identifier (ORISPL) and unit ID (also called boiler ID) (BLRID); generic units do not have these data.

1 

### ftp://ftp.epa.gov/EmisInventory/finalnei99ver3/crite ria/documentation/point/point_99nei_finalv3_0204.pdf

### Atmospheric Sciences Group

Alpine Geophysics, LLC ▪ 387 Pollard Mine Road ▪ Burnsville, NC 28714 ▪ (828) 675-9045 ▪ (828) 675-5801 FAX 

## The IPM data were further processed by Pech an using data files and methodology recently approved by EPA. The most current documentati on related to this subject is the EPA report
titled, Documentation for the 2002 Electric Gene rating Unit (EGU) National Emissions Inventory (NEI), September 2004 2 

## . The processing includes estimating various types of emissions and adding in control efficiencies, stack parameters, latitude-longitude coordinates, and State identifiers (plant ID, point ID, stack ID, process ID). Additionally, the generic units were sited in a county and given IDs.

Pechan developed SCC assignments for all units; unit/fuel/firing/bottom type data were used for existing units’ assignments, while only unit and fuel type were used for generic units’ assignments. Additional review of the source code used in deve loping these post-processed files confirmed this fact. In actuality, not only does it exist that the post-processing code assigns

different emission factors for the same SCC but that SCCs assigned in future year IPM output are potentially different than thos e assigned in the base year i nventory, leading to additional, propagating differences in the base year and future year estimates. The full extent of these issues is currently under review by VISTAS and MRPO.

Stack parameters were attache d, first using matches to data in the VISTAS 2002 NIF files, secondly using the EPA-provided data files, thir dly using a March 9, 2004 Pechan in-house stack parameter file based on previ ous EIA-767 data, and lastly usi ng an EPA June 2003 SCC-based default stack parameter file.

Plant ID (within State and county) , point ID, process ID , and stack ID were then attached, first using the VISTAS-provided data files, or seco ndly using EPA or Pechan-generated defaults. Default stack IDs within a plant were assi gned for each unique stack height-diameter combination. The process ID and stack ID default data were only used when the data were not matched to the original VISTAS 2002 NIF files.

Additional data were required for estimating VOC, CO, filterable primary PM 10 

## and PM 2.5 

## , PM condensable, and NH 3 

## emissions for all units. Thus, ash and sulfur contents were assigned by first using 2002 EIA-767 values for existing units or SCC-based defaults; filterable PM 10 

## and

PM 2.5 

## efficiencies were obtained from the 200 2 EGU NEI that were based on 2002 EIA-767

control data and the PM Calcul ator program (a default of 99.2% was used for coal units if necessary); fuel use was back calculated from th e given heat input and a default SCC-based heat
content; and emission factors were obtaine d from an EPA-approved October 7, 2004 Pechan

emission factor file based on AP-42 emission f actors. Table 1 provides the emission factor

differences between the “old” emission factor fi le (used in development of EPA’s 1999 NEI v.3) and the updated factors as used in VISTAS latest IPM conversion. Note that this updated file was not the one used for estimating emissions for pr evious EPA post-processed IPM files (including estimates for CAIR). It should al so be noted that this component of emission estimation is only for the filterable component of PM and that th e emission factors used for condensable PM did not change between the two versions.

2 

### ftp://ftp.epa.gov/EmisInventory/draftn ei2002/point/documentation/egu2002doc.pdf

### Atmospheric Sciences Group

Alpine Geophysics, LLC ▪ 387 Pollard Mine Road ▪ Burnsville, NC 28714 ▪ (828) 675-9045 ▪ (828) 675-5801 FAX 

## Issue Identification

During a VISTAS TAWG meeting held at the Solu tion Center in Durham, NC on April 5 and 6, 2005, emission summaries were presented as co mparisons of 2002 to 2018 forecasts. Table 2 presents the slide originally used in identifying the increase in PM and NH3 emissions. In this comparison, it was noted that PM and NH3 emissions (highlighted in Tabl e 2) from EGUs were significantly higher in 2018 than in 2002 and based on known regulation and activity, no reason

could be identified for this increase. After an init ial review of the data, it was determined that the

PM and NH3 emission factors used between the base year and future year were most likely the culprit. In fact, for some SCCs, the NH3 em ission factor increased by over 5,000% (0.000565 to 0.03 lbs/ton coal burned). Changes in PM emission factors were not as large and limited to only a few SCCs. However, this emissions increase was simply an artifact of the change in emission factor, not anything to do with changes in activity or control technology application.

Additionally, after further review of the post-processing code by VISTAS, it was determined that not only were differing emi ssion factors being used for similar SCCs between the base and future year estimates for those SCCs identified in Tabl e 2, but that the same S CCs were not necessarily being used for emission factor assignment in th e base and post-processed IPM scenarios. This issue has implications not only for the different PM and NH3 factors, but for other pollutants (CO, VOC) not initially estimated by IPM.

Table 3 presents those unit-segment (SCC) combinat ions which have been identified in the 2018 OTW run to have been assigned SCCs in the IPM post-processing step different than those in the 2002 base case. In some instances, the SCCs are comparable enough that the emission factors assigned were the same. However, there are additional instances where significant enough

difference exists that review a nd correction may be warranted. An analysis of the differences in assignment of these SCCs and associated factors has not yet been completed.

Proposed Solution

There are two issues which need to be resolved in the estimation of relative differences in EGU emissions between VISTAS base year 2002 emissions inventory and any forecasts of this source sector using IPM and post-proces sing steps applied using exis ting programs provided by Pechan; (1) consistent use of emission f actors between the base and future years, and (2) the consistent use of SCCs for determining emission fact ors between the base and future years.

These issues can be resolved using a variety of ways but the proposal provided here positions VISTAS to regenerate some specific pollutant 2002 emissions for the EGU sector in a fashion consistent, and presumably, more up-to-date, than the estimates provided in the 2002 base year inventory. Additionally, this proposal allows for th e existing process to be completed in the postprocessing steps but adjusts the resulting non-IPM generated emissions using correct SCCs and

emission factors.

### Atmospheric Sciences Group

Alpine Geophysics, LLC ▪ 387 Pollard Mine Road ▪ Burnsville, NC 28714 ▪ (828) 675-9045 ▪ (828) 675-5801 FAX 

## Base Year Emissions Adjustment

The first step is the adjustment of the 2002 ba se year emissions inve ntory. Using the latest “EPA-approved” uncontrolled emission factors by SCC, VISTAS contactors will utilize CERR or VISTAS reported annual heat input, fuel th roughput, heat, ash and sulfur content to estimate

annual uncontrolled emissions for units identified as output by IPM. This step will be conducted for non-CEM pollutants (CO, VOC, PM, and NH3) only. For PM emissions, the condensable component of emissions will also be calcula ted and added to the resulting PM primary

estimations. When these fuel characteristic va riables are found to be zero, out of range (as identified by AP-42 factors), or invalid, average fuel data collected from EPA’s AP-42 documentation on heat, sulfur, and/or ash content will be used. The resulting emissions will then be adjusted by any control efficiency factors re ported in the CERR or VISTAS data collection

effort.

Future Year Scenario Adjustment

Because the assignment of the SCCs to IPM output is a post-processing step which involves the cross-reference file developed to match IPM units to VISTAS 2002 base year inventory, it should be relatively straightforwar d to modify the code to assign the same base year SCC to the future year. Then, through assignment of SCCs and associated emission factors (via another cross-reference), similar base year and future year emission factor assi gnments could be made; just using the projected controls and fuel throughput as pred icted by IPM. If modifications can not be made directly to the code for this cro ss-reference step, VISTAS can modify the resulting post-processed NIF files for those sources identified with alternate SCCs assigned in the future year. Using the same methods as described for the 2002 revisions, those non-IPM generated pollutants would be estimated using IPM predic ted fuel characteristics and base year 2002 SCC assignments.

### Atmospheric Sciences Group

Alpine Geophysics, LLC ▪ 387 Pollard Mine Road ▪ Burnsville, NC 28714 ▪ (828) 675-9045 ▪ (828) 675-5801 FAX 

## Table 1. Comparison of “Old” vs. “New” Em ission Factors for IPM Post-Processing

SCCEMFACforMRPOoldvsnew.xls -- PM+NH3 EF , 12/17/04

This file lists the "Old" and "N ew" EPA-approved Uncontrolled PM 10 

### , PM 2.5 

### , and NH 3 

### Emission

Factors for the SCCs in the MRPO Scenarios.

SCC 1 

### FUEL "New"

PM10EF 4 

### "Old"

PM10EF 3 

### "New"

PM25EF 4 

### "Old"

PM25EF 3 

### PMFLAG 2 

### "New"

NH3EF 4 

### "Old"

NH3EF 3



### 10100201 BIT 2.6000 2.6000 1.4800 1.4800 A 0.030000 0.000565

10100202 BIT 2.3000 2.3000 0.6000 0.6000 A 0.030000 0.000565

10100203 BIT 0.2600 0.2600 0.1100 0.1100 A 0.030000 0.000565

10100204 BIT 13.2000 13.2000 4.6000 4.6000 0.030000 0.000565

10100211 BIT 2.6000 2.6000 1.4800 1.4800 A 0.030000 0.000565

10100212 BIT 2.3000 2.3000 0.6000 0.6000 A 0.030000 0.000565

10100217 BIT 12.4000 12.4000 1.3640 3.2000 0.030000 0.000565

10100221 SUB 2.6000 2.6000 1.4800 1.4800 A 0.030000 0.000565

10100222 SUB 2.3000 2.3000 0.6000 0.6000 A 0.030000 0.000565

10100223 SUB 0.2600 0.2600 0.1100 0.1100 A 0.030000 0.000565

10100224 SUB 13.2000 13.2000 4.6000 4.6000 0.030000 0.000565

10100226 SUB 2.3000 2.3000 0.6000 0.6000 A 0.030000 0.000565

10100238 SUB 16.1000 16.1000 4.2000 4.2000 0.030000 0.000565

10100301 LIG 1.8170 1.8170 0.5214 0.5214 A 0.030000 0.000565

10100302 LIG 2.3000 2.3000 0.6600 0.6600 A 0.030000 0.000565

10100303 LIG 0.8710 0.8700 0.3690 0.1100 A 0.030000 0.000565

10100317 LIG 12.0000 12.0000 1.4000 1.4000 0.030000 0.000565

10100601 NG 1.9000 1.9000 1.9000 1.9000 3.200000 3.200000

10100801 PC 7.9000 7.9000 4.5000 4.5000 A 0.397000 ---

10102018 WC 12.0000 12.0000 1.4000 1.4000 0.030000 0.000565

20100201 NG 1.9380 1.9380 1.9380 1.9380 6.560000 ---

20100301 IGCC 11.5500 11.5500 11.5500 11.5500 6.560000 ---

Notes:

1. SCCs beginning with 101002 (coal), 101003 (coal), 101008 (coke), or 101020 (waste coal), emission factors in LB/TON; SCCs beginning with 101006 (natural gas), 201002 (natural gas), or 201003 (IGCC),

emission factors are in LB/E6FT3.
2. If PMFLAG = 'A', then apply ash content to PM emission factor.
3. "Old" emission factors are used for latest EPA IPM post-processing.

4. "New" emission factors are used for MRPO IPM post-processing.Atmospheric Sciences GroupAlpine Geophysics, LLC▪387 Pollard Mine Road▪Burnsville, NC 28714▪(828) 675-9045▪(828) 675-5801 FAXTable 2. Annual Emissions Comparison of 2002 Typical with 2018 OTW; VISTAS Tier 1 Category Totals.19%9%13%-50%-8%-52%-19%VISTAS Total15%5%14%0%0%0%2%Miscellaneous35%-29%-29%-61%23%-30%-40%Off-highway36%-53%-34%-89%-19%-70%-47%Highway Vehicles52%10%11%37%9%13%11%Waste Disposal & Recycling40%2%-4%34%46%28%-19%Storage & Transport20%32%34%23%36%48%22%Solvent Utilization16%25%28%19%21%15%22%Other Industrial Processes12%33%35%11%15%23%-19%Petroleum & Related Industries60%20%20%37%29%27%43%Metals Processing27%36%36%31%32%29%50%Chemical & Allied Product Mfg23%-8%-16%15%-28%19%-55%Fuel Comb. Other28%7%5%7%15%0%12%Fuel Comb. Industrial3024%82%69%-63%53%-68%13%Fuel Comb. Elec. Util.NH3PM-2.5PM-10SO2CONOxVOCSource CategoryAnnual 2018 OTW - 2002Typical Emissions (Percent)Atmospheric Sciences GroupAlpine Geophysics, LLC▪387 Pollard Mine Road▪Burnsville, NC 28714▪(828) 675-9045▪(828) 675-5801 FAXTable 3. Differences in VISTAS Base Year 2002 and IPMPost-Processed SCC Emission Factor AssignmentsFIPS Plant ID Plant Name Point IDStack ID Segment 2002 SCC IPM SCC01039 0001 ALABAMA ELECTRIC COOPERATIVE - MCWILLIAMS 005 002 01 10100201 2010020101055 0002 ALABAMA POWER COMPANY - GADSDEN 002 001 01 10100202 2010020101055 0002 ALABAMA POWER COMPANY - GADSDEN 003 001 01 10100201 2010020101063 0001 ALABAMA POWER COMPANY - GREENE COUNTY 002 001 01 10100201 1010020201063 0001 ALABAMA POWER COMPANY - GREENE COUNTY 003 001 01 10100201 1010020201071 0008 TVA - WIDOWS CREEK 008 002 01 10100202 1010021201071 0008 TVA - WIDOWS CREEK 009 003 01 10100202 1010021201085 0008 GENERAL ELECTRIC CO 001 001 01 10200602 2010020101097 1001 ALABAMA POWER COMPANY - BARRY 002 001 01 10100201 1010021201097 1001 ALABAMA POWER COMPANY - BARRY 003 001 01 10100201 1010021201097 1001 ALABAMA POWER COMPANY - BARRY 004 001 01 10100201 1010021201097 1001 ALABAMA POWER COMPANY - BARRY 005 002 01 10100201 1010021201097 1001 ALABAMA POWER COMPANY - BARRY 006 003 01 10100201 1010021201097 1001 ALABAMA POWER COMPANY - BARRY 007 005 01 20200203 2010020101097 1001 ALABAMA POWER COMPANY - BARRY 008 006 01 20200203 2010020101097 1001 ALABAMA POWER COMPANY - BARRY 009 007 01 20200203 2010020101097 1001 ALABAMA POWER COMPANY - BARRY 010 008 01 20200203 2010020101127 0001 ALABAMA POWER COMPANY - GORGAS 004 003 01 10100201 1010020201127 0001 ALABAMA POWER COMPANY - GORGAS 005 003 01 10100201 1010020201127 0001 ALABAMA POWER COMPANY - GORGAS 006 004 01 10100201 1010021201127 0001 ALABAMA POWER COMPANY - GORGAS 007 004 01 10100201 1010021201127 0001 ALABAMA POWER COMPANY - GORGAS 008 004 01 10100201 1010021212001 0010001 PROGRESS ENERGY FLORIDA, INC. U OF FL COGEN 1 1 1 20200203 2010020112009 0090006 FLORIDA POWER & LIGHT (PCC) CAPE CANAVERAL 1 1 2 10100401 2010020112009 0090006 FLORIDA POWER & LIGHT (PCC) CAPE CANAVERAL 2 2 2 10100401 2010020112027 0270016 DESOTO COUNTY GENERATING COMPANY, LLC 2 2 1 20100101 2010020112031 0310047 JEA KENNEDY 3 3 1 20100101 2010020112031 0310047 JEA KENNEDY 4 4 1 20100101 2010020112031 0310047 JEA KENNEDY 5 5 1 20100101 2010020112031 0310485 JEA BRANDY BRANCH FACILITY 2 2 1 20100101 2010020112033 0330045 GULF POWER COMPANY CRIST ELECTRIC GENERATINGPLANT 2 1 1 10100601 2010020112033 0330045 GULF POWER COMPANY CRIST ELECTRIC GENERATINGPLANT 3 1 2 10100601 20100201Atmospheric Sciences GroupAlpine Geophysics, LLC▪387 Pollard Mine Road▪Burnsville, NC 28714▪(828) 675-9045▪(828) 675-5801 FAXFIPS Plant ID Plant Name Point IDStack ID Segment 2002 SCC IPM SCC12049 0490043 VANDOLAH POWER COMPANY, LLC 1 1 1 20100101 2010020112095 0950203 ORLANDO COGEN LIMITED, L.P. 1 1 1 20200203 2010020112097 0970014 PROGRESS ENERGY FLORIDA, INC. INTERCESSION CITY PLANT 11 11 1 20100101 2010020112097 0970014 PROGRESS ENERGY FLORIDA, INC. INTERCESSION CITY PLANT 18 18 2 20100101 2010020112099 0990042 FLORIDA POWER & LIGHT (PRV) RIVIERA POWER PLANT 3 3 3 10100401 2010020112099 0990042 FLORIDA POWER & LIGHT (PRV) RIVIERA POWER PLANT 4 4 3 10100401 2010020112099 0990045 CITY OF LAKE WORTH UTILITIES TOM G. SMITH POWER PLANT 9 9 1 10100601 2010020112103 1030011 PROGRESS ENERGY FLORIDA, INC. BARTOW PLANT 1 1 2 10100401 2010020112103 1030011 PROGRESS ENERGY FLORIDA, INC. BARTOW PLANT 2 2 2 10100404 2010020112103 1030011 PROGRESS ENERGY FLORIDA, INC. BARTOW PLANT 3 3 2 10100404 2010020112105 1050003 LAKELAND ELECTRIC CHARLES LARSEN MEMORIAL POWER PLANT 4 4 2 10100401 2010020112105 1050221 CALPINE/AUBURNDALE POWER PARTNERS, LP 6 6 2 20100101 2010020112105 1050223PROGRESS ENERGY FLORIDA, INC. TIGER BAY COGENERATIONFACILITY3 3 1 10200602 2010020112105 1050233 TAMPA ELECTRIC COMPANY POLK POWER STATION 1 1 2 20100201 2010030112121 1210003 PROGRESS ENERGY FLORIDA, INC. FL POWER SUWANNEE RVR PLANT 1 1 3 10100404 2010020112121 1210003 PROGRESS ENERGY FLORIDA, INC. FL POWER SUWANNEE RVR PLANT 2 2 3 10100401 2010020112121 1210003 PROGRESS ENERGY FLORIDA, INC. FL POWER SUWANNEE RVR PLANT 3 3 3 10100401 2010020112127 1270009 FLORIDA POWER & LIGHT (PSN) SANFORD POWER PLANT 1 1 3 10100401 2010020112127 1270020 PROGRESS ENERGY FLORIDA, INC. TURNER PLANT 10 10 1 20100101 2010020112127 1270020 PROGRESS ENERGY FLORIDA, INC. TURNER PLANT 9 9 1 20100101 2010020112127 1270028 PROGRESS ENERGY FLORIDA, INC. DEBARY FACILITY 17 17 1 20100101 2010020112127 1270028 PROGRESS ENERGY FLORIDA, INC. 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