NEEDS v.4.10 User Guide 

The National Electric Energy Data System (NEEDS) is the database of existing and planned-committed units which are modeled in ththat are currently operational in the electric industry are termed as “existing” units. Units that are not currently operating but are firmly the future, and have either broken ground (initiated construction) or secured financing are termed “planned-committed”. NEEDS is maintained in spreadsheet format. Below is a guide to the fields found in NEEDS. 

Field Name Column Definition Key to Recu

Plant Name A The plant's name. UniqueID_Final B 

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. 

ORIS Plant Code C 

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.) 

B Boiler G Generator Boiler/Generator/Committed Unit D An indicator of whether the unit is a boiler, generator, or committed unit. Committed units are those with a future expected in-service date (see “On Line Year”) C Committed Unit 

Unit ID E The identifier assigned to each unit/boiler in a given plant. CAMD Database UnitID F 

Unit-level identifier assigned by EPA's Clean Air Markets Division (CAMD) business system. Unlike other identification codes (e.g., ORIS codes), which are subject to change, once assigned to a unit, the CAMD Database Unit ID does not change. Used primarily for internal tracking purposes at EPA. 
Field Name Column Definition Key to Recu

PlantType G 

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)). 

Biomass Coal Steam Combined Cycle Combustion Turbine Fossil Waste Fuel Cell Geothermal Hydro IGCC Landfill Gas Municipal Solid Waste Non-Fossil Waste Nuclear O/G Steam Pumped Storage Solar Tires Wind 

Combustion Turbine/IC Engine H 

Clarifies the engine type for units with “Combustion Turbine” plant type. An Internal Combustion (IC) Engine is a reciprocating engine which uses pistons to extract energy from a fluid to perform work. A Combustion Turbine is a standalone turbine combusting fuel to drive a generator (a combined cycle less the Heat Recovery Steam Generator (HRSG)). 

Combustion Turbine IC Engine 

Region Name I 

The region, used in the Integrated Planning Model (IPM), where the generating unit is located. IPM regions are defined to enable IPM to accurately represent the operation and structure of U.S. and Canada electric power system. IPM regions are generally subdivisions of the 10 North American Electric Reliability Council (NERC) regions and aggregations of the electricity grid's contiguous control areas. IPM also includes Alaska, Hawaii, Puerto Rico, and the U.S. Virgin Islands. 

See Appen

State Name J State Code K County L County Code M FIPS5 N 

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. 

Capacity (MW) O 

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. 
Field Name Column Definition Key to Recu

Heat Rate (Btu) P The net heat input (in Btu) required to generate 1 kilowatt hour of electricity. It is a measure of a generating unit’s efficiency. On Line Year Q The year in which the unit is commissioned. Retirement Year R The year in which the unit is to be decommissioned. ("9999" indicates that the unit has not been retired.) 

Cell: boilers that combine 2-vertical assembly installed on within a furnace. Cyclone: A special type of bashes. Combustion occurs whigh temps which turn the asbottom" furnace often accomFBC: “fluidized bed combuston upward-blowing jets of airand solids and a tumbling acchemical reactions and heat process. Stoker/SPR: stoker boilers wonto a moving grate or chain combustion zone in which air takes place. The carbon graddrops off at the end into a recdisposal. Tangential (also referred to along furnace corners in mulworking in conjunction with thvertical, circular swirling comTurbo (wall fired burner): Buvolatile bituminous coals (RilHour glass shaped furnace wdownwards. Vertical: standard furnace (a

Firing S 

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. 

Wall: standard burner / furnalocated on the front and rear 

Bottom T 

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. 

Dry Wet 

Cogen? U This field indicates whether a unit is a cogenerator. A unit is considered a Y Yes 
Field Name Column Definition Key to Recu

cogenerator if it produces electricity and another form of useful thermal energy (such as heat or steam), used for industrial, commercial, heating, or cooling purposes. 

N No 

Modeled Fuels V Fuels that are reported to be combusted by the unit. 

Biomass Bituminous Distillate Fuel Oil Fossil Waste Geothermal Hydro Landfill Gas Lignite MSW Natural Gas Non-Fossil Waste Nuclear Fuel Petroleum Coke Pumped Storage Residual Fuel Oil Solar Subbituminous Tires Waste Coal Wind 

Wet/DryScrubber W 

This field indicates if a unit has an SO2 scrubber, and, if so, whether it is a wet or 

dry scrubber. Also known as flue gas desulfurization (FGD) systems, SO2

scrubbers use chemical and physical absorption to remove SO2 from the flue 

gas. Wet scrubbers use a liquid sorbent to remove SO2 and the flue gas leaving 

the absorber is moisture saturated. With dry scrubbers the flue gas leaving the absorber is not saturated. For circulating fluidized bed units (as shown in the "Firing" field), this field indicates whether reagent injection is used for SO2

control. Reagent injection involves adding finely crushed limestone to the fluidized bed. During combustion, the limestone is reduced to lime, the sulfur in the fuel is oxidized to form SO2, and, in the presence of excess oxygen, the SO2

reacts with the lime particles to form calcium sulfate, which can be removed with the bottom ash or collected with the fly ash by a downstream particulate matter (PM) control device. 

 Dry Scrubber Wet Scrubber Reagent Injection 

Scrubber_Online_Year X The first year of operation of an existing or committed SO2 scrubber Scrubber Efficiency Y The removal efficiency of the SO2 scrubber. 

AA Advanced Overfire BF Biased Firing (alterBOOS Burners-Out-Of-SeCM Combustion Modifi

NOx Comb Control Z This field indicates the NOX combustion controls employed by a generating unit. 

Combustion controls reduce NOX emissions during the combustion process 

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

CO Combustion Optim
Field Name Column Definition Key to Recu

DLNB Dry Low NOx BurnFR Flue Gas RecirculaFU Fuel Reburning H2O Water Injection LA Low Excess Air LN Low NOx Burner LNB Low NOx Burner TLNBO Low NOx Burner TLNC1 Low NOx Burner TLNC2 Low NOx Burner TLNC3 Low NOx Burner T

coupled/Separated 

LNCB Low NOx Cell BurnLNF Low NOx Furnace MR Methane Reburn N2 Nitrogen NDI Nitrogen Diluent InjNGR Natural Gas ReburNH3 Ammonia Injection OFA Overfire Air other Other ROFA Rotating Overfire ASC Slagging SOFA Stationary Overfire STC Staged CombustioSTM Steam Injection WIR Underfire Air SCR Selective Catalytic 

NOx Post-CombControl AA 

This column indicates the post-combustion NOX emission controls at a 

generating unit. There are two NOX post-combustion control options: Selective 

Catalytic Reduction (SCR) or Selective Non-Catalytic Reduction (SNCR). Postcombustion controls operate downstream of the combustion process and remove NOx emissions from the flue gas. SNCR Selective Noncatal

SCR_Online_Year AB The first year of operation of an existing or committed SCR SNCR_Online_Year AC The first year of operation of an existing or committed SNCR 

B Baghouse C Cyclone ESP Electrostatic PrecipESPH Hot side electrosta

conditioning 

ESPC Cold side electrost

conditioning 

PM Control AD This field indicates the presence of particulate matter (PM) controls 

WS Wet Scrubber 
Field Name Column Definition Key to Recu

Mercury_Controls AE Dedicated Mercury emission controls in existence at a generating unit ACI (Activated Carbon InjecACI_Online_Year AF The first year of operation of an existing or committed ACI Mercury_Controls Efficiency AG The removal efficiency of the mercury control device. SO2 Permit Rate AH The SO2 emission rate (in lb/mmBtu) limit that applies to the unit due to federal, state or local emission regulations. Uncontrolled NOX Base 

Rate (or “Mode 1 NOX Rate”) 

AI 

The 4 NOX rates in NEEDS allow modeling of any conceivable scenario involving 

NOX controls. The Mode 1 rate applies to units not covered by a NOX control 

policy. Specifically, this is the NOX rate with post-combustion controls shut off. 

For units without post-combustion controls, it’s their uncontrolled NOX rate. 

Controlled NOX Base Rate 

(or “Mode 2 NOX Rate”) AJ 

The 4 NOX rates in NEEDS allow modeling of any conceivable scenario involving 

NOX controls. The Mode 2 rate applies to units covered by a mercury emission 

limit. A unit with post-combustion controls operates them, but a unit without post-combustion controls operates as usual. (Note: In the case of mercury limits, Mode 2 applies since it implies operation of an SCR or SNCR. This equipment, in combination with SO2 and particulate controls, provides reduction 

and capture of mercury as a co-benefit.) 

Uncontrolled NOX Policy 

Rate (or “Mode 3 NOX Rate”) 

AK 

The 4 NOX rates in NEEDS allow modeling of any conceivable scenario involving 

NOX controls. The Mode 3 rate applies to units affected by a seasonal (typically 

summer) NOX policy. The Mode 3 rate is the unit’s NOX rate in the off-season 

(winter). For units with post-combustion controls, this is the NOX rate with postcombustion controls shut off. For units without post-combustion controls, it’s the 

NOX rate with state-of-the-art combustion controls operating. (Exception: In the 

SIP Call region current combustion controls are assumed to be retained.) 

Controlled NOX Policy Rate 

(or “Mode 4 NOX Rate”) AL 

The 4 NOX rates in NEEDS allow modeling of any conceivable scenario involving 

NOX controls. The Mode 4 NOX rate applies to units covered by an annual NOX

policy. For units with SCR, it’s the NOX rate with the SCR operating. For units 

with SNCR, it’s the NOX rate with SNCR operating plus state-of-the-art 

combustion controls operating if required to attain rate limits. For units without post-combustion controls, it’s the NOX rate with state-of-the-art combustion 

controls operating. (Exception: In the SIP Call region current combustion controls are assumed to be retained.) 
Field Name Column Definition Key to Recu

Hg EMF Inputs AM 

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 as shown in the six subsequent "Controlled Hg EMF" and "Uncontrolled Hg EMF" fields. 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 metrics that quantify the extent of mercury emission reduction achieved by these non-mercury controls. The impact of mercury-specific controls (e.g., ACI) is not taken into account in the EMFs. 

Controlled Hg EMF for BIT AN 

Mercury Emission Modification Factor (EMF) when the unit combusts bituminous coal and existing NOx post combustion controls (SCR or SNCR) are operating. “Mercury EMF” is defined as the percentage of fuel mercury left after accounting for the mercury removal obtained by the SO2, NOx, and particulate controls shown in the “EMF_Controls” field. 

Controlled Hg EMF for SUB AO 

Mercury Emission Modification Factor (EMF) when the unit combusts subbituminous coal and existing NOx post combustion controls (SCR or SNCR) 

are operating. 

Controlled Hg EMF for LIG AP Mercury Emission Modification Factor (EMF) when the unit combusts lignite coal and existing NOx post combustion controls (SCR or SNCR) are operating. Uncontrolled Hg EMF for BIT AQ 

Mercury Emission Modification Factor (EMF) when the unit combusts bituminous coal and existing NOx post combustion controls (SCR or SNCR) are not operating. 

Uncontrolled Hg EMF for SUB AR 

Mercury Emission Modification Factor (EMF) when the unit combusts subbituminous coal and existing NOx post combustion controls (SCR or SNCR) are not operating. 

Uncontrolled Hg EMF for LIG AS Mercury Emission Modification Factor (EMF) when the unit combusts lignite\ coal and existing NOx post combustion controls (SCR or SNCR) are not operating. 
Field Name Column Definition Key to Recu

Dispatchable Scrubber AT 

One-time option that allows certain generating units in the model to install a scrubber retrofit at zero capital cost. It applies to generating units known to have existing scrubbers that may not be operating because the original regulatory cause for their installation is no longer present. The model will use this retrofit if the control is economical to operate, but it will not use the retrofit if the control is not economical. This “dispatchable” construct allows modeling behavior in areas transitioning from a more stringent to less stringent regulatory regime (for example, a state affected by CAIR but potentially not affected by the proposed Transport Rule), where some operators may have economic incentive to bypass or reduce operation of a previously installed emission control, while other operators still need to operate the control in order to comply with settlements, state rules, or other past policies regardless of the status of the CAIR program. 

Yes = unit has the dispatcha<blank> = unit does not have 

Dispatchable SCR AU 

One-time option that allows certain generating units in the model to install an SCR retrofit at zero capital cost. It applies to generating units known to have existing SCR that may not be operating because the original regulatory cause for their installation is no longer present. The model will use this retrofit if the control is economical to operate, but it will not use the retrofit if the control is not economical. This “dispatchable” construct allows modeling behavior in areas transitioning from a more stringent to less stringent regulatory regime (for example, a state affected by CAIR but potentially not affected by the proposed Transport Rule), where some operators may have economic incentive to bypass or reduce operation of a previously installed emission control, while other operators still need to operate the control in order to comply with settlements, state rules, or other past policies regardless of the status of the CAIR program. 

Yes = unit has the dispatcha<blank> = unit does not have 

Dispatchable ACI AV 

One-time option that allows certain generating units in the model to install an ACI retrofit at zero capital cost. It applies to generating units known to have existing ACI installations that may not be operating because the original regulatory cause for their installation is no longer present. The model will use this retrofit if the control is economical to operate, but it will not use the retrofit if the control is not economical. This “dispatchable” construct allows modeling behavior in areas transitioning from a more stringent to less stringent regulatory regime, where some operators may have economic incentive to bypass or reduce operation of a previously installed emission control, while other operators still need to operate the control in order to comply with settlements, state rules, or other past policies regardless of the status of the original regulatory program. 

Yes = unit has the dispatcha<blank> = unit does not have 
Appendix I. IPM Model Regions Map 
Appendix II. Mapping of NERC Regions and NEMS Regions with EPA Base Case v.4.10 Model Regions 

NERC 

Region 

NEMS 

Region Model Region Model Region Description 

TRE ERCOT ERCT Texas Regional Entity 

FRCC FL FRCC Florida Reliability Coordinating Council 

MAPP MRO Midwest Regional Planning Organization MRO 

MAIN WUMS Wisconsin-Upper Michigan 

NE NENG New England Power Pool 

DSNY Downstate New York 

LILC Long Island Company 

NYC New York City 

NPCC NY 

UPNY Upstate New York 

RFCO Reliability First Corporation - MISO 

ECAR MECS Michigan Electric Coordination System 

RFCP Reliability First Corporation - PJM 

MACE Legacy Mid-Atlantic Area Council - East 

MAAC MACS Legacy Mid-Atlantic Area Council - South 

MACW Legacy Mid-Atlantic Area Council - West 

RFC 

MAIN COMD Commonwealth Edison 

MAIN GWAY Gateway 

ECAR TVAK Tennessee Valley Authority - MISO-KY 

SOU Southern Company 

TVA Tennessee Valley Authority 

ENTG Entergy 

VACA Virginia-Carolinas 

SERC 

STV 

VAPW Dominion Virginia Power 

SPPN Southwest Power Pool - North SPP SPP 

SPPS Southwest Power Pool - South 

WECC-AZ- AZNM Western Electricity Coordinating Council - Arizona, New Mexico 

NM-SNV RA 

SNV Western Electricity Coordinating Council - Southern Nevada 

WECC- CA-N Western Electricity Coordinating Council - California North 

California ISO CNV 

CA-S Western Electricity Coordinating Council - California South 

PNW Western Electricity Coordinating Council - Pacific Northwest WECC-NWPP NWP 

NWPE Western Electricity Coordinating Council - Northwest Power Pool East 

WECC-RMPA RA RMPA Western Electricity Coordinating Council - Rocky Mountain Power Area 

CNAB Alberta 

CNBC British Columbia 

CNMB Manitoba 

CNNB New Brunswick 

CNNF Newfoundland 

CNNL Labrador 

CNNS Nova Scotia 

CNON Ontario 

CNPE Prince Edward Island 

CNPQ Quebec 

Canada 

CNSK Saskatchewan 

ALSK Alaska 

HAWI Hawaii 

VIUS U.S. Virgin Islands Other 

PRCW Puerto Rico