Field Name Column Unit of Measure Definition

UniqueID A -------

The unique identifier assigned to a boiler or generator within a plant. It consists of the Plant 

ID (or ORIS Code), an indication of whether the unit is a boiler ("B"), generator ("G"), or 

committed unit ("C"), and the Unit ID. For example, for the Unique ID "113_B_1", "113" is 

the Plant ID, "B" indicates that this unit is a boiler, and "1" indicates that the ID of the boiler 

is 1.

RegionName B ------- The electricity grid region the unit is located in. 

StateName C -------

StateCode D -------

CountyName E -------

CountyCode F -------

“Parsed” data, representing model projections disaggregated to the unit level, will often differ from the corresponding variables (e.g., pollutant emission rates) reported for each unit in the NEEDS database, because the model may select different fuels, add 

new pollution control technologies, or revise the operation of particular units in response to future economic and regulatory conditions. (EPA uses detailed information about rail and barge links for coal, and pipeline availability for natural gas to constrain the 

model’s choices of available fuels at each unit (see IPM Documentation, Chapters 9 and 10 http://www.epa.gov/powersectormodeling/)

EPA’s application of IPM can result in differences between historic (observed) and future (simulated) values for the following parameters affecting EGU emissions:

- Post-combustion pollution control technologies installed (for SO2, NOX, HCl, Hg, PM, and CO2)

- Combustion control technologies installed (for NOX)

- Fuel type(s) combusted

- Generation produced

- Heat rate (the model may only change a unit’s heat rate if the heat rate improvement retrofit option is made available in that analysis)

Some apparent differences in input (NEEDS) and output (parsed) data are related to EPA’s approach to using each type of input data in the modeling process. For example, while NEEDS reports unit-level SO2 permit rates (where known), EPA uses that input 

parameter as an upper-bound constraint to prevent the model from making decisions that would exceed that emission rate. However, the model may select combinations of fuels and pollution control technologies that result in projected SO2 emission rates 

that are lower than the indicated SO2 permit rates for the unit in question. This approach preserves the model’s flexibility to select the most economic type of coal available for each unit based on the fuel’s simulated market price, sulfur content, and the 

environmental regulations applicable to the unit. The model’s decisions on fuel selection and pollution control configuration for each unit can be reviewed in the parsed file; the associated emission rate for the unit can be calculated by dividing the emission 

mass by the heat input in the parsed file.

For example, at the Seminole plant in Florida, unit 1 (Unique ID: 136_B_1) has a SO2 permit rate of 0.67 lbs/mmBtu in NEEDS. The annual SO2 rate projected by the model can be calculated by dividing the annual SO2 emissions by the heat input, both in the 

parsed file. This results in a projected 2018 SO2 emission rate of 0.22 lbs/mmBtu, which is lower than the permit rate listed in NEEDS.

One may also compare the IPM-projected 0.22 lbs/mmBtu SO2 emission rate to the actual 2011 SO2 emission rate of 0.35 lbs/mmBtu (calculated from Air Markets Program Data (AMPD), http://ampd.epa.gov/ampd/). Each of the potential drivers of this 

difference in historic and projected emission rates at this unit can be considered by reviewing the relevant modeling inputs and outputs. First, a comparison of the unit’s pollution control technologies present in 2011 and those shown in the 2018 modeling 

outputs reveals that the model did not apply any new pollution control technology to this unit (EIA Form 860 for year 2011, http://www.eia.gov/electricity/data/eia860/). Second, the removal efficiency of the FGD at the unit from reported data in 2011 was 

92.3% (EIA Form 923 for year 2011, http://www.eia.gov/electricity/data/eia923/), while NEEDS shows a 95% removal efficiency assumed in IPM modeling for the FGD on this unit (as explained in Section 5.1 of the IPM Documentation (page 5-2), for power 

sector modeling purposes, EPA assumes that FGD SO2 removal efficiencies are equivalent to the values reported for each FGD on EIA form 860). Recalculating the 2018 projected emissions at this unit, assuming the 92.3% removal efficiency reported for the 

unit’s FGD in 2011, would yield an emission rate equivalent to the 0.35 lbs/mmBtu reported in 2011. This difference in the reported 2011 SO2 removal efficiency and the SO2 removal efficiency assumed for power sector modeling explains the difference in 

reported 2011 and projected 2018 SO2 emission rates at this unit. If differences between historic values and assumed or projected future-year values in observed unit characteristics such as removal efficiency, heat rate, or retrofitted controls do not explain 

differences in historic and projected emission rates, then by process of elimination such a difference in emission rates would be due to differences in historic and modeled future-year fuel choices. 

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Unlike for SO2, where the model is determining future emission rates based on a suite of fuel and pollution control technology choices that are available inside the model, EPA’s methodology for making EGU NOX projections is based on an interpretation of 

each unit’s historical NOX emission rate data combined with potential pollution control configurations. From this data analysis, EPA quantifies four potential future NOX emission rates for each unit, from which the model selects one future NOX rate 

depending on the conditions represented in the future-year scenario for each analysis. These four potential NOX rates for each unit are listed in NEEDS and are derived from unit-specific reported emission data combined with assumptions about pollution 

control technology performance, as described in Attachment 3-1 and Figure 3-4 in the IPM Documentation, available at www.epa.gov/powersectormodeling. As explained in the modeling documentation, the projected NOx rate for a given unit (reported in the 

parsed file for a given IPM analysis) will either be one of the four potential NOx rates shown for that unit in the corresponding input file (NEEDS), or it may be a yet lower emission rate if the model chose to add a new post-combustion control technology to 

that unit (which will also be indicated in the parsed file).

Key to Recurring Column Values

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EPA v.5.15 Parsed File User Guide - August 2015 IPM output 

files report aggregated results for "model" plants (i.e., aggregates of generating units with similar operating characteristics). Parsed files approximate the IPM results at the generating unit level. This document defines the column headers found in EPA v.5.14 

parsed files.

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These four fields identify the geographic location of the unit. The State Code is the FIPS State 

Code, and the County Code is the FIPS County Code. New units have blanks in these columns, 

while committed units have zeros. Federal information processing standards (FIPS) codes 

are a standardized set of numeric or alphabetic codes issued by the National Institute of 

Standards and Technology (NIST) to ensure uniform identification of geographic entities 

through all federal government agencies.
ORISCode G -------

A unique identifier assigned to each power plant in NEEDS. While the ORIS code is unique 

for each plant, all generating units within a plant will typically have the same ORIS code. For 

committed units (i.e., those not currently operating, but firmly anticipated to be operational 

in the future), the entry in this field might be a dummy ORIS code assigned as a placeholder 

unique ID to the committed plant. (Note: ORIS originally referred to the Office of Regulatory 

Information Systems in the Department of Energy (DOE) Energy Information Administration 

(EIA) which was responsible for assigning unique identification codes to utility power plants.)

UnitID H ------- The identifier assigned to each unit/boiler in a given plant.

PlantName I ------- The plant's name.

HeatRate J ------- The unit's heat rate.

OnLineYear K ------- For existing units, this is the year the unit came on line. For committed units, this is the year 

the unit is projected to come on line

RetirementYear L ------- The year a unit is planned to be retired. For units without a firm retirement year, this field 

has a value of 9999

Firing -------

This field, which applies only to boilers, indicates the burner type and configuration (e.g., 

cell, cyclone, FBC (fluidized bed combustion), stoker/SPR, tangential, or vertical). A blank 

appears in instances where the firing characteristics of a boiler are unknown or the unit is a 

not a boiler.

N

The type of electric generating unit, usually defined by the "prime mover" and/or fuels 

burned. "Prime mover" refers to the machine (e.g., engine, turbine, water wheel) that drives 

an electric generator or the device that converts energy to electricity directly (e.g., 

photovoltaic solar and fuel cell(s)).

PlantType M -------

Municipal Solid Waste

Non-Fossil Waste

Nuclear

O/G Steam

Pumped Storage

Solar

Biomass

Coal Steam

Combined Cycle

Combustion Turbine

Fossil Waste

Fuel Cell

Wind

Geothermal

Hydro

IGCC

Landfill Gas

Tires

Cell: boilers that combine 2-3 standard burners into a compact, vertical assembly 

installed on the furnace wall; multiple cells utilized within a furnace.

Cyclone: A special type of burner for coals with low fusion point ashes. 

Combustion occurs within the horizontal burner generating high temperatures 

which turn the ash into molten slag. The term "wet bottom" furnace often 

accompanies the cyclone burner.

FBC: “fluidized bed combustion” where solid fuels are suspended on upwardblowing jets of air, resulting in a turbulent mixing of gas and solids and a tumbling 

action which provides especially effective chemical reactions and heat transfer 

during the combustion process.

Stoker/SPR: stoker boilers where lump coal is fed continuously onto a moving 

grate or chain which moves the coal into the combustion zone in which air is 

drawn through the grate and ignition takes place. The carbon gradually burns off, 

leaving ash which drops off at the end into a receptacle, from which it is removed 

for disposal.

Tangential (also referred to as "corner firing"): burners located along furnace 

corners in multiples of 4. Burner angle is off-set working in conjunction with the 

opposing corner burner to create a vertical, circular swirling combustion zone 

within the furnace.

Turbo (wall fired burner): Burner design for pet coke and low volatile bituminous 

coals (Riley trademark name: "Turbo Furnace"). Hour glass shaped furnace with 

rectangular shaped burners angled downwards.

Wall: standard burner / furnace design used today. Circular burners located on 

the front and rear furnace walls at multiple elevations.

Vertical: standard furnace (assume wall fired)

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EMFControls P -------

This field shows the combination of SO2 scrubbers, NOx post-combustion controls, and 

particulate matter controls that already exist at a unit. The entries in this column are 

compiled from the "NOx Post-CombControl," "Wet/DryScrubber" and "Particulate Matter 

Type" fields. Together with the entry in the "Firing" and "Modeled Fuels" fields, the entries 

in this field are used for the assignment of the Emission Modification Factors (EMFs) for 

mercury. The EMFs enable the model to capture mercury emission reductions that are a 

function of the rank of coal burned (bituminous, subbituminous and lignite), the specific 

burner type, and the configuration of SO2, NOx, and particulate matter control devices. 

Consolidating the controls that impact mercury reductions into this field helps to insure that 

the correct EMFs are assigned to each unit. Note that EMFs are metric of the extent of 

mercury emission reduction achieved by these non-mercury controls, and do not include the 

presence or impact of mercury-specific controls (e.g., ACI).

AA Advanced Overfire Air 

BF Biased Firing (alternate burners)

BOOS Burners-Out-Of-Service

CM

Combustion Modification/Fuel 

Reburning

CO Combustion Optimization

DLNB Dry Low NOx Burners

FR Flue Gas Recirculation

FU Fuel Reburning

H2O Water Injection

LA Low Excess Air 

LN Low NOx Burner

LNB

 

Bottom only)

LNBO

Low NOx Burner Technology w/ Overfire 

Air

LNC1

 

coupled OFA

LNC2 Separated OFA

LNC3 coupled/Separated OFA

LNCB Low NOx Cell Burner

LNF Low NOx Furnace

MR Methane Reburn

N2 Nitrogen

NDI Nitrogen Diluent Injection

NGR Natural Gas Reburn

NH3 Ammonia Injection

OFA Overfire Air

other Other

ROFA Rotating Overfire Air

SC Slagging

SOFA Stationary Overfire Air

STC Staged Combustion

STM Steam Injection

WIR Underfire Air

Year U ------- The model run year from which the parsed results were derived.

BGCI Indicates where a unit is an existin boiler, and existing generator, or a committed unit that is 

not currently in operation

Wet

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This field indicates the SO2 controls which are in existence at a generating unit before the 

model is run. SO2 controls reduce SO2 emissions by using chemical processes to remove SO2 

from the post-combustion emission stream.

R -------

Reagent Injection

C - Committed

------- G - Generator

This field, which applies only to boilers, indicates whether the bottom of the combustion 

chamber is "wet" (i.e., ash is removed from the furnace in a molten state) or "dry" (i.e., the 

boiler has a furnace bottom temperature below the ash melting point and the bottom ash is 

removed as a solid). A blank appears in instances where the bottom characteristics of a 

boiler were not known or the unit was not a boiler.

Bottom O -------

NOxControl Q -------

FossilUnit Indicates whether a unit is fossil-fuel fired

This field indicates the NOx combustion controls which are in existence at a generating unit 

after the model is run. Combustion controls reduce NOx emissions during the combustion 

process generally by regulating flame characteristics such as temperature and fuel-air mixing.

T

S

SO2Control

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Dry Scrubber

Wet Scrubber

B - Boiler

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Fossil

Non-Fossil

Dry
FuelUseWinter X TBtu Projected fuel consumed (TBtu) at the unit in January - April and October - December during 

the year for which the run was parsed. 

FuelUseSummer Y TBtu Projected fuel consumed (TBtu) at the unit in May - September during the year for which the 

run was parsed. 

FuelUseTotal Z TBtu Projected fuel consumed (TBtu) at the unit during the year for which the run was parsed.

BITFuelUseWinter AA TBtu

BITFuelUseSummer AB TBtu

BITFuelUseTotal AC TBtu

SUBFuelWinter AD TBtu

SUBFuelSummer AE TBtu

SUBFuelTotal AF TBtu

LIGFuelWinter AG TBtu

LIGFuelSummer AH TBtu

LIGFuelTotal AI TBtu

GWhWinter AJ GWh Projected generation (GWh) produced by the unit in January - April and October - December 

during the year for which the run was parsed. 

GWhSummer AK GWh Projected generation (GWh) produced by the unit in May - September during the year for 

which the run was parsed. 

GWhTotal AL GWh Projected generation (GWh) produced by the unit during the year for which the run was 

parsed.

CO2Winter AM Mtons (thousands short 

tons)

Projected winter (January - April and October - December) CO2 emissions (MTons) during the 

year for which the run was parsed.

CO2Summer AN Mtons (thousands short 

tons)

Projected summer (May - September) CO2 emissions (MTons) during the year for which the run 

was parsed.

CO2Total AO Mtons (thousands short 

tons) Projected annual CO2 emissions (MTons) during the year for which the run was parsed.

CO2Winter (Metric) AP Mtons (thousands metric 

tons)

Projected winter (January - April and October - December) CO2 emissions MTons (Thousand of 

Metric Tons) during the year for which the run was parsed.

CO2Summer (Metric) AQ Mtons (thousands metric 

tons)

Projected summer (May - September) CO2 emissions MTons (Thousand of Metric Tons) during the 

year for which the run was parsed.

CO2Total (Metric) AR Mtons (thousands metric 

tons)

Projected annual CO2 emissions MTons (Thousand of Metric Tons) during the year for which the run 

was parsed.

RetrofitSO2NOxControls W -------

These nine columns give the projected coal consumption (TBtu), by coal rank, during the 

summer months (May - September), winter months (January - April and October - 

December), and the entire year for which the run was parsed.

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Coal

Fwaste

Geothermal

Solar

Wind

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NaturalGas

Non-Fossil

Nuclear

Scrubber / SNCR

SNCR

Pet. Coke

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Coal Early Retirement

CT Early Retirement

Mercury Control

Scrubber / SCR

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Mercury Control / Coal Early Retirement

O/G Early Retirement

SCR

SCR - O/G Steam

Scrubber

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Scrubber / Mercury Control

Biomass

Summarizes all of the control technologies that a unit has put on. The retrofits are 

cumulative to the year for which the run is parsed. For instance, if the parsed file is for 2020, 

it will include all retrofits projected by the model for the unit through 2020.

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FuelType V This field indicates the type of fuel used by the unit.

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Oil

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CC Early Retirement

Waste Coal

Hydro

LF Gas

MSW
MERWinter AS Tons (short tons) Projected winter (January - April and October - December) mercury emissions (MTons) 

during the year for which the run was parsed.

MERSummer AT Tons (short tons) Projected summer (May - September) mercury emissions (MTons) during the year for which 

the run was parsed.

MERTotal AU Tons (short tons) Projected annual mercury emissions (MTons) during the year for which the run was parsed.

NOXWinter AV Mtons (thousands short 

tons)

Projected winter (January - April and October - December) NOx emissions (MTons) during 

the year for which the run was parsed.

NOXSummer AW Mtons (thousands short 

tons)

Projected summer (May - September) NOx emissions (MTons) during the year for which the 

run was parsed.

NOXTotal AX Mtons (thousands short 

tons) Projected annual NOx emissions (MTons) during the year for which the run was parsed.

SO2Winter AY Mtons (thousands short 

tons)

Projected winter (January - April and October - December) SO2 emissions (MTons) during the 

year for which the run was parsed.

SO2Summer AZ Mtons (thousands short 

tons)

Projected summer (May - September) SO2 emissions (MTons) during the year for which the 

run was parsed.

SO2Total BA Mtons (thousands short 

tons) Projected annual SO2 emissions (MTons) during the year for which the run was parsed.

HCLWinter BB Mtons (thousands short 

tons)

Projected winter (January - April and October - December) HCl emissions (MTons) during the 

year for which the run was parsed.

HCLSummer BC Mtons (thousands short 

tons)

Projected summer (May - September) HCl emissions (MTons) during the year for which the 

run was parsed.

HCLTotal BD Mtons (thousands short 

tons) Projected annual HCl emissions (MTons) during the year for which the run was parsed.

ASHWinter BE Mtons (thousands short 

tons)

Projected winter (January - April and October - December) ash (MTons) during the year for 

which the run was parsed.

ASHSummer BF Mtons (thousands short 

tons)

Projected summer (May - September) ash (MTons) during the year for which the run was 

parsed.

ASHTotal BG Mtons (thousands short 

tons) Projected annual ash (MTons) during the year for which the run was parsed.

FOMCost BH Million US$ / yr Fixed operation and mainetenance (O&M) cost for the unit during the year for which the run 

was parsed

VOMCostWinter BI Million US$ / yr Variable operation and maintenance (O&M) cost for the unit for the winter months (January - 

April and October - December) during the year for which the run was parsed

VOMCostSummer BJ Million US$ / yr Variable operation and maintenance (O&M) cost for the unit for the summer months (May - 

September) during the year for which the run was parsed

VOMCostTotal BK Million US$ / yr Variable operation and maintenance (O&M) cost for the unit during the year for which the 

run was parsed

FuelCostWinter BL Million US$ / yr Fuel cost for the unit for the winter months (January - April and October - December) during 

the year for which the run was parsed

FuelCostSummer BM Million US$ / yr Fuel cost for the unit for the summer months (May - September) during the year for which 

the run was parsed

FuelCostTotal BN Million US$ / yr Fuel cost for the unit during the year for which the run was parsed

CapitalCost BO Million US$ /yr Annualized capital cost expenditures (i.e. added controls and upgrades) for the unit during 

the year for which the run was parsed

Capacity BP MW

The net summer dependable capacity (in megawatts) of the unit available for generation for 

sale to the grid. Net summer dependable capacity is the maximum capacity that the unit can 

sustain over the summer peak demand period reduced by the capacity required for station 

services or auxiliary equipment.

Post Combustion Control and Heat Rate I BQ ------- Summary of the SO2, NOX, and Mercury post-combustion controls installed at the unit during 

the run year, as well as any heat rate improvements made to the unit

Post Combustion Control (Scrubber: Wet/BR ------- Indicates if the unit has a Wet or Dry Scrubber. 

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Baghouse Retrofit (in conjunction with 

either dry FGD, ACI+Toxecon, and/or 

DSI)

BS ------- For some plant configurations, a baghouse is required for some retrofits (deals with meeting 

PM standard as cobenefit, so other PM controls not needed)

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ACI with Toxecon

Dry Scrubber / DSI

DSI

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Dry Scrubber / ACI with Toxecon

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Dry Scrubber