NEEDS v.6 User Guide, June 2018

The National Electric Energy Data System (NEEDS) is the database of existing and planned-committed units which are modeled in the EPA Initial Run v.6. 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".

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. Underthis modeling approach, the NEEDS database would show the "starting point" conditions of the affected units (i.e., theirexpected configuration as of the end of
2020) 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 2025).

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 v.6 platform are described in section 3.9 of the IPM Documentation available at

https://www.epa.gov/airmarkets/clean-air-markets-power-sector-modeling. These constraints, as inputs to the model, also appear in the RPT Replacement Files (Excel file) in the "Environmental Measures"
workbook for any given IPM analysis; the constraints included for EPA's Initial Run Using IPM v.6 are reported on this worksheet in the model input/output files posted on EPA's power sector modeling website,
https://www.epa.gov/airmarkets/clean-air-markets-power-sector-modeling

NEEDS is maintained in spreadsheet format. Below is a guide to the fields found in NEEDS.

Field Name

Column

Definition

Key to Recurring Column Values

Plant Name

The plant's name.

UniquelD_Final

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

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

An indicator of whether the unit is a boiler, generator, or committed unit. Committed units
are those with a future expected in-seivice date (see "On Line Year")

B = Boiler
G = Generator
C = Committed Unit

Unit ID

The identifier assigned to each unit (boiler and/or generator) in a given plant.

CAMD Database UnitID

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

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

0/G Steam

Pumped Storage

Solar

Tires

Wind

Combustion Turbine/IC Engine

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

Region Name

The region, used in the EPA Initial Run v.6 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

File: NEEDS v 6 User Guide June 2018.xlsx

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State Name

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

State Code

County

County Code

issued by the National Institute of Standards and Technology (NIST) to ensure uniform
identification of geographic entities through all federal government agencies.

FIPS5

Capacity (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 seivices or auxiliary equipment.

Heat Rate (Btu/kWh)

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's Power
Sector Modelinq Platform 6 usinq IPM for more details.

On Line Year

The year in which the unit is commissioned.

Retirement Year

The year in which the unit is to be decommissioned. ("9999" indicates that the unit has not
been retired.)

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.

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

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?

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, heatinq, orcoolinq purposes.

Y (Yes)
N (No)

Modeled Fuels

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

File: NEEDS v 6 User Guide June 2018.xlsx

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Wet/DryScrubber

W

This field indicates if a unit has an S02 scrubber, and, if so, whether it is a wet or dry
scrubber. Also known as flue gas desulfurization (FGD) systems, S02 scrubbers use
chemical and physical absorption to remove S02 from the flue gas. Wet scrubbers use a
liquid sorbent to remove S02 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 S02 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 S02, and, in the presence of excess oxygen, the S02
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 S02 scrubber



Scrubber Efficiency

Y

The removal efficiency of the S02 scrubber.



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.

AA Advanced Overfire Air

BF Biased Firing (alternate burners)

BOOS Burners-Out-Of-Seivice

CM Combustion Modification/Fuel Reburning

CO Combustion Optimization

DLNB Dry Low NOx Burners

FR Flue Gas Recirculation

FU Fuel Reburning

H20 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

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). 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

AB

The first year of operation of an existing or committed SCR



SNCR Online Year

AC

The first year of operation of an existinq or committed SNCR



PM Control

AD

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 Wfit PM Scrubber

FlueGasConditioninq Flaq

AE

Indicates if the unit has flue qas conditioninq



Mercury Controls

AF

Dedicated Mercury emission controls in existence at a qeneratinq unit

ACI (Activated Carbon Injection)

ACI Online Year

AG

The first year of operation of an existinq or committed ACI



Mercury Controls Efficiency

AH

The removal efficiency of the mercury control device.



S02 Permit Rate (Ibs/mmBtu)

Al

The S02 emission rate (in Ib/mmBtu) limit that applies to the unit due to federal, state or
local emission regulations.



File: NEEDS v 6 User Guide June 2018.xlsx

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The 4 NOx rates in NEEDS allow modeling of any conceivable scenario involving NOX
controls. Mode 1 and Mode 2 reflect a unit's emission rates with its existing configuration of
combustion and post-combustion (i.e., SCR orSNCR) controls.



Mode 1 NOx Rate (Ibs/mmBtu)

AJ

• For a unit with an existing post-combustion control, mode 1 reflects the existing post-
combustion control not operating and mode 2 the existing post-combustion control
operating. However:
o If a unit has operated its post-combustion control year round during 2017,
2016, 2015, 2014, 2011, 2009, and 2007 years then mode 1 = mode 2,
which reflects that the control will likely continue to operate year round,
o If a unit has not operated its post-combustion control during 2017, 2016,
2015, 2014, 2011, 2009, and 2007 years, mode 1 will be based on
historic



Mode 2 NOx Rate (Ibs/mmBtu)

AK

data and mode 2 will be calculated using the method described under
Question 3 in Attachment 3 1.
o If a unit has operated its post-combustion control seasonally in recent
years (i.e., either only in the summer or winter, but not both), mode 1 will
be based on historic data from when the control was not operating, and
mode 2 will be based on historic data from when the SCR was operating.

• For a unit without an existing post-combustion control, mode 1 = mode 2 which reflects the
unit's historic NOx rates from a recent year.

See Section 3.9.2 of the Documentation for EPA Initial Run v.5.13 for more information on
NOx Rates in NEEDS.



Mode 3 NOx Rate (Ibs/mmBtu)

AL

The 4 NOx rates in NEEDS allow modeling of any conceivable scenario involving NOX
controls. Mode 3 and Mode 4 emission rates parallel modes 1 and 2 emission rates, but are
modified to reflect installation of state-of-the-art combustion controls on a unit if it does not
already have them.



Mode 4 NOx Rate (Ibs/mmBtu)

AM

• For units that already have state-of-the-art combustion controls: Mode 3 = mode 1 and
mode 4 = mode 2.

See Section 3.9.2 of the Documentation for EPA Initial Run v.5.13 for more information on
NOx Rates in NEEDS.



Hg EMF for BIT

AN

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 S02, NOx, and particulate controls.



Hg EMFforSUB

AO

Mercury Emission Modification Factor (EMF) when the unit combusts subbituminous coal.



Hq EMF for LIG

AP

Mercury Emission Modification Factor (EMF) when the unit combusts lignite coal.



HCL Removal

AQ

Indicates the HCI removal efficiency based upon the exisng HCL controls such as S02
scrubber and DSI.



DSI Unit

AR

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



DSI Online Year

AS

The first year of operation of an existing or committed dry sobent injection (DSI) equipment



CCS

AT

Flag indicating if the unit has carbon capture and sequestration (CCS)



CCS Removal

AU

The C02 removal efficiency of the CCS control



C2G

AV

Flaq Indicatinq if this unit has been/will be converted from coal to qas



C2G Online Year

AW

The first year of operation of an existinq or committed coal-to-qas (C2G) conversion



BART Affected Unit

AX

Flag indicating if the unit is subject to Best Available Retrofit Technology (BART)
requirements



File: NEEDS v 6 User Guide June 2018.xlsx

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Appendix with Model Regions

¦ EPA Initial Case v.6 Regions

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Table 3-1 Mapping of NERC Regions and NEMS Regions with EPA Platform v6 Model Regions

NERC Assessment Region

AEO 2017 NEMS Region |

Model Region

| Model Region Description



ERCT (1)

ERCREST

ERCOTRest



ERCT (1)

ERCGWAY

ERCOTTenaska Gateway Generating Station

ERCOT

ERCT (1)

ERCFRNT

ERCOTTenaska Frontier Generating Station



ERCT (1)

ERC_WEST

ERCOT_West



ERCT (1)

ERCPHDL

ERCOTPanhandle

FRCC

FRCC (2)

FRCC

FRCC

MAPP

MROW (4)

MIS_MAPP

MISO_MT, SD, ND



SRGW (13)

MISJL

MiSOJiiinois



RFCW (11), SRCE (15)

MISINKY

MISOIndiana (including parts of Kentucky)



MROW (4)

MISJA

MISOJowa



MROW (4)

MIS_MIDA

MISO_iowa-MidAmerican



RFCM (10)

MIS_LMI

MISO_Lower Michigan



SRGW (13)

MIS_MO

MISO_Missouri

MISO

MROE (3), RFCW (11)

MIS_WUMS

MISO_Wisconsin- Upper Michigan (WUMS)



MROW (4)

MIS_MNWI

MISO Minnesota and Western Wisconsin



SRDA (12)

MIS_WOTA

MISO_WOTAB (including Western)



SRDA (12)

MIS_AMSO

MISO_Amite South (including DSG)



SRDA (12)

MIS_AR

MISOArkansas



SRDA (12)

MIS_D_MS

MISOMississippi



SPSO (18)

MIS_LA

MISO Louisiana



NEWE (5)

NENG_CT

ISONEConnecticut

ISO-NE

NEWE (5)

NENGREST

ISONE_MA, VT, NH, Rl (Rest of ISO New England)



NEWE (5)

NENG_ME

ISONEMaine



NYUP (8)

NY_Z_C&E

NYZone C&E



NYUP (8)

NY_Z_F

NY_Zone F (Capital)



NYUP (8)

NY_Z_G-I

NY_Zone G-l (Downstate NY)

NYISO

NYCW (6)

NY_Z_J

NY Zone J (NYC)



NYLI (7)

NY_Z_K

NY Zone K (LI)



NYUP (8)

NY_Z_A

NY_Zone A (West)



NYUP (8)

NY_Z_B

NY Zone B (Genesee)



NYUP (8)

NY_Z_D

NY Zone D (North)



RFCE (9)

PJM_WMAC

PJM_Western MAAC



RFCE (9)

PJM_EMAC

PJM_EMAAC



RFCE (9)

PJM_SMAC

PJM_SWMAAC



RFCW (11)

PJM_West

PJM West

PJM

RFCW (11)

PJM_AP

PJM_AP



RFCW (11)

PJM_COMD

PJM_ComEd

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RFCW (11)

PJM_ATSI

PJM_ATSI



SRVC (16)

PJM_Dom

PJM_Dominion



RFCE (9)

PJM_PENE

PJM PENELEC

SERC-E

SRVC (16)

S_VACA

SERC VACAR



SRCE (15)

S_C_KY

SERCCentralKentucky

SERC-N

SRDA (12)

S_D_AECI

SERCDeltaAECI



SRCE (15)

S_C_TVA

SERCCentralTVA

SERC-SE

SRSE (14)

S_SOU

SERC Southeastern



MROW (4)

SPP_NEBR

SPP Nebraska



SPNO (17), SRGW(13)

SPP_N

SPP North- (Kansas, Missouri)

SPP

SPSO (18)

SPP_KIAM

SPPKiamichi Energy Facility

SPSO (18), SRDA (12)

SPP_WEST

SPP West (Oklahoma, Arkansas, Louisiana)



SPSO (18)

SPP_SPS

SPP SPS (Texas Panhandle)



MROW (4)

SPP_WAUE

SPP_WAUE



CAMX (20)

WEC_CALN

WECC_Northern California (not including BANC)

California/Mexico (CA/MX)

CAMX (20)
CAMX (20)

WEC_LADW
WEC_SDGE

WECC_LADWP

WECC San Diego Gas and Electric



CAMX (20)

WECC_SCE

WECC Southern California Edison



NWPP (21)

WECC_MT

WECC_Montana



CAMX (20)

WEC_BANC

WECC_BANC



NWPP (21)

WECC_ID

WECC_ldaho

Northwest Power Pool (NWPP)

NWPP (21)

WECC_NNV

WECC_Northern Nevada



AZNM (19)

WECC_SNV

WECC_Southern Nevada



NWPP (21)

WECC_UT

WECC_Utah



NWPP (21)

WECC_PNW

WECC_Pacific Northwest

Rocky Mountain Reserve Group (RMRG)

RMPA (22)
NWPP (21), RMPA (22)

WECC_CO
WECC_WY

WECCColorado
WECC_Wyoming



AZNM (19)

WECC_AZ

WECC_Arizona

Southwest Reserve Sharing Group (SRSG)

AZNM (19)

WECC_NM

WECC_New Mexico



AZNM (19)

WECCJID

WECC_lmperial Irrigation District (IID)





CNAB

CanadaAlberta





CN_BC

Canada British Columbia





CN_MB

CanadaManitoba





CNNB

Canada_New Brunswick





CN_NF

Canada_New Foundland

Canada



CN_NL
CN_PE
CN_NS
CN_ON
CN_PQ
CN SK

CanadaLabrador

Canada Prince Edward island

Canada Nova Scotia

CanadaOntario

CanadaQuebec

Canada Saskatchewan

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