File: NEEDS v 5 14 User Guide 07-21-15.xlsx

NEEDS v.5.14 User Guide, July 2015

Field Name Column Definition Key to Recurring Column Values

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.)

———

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”)

B = Boiler

G = Generator

C = Committed Unit

Unit ID E The identifier assigned to each unit (boiler and/or generator) 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.

———

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 

stand-alone turbine combusting fuel to drive a generator (a combined cycle 

less the Heat Recovery Steam Generator (HRSG)).

Combustion Turbine

IC Engine

The National Electric Energy Data System (NEEDS) is the database of existing and planned-committed units which are modeled in the EPA Base Case v.5.14. Units that are currently operational 

in the electric industry are termed as “existing” units. Units that are not currently operating but are firmly anticipated to be operational in 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.

It is important to note that the NEEDS database only describes the configuration of the fleet for the model’s first projection year; NEEDS may not include representation of retrofits or retirements 

that may be expected to occur (e.g., pursuant to a finalized enforcement action, as described in the next paragraph) by a date subsequent to the first projection year. One advantage of this 

approach is that the model retains the flexibility to select the least-cost response of affected units to those future-year requirements, instead of requiring the analyst to presuppose a particular 

response (as would be necessary for representation in NEEDS). For example, some enforcement actions allow affected facilities to select from different combinations of retrofits and retirements 

across multiple units by specified deadlines occurring in the future modeling horizon. Under this modeling approach, the NEEDS database would show the “starting point” conditions of the affected 

units (i.e., their expected configuration as of the end of 2015) and the model would be given a separate constraint describing subsequent operating requirements affecting those units (i.e., an 

enforcement action’s terms requiring retrofits or retirements by a future year such as 2020).

The modeling constraints affecting future unit behavior that are imposed as run specifications include federal and state environmental regulations, enforcement action settlements and consent 

decrees, and energy efficiency and renewable portfolio standards. The specific constraints included in the IPM v5.14 platform are described in section 3.9 of the IPM Documentation with updates 

for the v5.14 platform described in the Incremental Documentation, available at www.epa.gov/powersectormodeling. These constraints, as inputs to the model, also appear in the System 

Summary Report (Excel file) on the “All Constraints” worksheet for any given IPM analysis; the constraints included for EPA’s Base Case Using IPM v5.14 are reported on this worksheet in the 

model input/output files posted on EPA’s power sector modeling website, www.epa.gov/powersectormodeling.
File: NEEDS v 5 14 User Guide 07-21-15.xlsx

Region Name I

The region, used in the EPA Base Case v.5.13 using 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 8 

North American Electric Reliability Council (NERC) regions and aggregations 

of the electricity grid's contiguous control areas. 

See Appendix or Figure 3-1 and Table 3-1 of the IPM 

Documentation for a map and description of the IPM regions

State Name J ———

State Code K ———

County L ———

County Code M ———

FIPS5 N ———

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.

———

Heat Rate (Btu/kWh) 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. See Section 3.8 in the 

Documentation for EPA Base Case v.5.13 for more details

———

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.) ———

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.

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 temps 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 

upward-blowing 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 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.

Vertical: standard furnace (assume wall fired)

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

located on the front and rear furnace walls at multiple elevations.

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 

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.

Y (Yes)

N (No)

These five 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 for 

county codes. 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 
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Modeled Fuels V

The fuels that can be combusted or used 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. ———

Scrubber Efficiency_MATS Z

The removal efficiency of the SO2 scrubber assuming an upgrade to preexisting scrubbers that do not meet the MATS HCl removal requirement, 

assuming this is the most cost effective approach for meeting the limit

———

NOx Comb Control AA

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.

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 Low NOx Burner Technology (Dry Bottom only)

LNBO Low NOx Burner Technology w/ Overfire Air

LNC1 Low NOx Burner Technology w/ Closed-coupled OFA

LNC2 Low NOx Burner Technology w/ Separated OFA

LNC3 Low NOx Burner Technology w/ Closed-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

NOx Post-Comb Control AB

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). 

Post-combustion controls operate downstream of the combustion process and 

remove NOx emissions from the flue gas.

SCR Selective Catalytic Reduction

SNCR Selective Noncatalytic Reduction

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

PM Control AE

This field indicates the presence of particulate matter (PM) controls B Baghouse

C Cyclone

ESPH Hot side electrostatic precipitator

ESPC Cold side electrostatic precipitator

WS Wet PM Scrubber

PM Control_MATS AF

This field indicates existing PM controls and, if necessary, exogenously 

determined control upgrades to comply with filterable PM limits. These upgrade 

may be one of 3 ESP upgrades or a fabric filter. See Section 5.6 in 

Documentation for EPA Base Case v.5.13 Using the Integrated Planning 

Model ———

FlueGasConditioning_Flag AG Indicates if the unit has flue gas conditioning ———

Mercury_Controls AH Dedicated Mercury emission controls in existence at a generating unit ACI (Activated Carbon Injection)

ACI_Online_Year AI The first year of operation of an existing or committed ACI ———

Mercury_Controls 

Efficiency_MATS AJ The removal efficiency of the mercury control device. ———

SO2 Permit Rate (lbs/mmBtu) AK

The SO2 emission rate (in lb/mmBtu) limit that applies to the unit due to federal, 

state or local emission regulations. ———

Mode 1 NOx Rate (lbs/mmBtu) AL

The 4 NOx rates in NEEDS allow modeling of any conceivable scenario 

involving NOX controls. Mode 1 “Existing combustion controls, non ozoneseason”: Applies to units not covered by a NOx control policy. Specifically, 

this is typically the NOx rate with post-combustion controls shut off. For units 

without post-combustion controls, it’s their uncontrolled NOx rate. An exception 

to this rule is that if the unit was operating its SCR annually in 2011,then the 

Mode 1 NOx rate reflects the 2011 annual average ETS NOx rate. See Section 

3.9.2 of the Documentation for EPA Base Case v.5.13 for more information on 

NOx Rates in NEEDS

———

Mode 2 NOx Rate (lbs/mmBtu) AM

The 4 NOx rates in NEEDS allow modeling of any conceivable scenario 

involving NOX controls. Mode 3 “State-of-the-art combustion controls, non 

ozone-season”: Represents a unit’s NOx rate in months outside of the ozoneseason, for units only subject to NOx limitations during the ozone season. For 

units with post-combustion controls, this is the NOx rate with post-combustion 

controls shut off. For units without post-combustion controls, it’s the NOx rate 

with state-of-the-art combustion controls operating. See Section 3.9.2 of the 

Documentation for EPA Base Case v.5.13 for more information on NOx Rates 

in NEEDS

———

Mode 3 NOx Rate (lbs/mmBtu) AN

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

involving NOX controls. Mode 3 “Uncontrolled NOx Policy Rate” represents a 

unit’s NOx rate in months outside of the ozone season, for units only subject to 

NOx limitations during the ozone season. For units with post-combustion 

controls, this is the NOx rate with post-combustion controls shut off. For units 

without post-combustion controls, it’s the NOx rate with state-of-the-art 

combustion controls operating. See Section 3.9.2 of the Documentation for 

EPA Base Case v.5.13 for more information on NOx Rates in NEEDS

———

Mode 4 NOx Rate (lbs/mmBtu) AO

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

involving NOX controls. Mode 4 “State-of-the-art combustion controls, ozoneseason”: NOx rate applicable under a NOx policy with a first year of 

compliance post 2011. For SCR units, it’s the NOx rate with the SCR 

operating. For SNCR units, it’s the NOX rate with SNCR operating plus stateof-the-art combustion controls operating. For units without post-combustion 

controls, it’s the NOx rate with state-of-the-art combustion controls operating. 

See Section 3.9.2 of the Documentation for EPA Base Case v.5.13 for more 

information on NOx Rates in NEEDS

———

Hg EMF for BIT_MATS AP

Mercury Emission Modification Factor (EMF) when the unit combusts 

bituminous coal. “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.

———

Hg EMF for SUB_MATS AQ Mercury Emission Modification Factor (EMF) when the unit combusts 

subbituminous coal. ———

Hg EMF for LIG_MATS AR Mercury Emission Modification Factor (EMF) when the unit combusts lignite 

coal. ———

HCL Removal AS Indicates the HCl removal efficiency based upon the exisng HCL controls such 

as SO2 scrubber and DSI. ———

HCL Removal_MATS AT

The HCL removal efficiency of the SO2 scrubber assuming an upgrade to preexisting scrubbers that do not meet the MATS HCl removal requirement, 

assuming this is the most cost effective approach for meeting the limit ———

DSI Unit AU Flag indicating if the unit has dry sorbent injection (DSI) ———

BART Affected Unit AV Flag indicating if the unit is subject to Best Available Retrofit Technology 

(BART) requirements ———

DSI Online Year AW The first year of operation of an existing or committed dry sobent injection 

(DSI) equipment

CCS Removal AX The CO2 removal efficiency of the CCS control

C2G AY Indicate if this unit has been/will be converted from coal to gas
Appendix with Model Regions
NERC Assessment Region AEO 2013 NEMS Region Model Region Model Region Description

ERC_FRNT ERCOT_Tenaska Frontier Generating Station

ERC_GWAY ERCOT_Tenaska Gateway Generating Station

ERC_REST ERCOT_Rest

ERC_WEST ERCOT_West

FRCC FRCC (2) FRCC FRCC

MAP_WAUE MAPP_WAUE

MIS_MAPP MISO_MT, SD, ND

MROE (3), RFCW (11) MIS_WUMS MISO_Wisconsin- Upper Michigan (WUMS)

MIS_IA MISO_Iowa

MIS_MIDA MISO_Iowa-MidAmerican

MIS_MNWI MISO_Minnesota and Western Wisconsin

RFCM (10) MIS_LMI MISO_Lower Michigan

RFCW (11), SRCE (15) MIS_INKY MISO_Indiana (including parts of Kentucky)

MIS_IL MISO_Illinois

MIS_MO MISO_Missouri

NENG_CT ISONE_Connecticut

NENG_ME ISONE_Maine

NENGREST ISONE_MA, VT, NH, RI (Rest of ISO New England)

NYCW (6) NY_Z_J NY_Zone J (NYC)

NYLI (7) NY_Z_K NY_Zone K (LI)

NY_Z_A&B NY_Zones A&B

NY_Z_C&E NY_Zone C&E

NY_Z_D NY_Zones D

NY_Z_F NY_Zone F (Capital)

NY_Z_G-I NY_Zone G-I (Downstate NY)

PJM_EMAC PJM_EMAAC

PJM_PENE PJM_PENELEC

PJM_SMAC PJM_SWMAAC

PJM_WMAC PJM_Western MAAC

PJM_AP PJM_AP

PJM_ATSI PJM_ATSI

PJM_COMD PJM_ComEd

PJM_West PJM West

SRVC (16) PJM_Dom PJM_Dominion

SERC-E SRVC (16) S_VACA SERC_VACAR

S_C_KY SERC_Central_Kentucky

S_C_TVA SERC_Central_TVA SERC-N SRCE (15)

Table 3-1 Mapping of NERC Assessment Regions and NEMS Regions with EPA Base Case v.5.14 Model Regions

NEWE (5)

NYISO

NYUP (8)

ERCOT ERCT (1)

MAPP MROW (4)

MISO

PJM

RFCE (9)

MROW (4)

SRGW (13)

RFCW (11)

ISO-NE
SERC-SE SRSE (14) S_SOU SERC_Southeastern

S_D_AMSO SERC_Delta_Amite South (including DSG)

S_D_N_AR SERC_Delta_Northern Arkansas (including AECI)

S_D_REST SERC_Delta_Rest of Delta (Central Arkansas)

S_D_WOTA SERC_Delta_WOTAB (including Western)

MROW (4) SPP_NEBR SPP Nebraska

SPNO (17), SRGW (13) SPP_N SPP North- (Kansas, Missouri)

SPP_KIAM SPP_Kiamichi Energy Facility

SPP_SE SPP Southeast (Louisiana)

SPP_SPS SPP SPS (Texas Panhandle)

SPSO (18), SRDA (12) SPP_WEST SPP West (Oklahoma, Arkansas, Louisiana)

WECC_ID WECC_Idaho

WECC_NNV WECC_Northern Nevada

WECC_UT WECC_Utah

WEC_CALN WECC_Northern California (including SMUD)

WECC_SF WECC_San Francisco

AZNM (19) WECC_IID WECC_Imperial Irrigation District (IID)

WEC_LADW WECC_LADWP

WEC_SDGE WECC_San Diego Gas and Electric

WECC_SCE WECC_Southern California Edison

WECC_MT WECC_Montana

WECC_PNW WECC_Pacific Northwest

NWPP (21), RMPA (22) WECC_WY WECC_Wyoming

RMPA (22) WECC_CO WECC_Colorado

WECC_AZ WECC_Arizona

WECC_NM WECC_New Mexico

WECC_SNV WECC_Southern Nevada

CN_AB Alberta

CN_BC British Columbia

CN_MB Manitoba

CN_NB New Brunswick

CN_NF Newfoundland

CN_NL Labrador

CN_NS Nova Scotia

CN_ON Ontario

CN_PE Prince Edward Island

CN_PQ Quebec

CN_SK Saskatchewan

Canada

Northwest (NORW) NWPP (21)

Rockies (Rock)

Desert Southwest (DSW) AZNM (19)

Basin (BASN) NWPP (21)

Northern California (CALN) CAMX (20)

Southern California (CALS) CAMX (20)

SERC-W SRDA (12)

SPP SPSO (18)