THE EMISSIONS & GENERATION RESOURCE INTEGRATED DATABASE 

FOR 2012 (eGRID2012) TECHNICAL SUPPORT DOCUMENT

Prepared for: 

U.S. Environmental Protection Agency 

Office of Atmospheric Programs 

Clean Air Markets Division 

Washington, DC 20460 

Prepared by: 

TranSystems|E.H. Pechan, formerly E.H. Pechan & Associates, Inc. 

5528-B Hempstead Way 

Springfield, VA 22151 

April 2012 

Contract No. EP-D-06-001 

Work Assignment No. 2-04 

i 

NOTICES 

This document has been reviewed by the Clean Air Markets Division (CAMD), Office of Atmospheric 

Programs (OAP), U.S. Environmental Protection Agency (EPA), and approved for distribution. 

This document is available to the public through the EPA eGRID website at http://www.epa.gov/egrid . 

ACKNOWLEDGMENTS 

This edition of eGRID was developed under the leadership of EPA’s Mr. Art Diem, Clean Air Markets 

Division (CAMD), and TranSystems|E.H. Pechan’ eGRID Team Manager, Dr. Susy Rothschild, who also 

prepared all the earlier editions of eGRID. Ms. Cristina Quiroz, Team member and Environmental 

Engineer at TranSystems|E.H Pechan, provided valuable analysis and support. The eGRID system was 

conceived of by Mr. Rick Morgan, former EPA Senior Energy Analyst in the Office of Atmospheric 

Programs. The cover graphics were supplied by the National Renewable Energy Laboratory. 
ii 

CONTENTS 

Page

ACKNOWLEDGMENTS ............................................................................................................................. i

ABBREVIATIONS AND ACRONYMS ..................................................................................................... v

SECTION I. INTRODUCTION .................................................................................................................. 1

SECTION II. SUMMARY OF eGRID2012 DATA .................................................................................... 3

 A. eGRID FILES ..................................................................................................................... 3

 B. WHAT’S NEW IN eGRID2012 ......................................................................................... 4

 C. USES AND USERS OF eGRID ......................................................................................... 5

 D. eGRID SOURCES .............................................................................................................. 8

SECTION III. eGRID METHODOLOGY .................................................................................................. 9

 A. ESTIMATION OF EMISSIONS ........................................................................................ 9

 1. Unadjusted Emission Estimates for Year 2009 ................................................................... 9

 2. Annual Emission Estimates for CO2, SO2, and NOx ......................................................... 10

 3. Annual Emission Estimates for CH4 and N2O .................................................................. 11

 4. Annual Emission Estimates for Mercury (Hg) ................................................................. 11

 5. Ozone Season Emission Estimates for NOx ...................................................................... 12

 6. Adjusted Emission Estimates ............................................................................................ 12

 7. Adjustments for Biomass .................................................................................................. 12

 8. Adjustments for CHP ........................................................................................................ 14

 9. Emission Rate Estimates ................................................................................................... 15

 B. TREATMENT OF PLANT OWNERSHIP ...................................................................... 19

 C. DETERMINATION OF PLANT PRIMARY FUEL ....................................................... 20

 D. ESTIMATION OF RESOURCE MIX ............................................................................. 22

 E. DETERMINATION OF PLANT AGGREGATION LINKS ........................................... 23

 1. NERC Region ................................................................................................................... 23

 2. eGRID Subregion ............................................................................................................. 24

 3. Power Control Area .......................................................................................................... 25

 F. TREATMENT OF AGGREGATION LEVELS .............................................................. 32

SECTION IV. SPECIFIC eGRID IDENTIFIER CODES, NAME CHANGES AND ASSOCIATIONS 33

 A. PLANT LEVEL ................................................................................................................ 33

 B. EGC, COMPANY LEVEL ............................................................................................... 33

SECTION V. DESCRIPTION OF DATA ELEMENTS ........................................................................... 35

 A. THE BLR (BOILER) FILE .............................................................................................. 35

 B. THE GEN (GENERATOR) FILE .................................................................................... 42

 C. THE PLNT (PLANT) FILE .............................................................................................. 45

 D. THE ST (STATE) FILE ................................................................................................... 60

 E. THE PCAL (PCA) FILE ................................................................................................... 66

 F. THE SRL (eGRID SUBREGION) FILE .......................................................................... 66

 G. THE NRL (NERC REGION) FILE .................................................................................. 66

 H. THE US (U.S.) FILE ........................................................................................................ 66

 I. THE REGIONAL GRID GROSS LOSS FILE ................................................................ 66
iii 

SECTION VI. REFERENCES .................................................................................................................. 69

APPENDIX A. eGRID2012 FILE STRUCTURE - VARIABLE DESCRIPTIONS FOR 2009 DATA 

YEAR ........................................................................................................................................................ A-1

APPENDIX B. eGRID2012 eGRID SUBREGION AND NERC REGION REPRESENTATIONAL 

MAPS ........................................................................................................................................................ B-1

TABLES

Page

Table III-1 Comparison of 100-Year GWPs ....................................................................................... 11 

Table III-2 Municipal Solid Waste MSB and MSF Splits .................................................................. 13 

Table III-3 Floors for Power to Heat Ratio and ELCALLOC............................................................. 15 

Table III-4 eGRID2012 Year 2009 Grid Gross Loss (%) ................................................................... 18 

Table III-5 Plant Primary Fuel ............................................................................................................ 21 

Table III-6 Plant Primary Fuel Generation Category .......................................................................... 22 

Table III-7 NERC Region Acronym and Names for eGRID .............................................................. 24 

Table III-8 eGRID Subregion Acronym and Names for eGRID ........................................................ 25 

Table III-9 PCA – NERC Region Relationship .................................................................................. 26 

Table III-10 PCA – MISO – eGRID Subregion – NERC Region Relationship.................................... 29 

Table A-1 eGRID2012 Version 1.0 File Structure .......................................................................... A-1 

FIGURES

Page

Figure III-1 Examples of Plant Through NERC Linkages ................................................................... 23 

Figure B-1 eGRID2012 eGRID Subregion Representational Map ................................................... B-1 

Figure B-2 eGRID2012 NERC Region Representational Map ......................................................... B-2 
iv 

[This page intentionally left blank.] 
v 

ABBREVIATIONS AND ACRONYMS 

40 CFR Part 75 Code of Federal Regulations Title 40 Part 75, which specifies the air emissions 

monitoring and reporting requirements delineated in EPA regulations 

AB 32 Assembly Bill 32 - California Global Warming Solutions Act 

AR4 Fourth Intergovernmental Panel on Climate Change Assessment 

BACT Best Available Control Technology 

BBtu Billion Btu 

Btu British thermal unit 

CAMD Clean Air Markets Division 

CEM Continuous Emissions Monitoring 

CHP Combined heat and power (cogeneration) 

CH4 Methane 

CO2 Carbon dioxide 

CO2e Carbon dioxide equivalent 

DOE U.S. Department of Energy 

EEA Energy and Environmental Analysis, an ICF International Company 

EF Emission factor 

eGRID Emissions & Generation Resource Integrated Database 

eGRID96 Emissions & Generation Resource Integrated Database for the year 1996 

(1995 data) 

eGRID97 Emissions & Generation Resource Integrated Database for the year 1997 

(1995-1996 data) 

eGRID2000 Emissions & Generation Resource Integrated Database for the year 2000 

(1996-1998 data) 

eGRID2002 Emissions & Generation Resource Integrated Database for the year 2002 

(1996-2000 data) 

eGRID2006 Emissions & Generation Resource Integrated Database for the year 2006 

(2004 data) 

eGRID2007 Emissions & Generation Resource Integrated Database for the year 2007 

(2004 and 2005 data) 

eGRID2010 Emissions & Generation Resource Integrated Database for the year 2010 

(2007 and 2005 and 2004 data) 

eGRID2012 Emissions & Generation Resource Integrated Database for the year 2012 

(2009 and 2007, 2005, and 2004 data) 

EGC Electric generating company 

EIA Energy Information Administration 

EPA U.S. Environmental Protection Agency 

ERG Eastern Research Group 

ETS Emissions Tracking System 

FERC Federal Energy Regulatory Commission 

FIPS Federal Information Processing Standards 

GATS Generation Attribute Tracking System 

GHG Greenhouse gas 

GIS Geographic Information System 

GWh Gigawatt-hour 

GWP Global warming potential 

Hg Mercury 

HHV Higher heating value 

ICF ICF International 
vi 

ID Identifier 

IPCC Intergovernmental Panel on Climate Change 

IPM Integrated Planning Model (developed by ICF) 

ISO Independent System Operator 

kWh Kilowatt-hour 

LAER Lowest Achievable Emission Rate 

lb Pound 

MISO Midwest Independent Transmission System Operator 

MMBtu Million Btu 

MMcf Million cubic feet 

MSW Municipal Solid Waste 

MW Megawatt 

MWC Municipal Waste Combustor 

MWh Megawatt-hour 

NATCARB Distributed National Carbon Sequestration Database and Geographic Information 

System 

NERC North American Electric Reliability Corporation 

NESCAUM Northeast States for Coordinated Air Use Management 

NETL National Energy Technology Laboratory 

NGO Nongovernmental Organization 

NIST National Institute of Standards and Technology 

NOx Nitrogen oxides 

NREL National Renewable Energy Laboratory 

N2O Nitrous oxide 

OAP Office of Atmospheric Programs 

OMEGA JV Ohio Municipal Electric Generation Agency Joint Ventures 

ORIS Office of the Regulatory Information System 

ORISPL Office of the Regulatory Information System PLant code 

ORNL Oak Ridge National Laboratory 

OTC Ozone Transport Commission 

OTR Ozone Transport Region 

PCA Power control area 

RACT Reasonably Available Control Technology 

RECS Renewable Energy Credits 

RGGI Regional Greenhouse Gas Initiative 

RPS Renewable Portfolio Standards 

RTO Regional Transmission Organization 

SAR Second Intergovernmental Panel on Climate Change Assessment 

SAS Statistical Analysis System 

SO2 Sulfur dioxide 

TAR Third Intergovernmental Panel on Climate Change Assessment 

TS|Pechan TranSystems|E.H. Pechan, formerly E.H. Pechan & Associates, Inc. 

USBIA U.S. Bureau of Indian Affairs 

USBR U.S. Bureau of Reclamation 

USCE U.S. Army Corps of Engineers 
1 

SECTION I. INTRODUCTION 

The Emissions & Generation Resource Integrated Database (eGRID) is a comprehensive source of data 

on the environmental characteristics of almost all electric power generated in the United States. The 

preeminent source of emissions data for the electric power sector, eGRID is based on available plantspecific data for all U.S. electricity generating plants that provide power to the electric grid and report 

data to the U.S. government. Data reported include generation in megawatt-hour (MWh); resource mix 

(for renewable and nonrenewable generation); emissions in tons for carbon dioxide (CO2), nitrogen 

oxides (NOx), and sulfur dioxide (SO2); emissions in pounds for methane (CH4), nitrous oxide (N2O) and 

mercury (Hg); emission rates for CO2, NOx, and SO2 (in both pounds per megawatt-hour [lb/MWh]) and 

pounds per million British thermal unit [lb/MMBtu]) and for CH4, N2O, and Hg (in pounds per gigawatthour [lb/GWh]) and Hg (in pounds per billion Btu [lb/BBtu]); heat input in MMBtu; and nameplate 

capacity in megawatts (MW). eGRID reports this information on an annual basis (as well as by ozone 

season for NOx emissions and emission rates, net generation and resource mix, and heat input) at different 

levels of aggregation (plant, companies, and grid regions of the country). 

The newest and eighth edition of eGRID, eGRID2012 Version 1.0, released in April 2012, includes one 

Excel workbook with year 2009 data. The eGRID workbook includes eight year 2009 data files – boiler, 

generator, plant, state, power control area, eGRID subregion, NERC region, and U.S. -- and a ninth file 

that displays the grid gross loss and the variables that are used in its estimation for year 2009. For this 

eGRID edition, eGRID2012’s date in the name represents the year in which the eGRID data have been 

released. 

Previous releases of eGRID include the following: 

 The 1996 eGRID (eGRID96) was first released in December 1998; the 1997 eGRID 

(eGRID97) with 1996 and 1997 data, was first released in December 1999; and the 2000 

eGRID (eGRID2000), with 1996 and 1997 data as in eGRID97, and 1998 data, was 

released in March and September 2001. 

 

 eGRID2002, with preliminary 2000 data, was first released as Version 1.0 in December 

2002 and with 1996-2000 data as Version 2.0 in April 2003 and Version 2.01 in May 

2003. 

 eGRID2006 Version 1.0, with the year 2004 plant spreadsheet file, was first released in 

December 2006; Version 2.0, which includes one Excel workbook with an updated plant 

file, as well as the boiler and generator files for year 2004, was released in early April 

2007; and Version 2.1, with the complete set of files – boiler, generator, plant, state, EGC 

location (operator)- and owner-based, parent company location (operator)- and ownerbased, power control area, eGRID subregion, and North American Electric Reliability 

Corporation (NERC) region – was released in late April 2007 and updated for typos in 

May 2007. 

 eGRID2007 Version 1.0 was released in October 2008 and Version 1.1 was released in 

January 2009, both with two Excel workbooks with year 2005 data (plant and 

aggregation) and one Excel workbook with years 2004 and 2005 data (ImportExport). 

 eGRID2010 Version 1.0 was released on February 23, 2011 and Version 1.1 was released 

May 20, 2011, including three Excel workbooks with year 2007 data as well as data for 
2 

years 2004 and 2005 (the same as those included in eGRID2007). Import-export data for 

years 2007, 2005, and 2004 are also included. 

eGRIDweb version 1.0, a web-based eGRID user friendly application with years 2005 and 2004 

eGRID2007 data, was released on April 27, 2009 by the U.S. EPA. For further information about this 

application, which allows the user to select, view, print, and download eGRID data; read the eGRIDweb 

Users Manual (TS|Pechan, 2009) that can be downloaded from the eGRID website or the Help tab on the 

application, which can be accessed either at http://cfpub.epa.gov/egridweb/index.cfm or through the 

eGRID website, http://www.epa.gov/egrid. This web-based application supplants an earlier one that was 

downloaded onto a user’s PC and displayed data years 1996-2000 for eGRID2002; see that Users Manual 

for details (TS|Pechan, 2003b). 

Three papers have been written to clarify issues and respond to questions about eGRID. The first one, 

“Total, Non-baseload, eGRID Subregion, State? Guidance on the Use of eGRID Output Emission Rates” 

(Rothschild and Diem, 2009), can be obtained from the EPA website, 

http://www.epa.gov/ttn/chief/conference/ei18/session5/rothschild.pdf, or downloaded from the 

eGRIDweb Reports tab. The second one, “The Value of eGRID and eGRIDweb to GHG Inventories” 

(Rothschild. Diem, Quiroz, and Salhotra, 2010), presented at the EUEC 2010 Environmental Conference, 

is available for download from the eGRID website at 

http://www.epa.gov/cleanenergy/documents/egridzips/The_Value_of_eGRID_Dec_2009.pdf. 

The third one, “eGRID: An Efficient Way to Value the GHG Emissions Reduction Effects of Energy 

Efficiency” (Diem, Rothschild, and Quiroz, 2011), is a paper that supplemented a poster presentation at 

the Boston August 2011 International Energy Program Evaluation Conference. 

Further, in January 2012, “eGRID Data for Carbon Footprinting Electricity Purchases,” (Diem, 

Rothschild, and Quiroz, 2012a) was presented at the EUEC 2012 Environmental Conference; and a 

paper/poster/podium presentation for “When to Use Which eGRID Data Year of GHG Emission Factors: 

Several Scenarios Presented” (Diem, Rothschild, and Quiroz, 2012b) has been accepted to the EPA 2012 

International Emission Inventory Conference in August 2012. 

Although eGRID is based on more than existing Federal data sources, its development required 

substantial attention to quality control. Accurate matching of entities from different databases required 

great care, even where identification codes were available. Inconsistencies between data sources, missing 

data, and ambiguous data necessitated adjustments to values of individual data elements, especially 

identification data. In general, however, questionable data have not been altered, except with regard to 

the relationship of plants to the power grid. 

This document provides a description of the eGRID2012 year 2009 data elements in the 8 Excel 

spreadsheet files for each level of aggregation, as well as the grid gross loss file. Section II provides a 

summary of the database; Section III is the Methodology Section and presents the methodology for 

emissions estimations, including adjustments for biomass and combined heat and power (CHP), among 

other issues; Section IV includes discussion of eGRID specific identification codes, name changes and 

associations; and Section V describes the data elements in detail. There is a set of Reference citations in 

Section VI and two Appendices – Appendix A, which includes the file structure, and Appendix B, which 

includes the eGRID subregion and NERC region representational maps (which remain unchanged from 

the previous edition of eGRID) (NERC, 2012b). 
3 

SECTION II. SUMMARY OF eGRID2012 DATA 

A. eGRID FILES 

eGRID2012 contains electric power data at different levels of aggregation. As the database name implies, 

the focus of the data files is on two areas: generation and emissions. Generation is expressed in both 

MWh and as a percentage (called “resource mix” – generation of a certain fuel or resource type divided 

by total generation). CO2, NOx, and SO2 emissions are expressed in tons and CH4, N2O, and Hg emissions 

are expressed in pounds. Emission rates are expressed in lb/MWh, lb/MMBtu for CO2, NOx, and SO2; in 

lb/GWh for CH4, N2O, and Hg; and in lb/BBtu for Hg. The measurement units are United States units, not 

metric units. 

Data users should take note that eGRID’s emissions and emission rates are calculated at the sources of 

generation and do not account for losses from transmission and distribution infrastructures. Please refer 

to section IIIA9c on p. 17 for how to account for line losses when assigning emission rates to estimate 

indirect emissions associated with electricity purchases. Aggregated eGRID data only accounts for U.S. 

generation that takes place within the aggregated area and does not account for any electricity that is 

imported from or exported to other areas. The grid gross loss calculation, however, does account for U.S. 

regional interchanges with other U.S. regions as well as Canada and Mexico. 

eGRID2012 includes not only year 2009 data but also the year 2004 data from eGRID2006, which were 

configured to reflect the industry’s structure as was known by October 1, 2006; the year 2005 data from 

eGRID2007, which were configured to reflect the industry’s structure as was known by December 21, 

2007; and the year 2007 data from eGRID2010, which were configured to reflect the industry’s structure 

as was known by December 31, 2010. Only certain eGRID files can be linked from year 2009 to years 

2007, 2005, or 2004. The files that can be linked include the NERC region (by NERC acronym), eGRID 

subregion (by eGRID subregion acronym), state (by postal state abbreviation), plant (by eGRID plant 

sequence number), and U.S. 

The eGRID year 2009 plant data are linked to the year 2007 plant data with the inclusion of the year 2007 

plant file’s SEQPLT07 variable in the year 2009 plant file; are linked to the year 2005 plant data with the 

inclusion of the year 2005 plant file’s SEQPLT05 variable in the year 2009 plant file; and linked to the 

year 2004 plant date with the inclusion of the year 2004 plant file’s SEQPLT04 variable in the year 2009 

plant file – when the plants match. (Although most plants will match on ORISPL, there are some 

exceptions, so it is completely accurate to match from year 2009 with SEQPLT09 to year 2007, to year 

2005, and to year 2004 using SEQPLT07, SEQPLT05, and SEQPLT04 respectively). 

The year 2009 data are displayed in one eGRID2012 year 2009 workbook. This workbook includes a 

Table of Contents; the boiler, generator, plant, state, power control area, eGRID subregion, NERC region, 

and U.S files; and the new year 2009 grid gross loss file. The workbook can be downloaded from the 

EPA eGRID web site, http://www.epa.gov/egrid, along with Summary Tables and this document. 

The data were originally processed on the EPA IBM mainframe using SAS, the Statistical Analysis 

System software. 

The eight eGRID2012 data aggregation files are: 

 BLR (boiler), with 5,560 year 2009 records; 

 GEN (generator), with 17,484 year 2009 records; 
4 

 PLNT (plant), with 5,492 year 2009 records with non-zero generation and/or unadjusted 

heat input; 

 ST (state), with 51 year 2009 records; 

 PCAL (power control area), with 119 year 2009 records in the file; 

 SRL (eGRID subregion), with 26 eGRID subregion year 2009 records in the file; 

 NRL (NERC region), with 10 NERC region year 2009 records in the file; and 

 US, with 1 year 2009 U.S. totals record. 

The number of variables in each of the eight aggregation files varies, with 34 in BLR, 15 in GEN, 164 in 

PLNT, 111 in ST, 111 in PCAL, 113 in SRL, 111 in NRL, and 109 in US. The first variable in each file 

is a unique sequence number for that file. The boiler file is sorted by state postal code abbreviation, plant 

name, plant code, and boiler ID. The generator file is sorted by state postal code abbreviation, plant 

name, plant code, and generator ID. The plant file is sorted by state postal code abbreviation, plant name, 

and plant code. The state file is sorted by state postal code abbreviation, the power control area file is 

sorted by power control area name, the eGRID subregion file is sorted by eGRID subregion name, and the 

NERC region file is sorted by NERC region acronym. 

The new year 2009 grid gross loss file is also included as the last tab in the eGRID workbook, 

eGRID2012V1_0_year09_DATA.xls. See Part B, What’s New in eGRID2012, for further information. 

The file structure for each of the files whose data are displayed in eGRID2012V1_0_year09_DATA.xls is 

included in Appendix A. The file structure also includes a description of the variables and the original 

data sources. The file structure indicates which variables and/or variable descriptions in year 2009 are 

new or different from those in year 2007. 

B. WHAT’S NEW IN eGRID2012 

Data file changes in eGRID2012 for year 2009 data include the following: 

 Because of budgetary issues, year 2009 data are trimmed by eliminating the updated 

operator, owners, nufront, and parent companies to a specified year 2012 date. The 

operators and owners (and plant name) displayed in the eGRID plant file for year 2009 

are as reported in the 2009 EIA-860. There are no associated operator parent companies 

in the plant file and there are no aggregation files for EGC operator-based, EGC ownerbased, parent company operator-based, or parent company owner-based data in the final 

eGRID workbook.

 The three separate eGRID Excel workbooks have been combined into one larger Excel 

workbook with ten tabs (in a ZIP file). 

 The derivation and data sources for the EIA-based state level grid gross loss have been 

replaced by the FERC- and EIA-based grid gross loss, beginning with year 2009. 

Consequently, the state import-export files have not been developed for year 2009. A 

new methodology for estimating grid gross losses has been employed using EIA utility 

sales data, FERC-714 power control area/balancing authority generation, and FERC-714 

interchange data that are summed to the grid level. 
5 

eGRID2012 includes several new data elements delineated below: 

 EPA/CAMD unit-level program codes as a replacement for the NBP flag in the boiler 

file; 

 eGRID subregion annual CO2 equivalent non-baseload output emission rate; and 

 Plant associated ISO/RTO territory. 

Some modifications have been made to eGRID plant file variables: 

 For year 2007 data, only the EIA-923 prime mover level data (collected under EIA-906 

in earlier years) were used for adjustment to the CAMD CO2 emissions. But, beginning 

with year 2009 data, the biomass fuel components’ CO2 CAMD emissions are adjusted to 

zero by the same biomass fuel component percentage as that in the matching EIA-923 

unit-level data (or if necessary, the matching EIA-923 prime mover level data). In 

addition, beginning with year 2009 data, the biogas components’ CAMD-based CH4, 

N2O, SO2, and NOx emissions are also adjusted by the same biogas fuel component 

percentage as that in the matching EIA-923 unit-level data (or if necessary, the matching 

EIA-923 prime mover level data) for the adjusted CH4, N2O, SO2, and NOx CAMD 

emissions. RMBMFLAG, the biomass flag, is assigned a value of 7100 if there is a 

biomass adjustment to CAMD CO2 emissions or a value of 71 if there are biogas 

adjustments to CAMD emissions. 

Methodological changes in eGRID2012 for year 2009 data include the following: 

 EIA-923 unit/boiler level data included. 

 A few updated GHG emission factors (EF). 

 Some updated latitude-longitude coordinates based on 2010 EIA’s data (EIA, 2011e). 

 Ozone season net generation from EPA/CAMD is derived differently from year 2007’s. 

Beginning with year 2009 data, for fuel-type output emissions rates, rather than divide 

the total adjusted emissions by the total plant net generation (as done for year 2007 data 

and earlier), if a plant is partially a combustion plant (i.e., it includes both combustion 

and non-combustion generators), then the total plant emissions are instead divided by the 

combustion net generation for that plant. 

Methodological changes are detailed in Section III, the Methodology Section. Year 2004, 2005, and 2007 

data included in eGRID2012 are unchanged from the data in previous eGRID editions, except that in the 

plant file for year 2007, the longitude field is corrected for those plants whose longitude is -99.xx (they 

had inadvertently been replaced by ‘N/A’ in the previous edition). For more information about the year 

2007 data, see the eGRID2010 Technical Support Document (TS|Pechan, 2010). For methodology from 

previous years, see their Technical Support Documents (TS|Pechan, 2008, 2007, 2003a). 

C. USES AND USERS OF eGRID 

eGRID data support a wide variety of users globally through a wide variety of uses. eGRID is valuable to 

those in the Federal Government, state and local governments, non-governmental organizations, 
6 

academia, and provides constructive direction to companies who are generally seeking environmental 

information from the electric power sector in the United States. eGRID is most often used for the 

estimation of indirect emissions from electricity purchases, in GHG inventories, for carbon footprinting, 

and for estimating avoided emissions from programs and projects that would reduce the consumption for 

grid supplied electricity. eGRID data are cited by emission inventory and registry protocols, by various 

emission calculation tools and applications, by many academic papers, by many consultants, and is used 

for many research applications and efforts. 

Within EPA, eGRID data are used in the following applications and programs: Power Profiler web 

application, Climate Leaders protocols, ENERGYSTAR’s Portfolio Manager and Target Finder, Waste 

Wise Office Carbon Footprint Tool, the Personal Greenhouse Gas Emissions Calculator, the Greenhouse 

Gas Equivalencies Calculator, and the Green Power Equivalency Calculator. 

When the EPA announced its “Apps for the Environment” challenge using EPA data, developers across 

the U.S. responded. EPA announced the winners on November 8, 2011 and the two top winning apps -- 

Light Bulb Finder (http://www.lightbulbfinder.net/) and Hootroot (http://hootroot.com/) use eGRID data 

for a mobile app and/or a web app, as did several other entries (EPA, 2011b). Another of the winning 

entries, Joulebug (http://joulebug.com/) uses eGRID data and developed a game to save energy as both a 

web and free iPhone app. 

In 2010, Executive Order 13514 was issued, requiring Federal agencies to “measure, report, and reduce 

their greenhouse gas emissions from direct and indirect activities.” The Federal GHG Accounting and 

Reporting Guidance accompanied this order and recommended using eGRID non-baseload emission rates 

to estimate the scope 2 emission reductions from renewable energy. 

One of the most popular uses of eGRID is to determine the indirect GHG emissions from electricity 

purchases and avoided GHG emissions from projects and programs that reduce the demand for grid 

supplied electricity. For example, The Climate Registry, the California Climate Action Registry, 

California’s Mandatory GHG emissions reporting program (AB 32) (CARB, 2007), and the Greenhouse 

Gas Protocol Initiative cite eGRID for use in estimating scope 2 (indirect) GHG emissions from 

electricity purchases in the United States. Most carbon footprint calculators that are applicable to the 

United States use eGRID data. 

The website, www.fueleconomy,gov, resulting from an EPA-U.S. Department of Energy (DOE) 

partnership, provides fuel economy information that consumers can use to make knowledgeable decisions 

when buying a car. The information can also help consumers achieve the best fuel economy from 

currently owned cars. This website showcases its Greenhouse Gas Emissions for Electric and Plug-in 

Hybrid Electric Vehicles calculator, http://www.fueleconomy.gov/feg/label/calculator.jsp, which uses 

eGRID data to estimate the total GHG emissions from electric and plug-in hybrid vehicles, including 

emissions from electricity used to charge the vehicle. eGRID is cited as a data source at 

http://www.fueleconomy.gov/feg/label/calculations-information.shtml . In a similar vein, the Union of 

Concerned Scientists (UCS, 2012) published a 2012 report using eGRID data to support its study results 

that it is advantageous to switch to a battery-powered vehicle, although there are wide differences in both 

real electricity costs and GHG emissions, depending on the region in which you live. 

eGRID data are also used for Galvin Electricity Initiative’s “Perfect Power Seal of Approval” 

(http://www.galvinpower.org/sealofapproval) tool whose metrics help consumers to evaluate the 

performance of the electricity grid (Galvin, 2011). EIA’s National Energy Modeling System (NEMS)’s 

electricity market module supply regions are the eGRID subregions; the map used in their 2011 

documentation (Figure 3) uses the eGRID subregion map and subregion colors, changing a few names 

(EIA, 2011d). 
7 

eGRID is also used by other Federal Government agencies such as Oak Ridge National Laboratory 

(ORNL) for their Combined Heat and Power Calculator, the National Energy Technology Laboratory 

(NETL) for their sponsored Distributed National Carbon Sequestration Database and Geographic 

Information System (NATCARB), and the National Renewable Energy Laboratory (NREL) for their 

micropower distributed generation optimization model named HOMER. 

States and local governments rely on eGRID data for electricity labeling (environmental disclosure 

programs), emissions inventories, and registries as well as for efforts to analyze air emissions from the 

electric power sector. Several states have published state specific emissions information from eGRID or 

have used eGRID to inform policy decisions. The Maryland Department of the Environment (MDE) 

determined eligibility for participation in the Voluntary Renewable Set-Aside Account (VERSA) using 

eGRID factors (Maryland, 2010); and in 2009, the Delaware Valley Regional Planning Commission 

(DVRPC) -- a nine county region in Pennsylvania and New Jersey -- completed a 2005 GHG Inventory in 

support of regional efforts to quantify and reduce emissions associated with climate change, using eGRID 

factors (DVRPC, 2010). 

Tracking Systems for Renewable Energy Credits (RECS), such as ISO-New England’s Generation 

Information System (GIS) and PJM’s Generation Attribute Tracking System (GATS) utilize eGRID data. 

ISO New England uses eGRID rates in developing the 2008 New England Electric Generator Air 

Emissions Report (http://www.iso-ne.com/genrtion_resrcs/reports/emission/2008_emissions_report.pdf). 

eGRID is additionally used for nongovernmental organizations’ (NGOs) tools and analysis. The 

following is a list of some known users and applications of eGRID data: Northeast States for Coordinated 

Air Use Management (NESCAUM) analysis, Powerscorecard.org, the Ozone Transport Commission’s 

(OTC) Emission Workbook, the Greenhouse Gas (GHG) Protocol Initiative, the Rocky Mountain 

Institute’s Community Energy Finder, Leonardo Academy’s “Cleaner and Greener Environmental 

Program,” the National Resource Defense Council’s Benchmarking Air Emissions, The Berkeley Institute 

of the Environment, Cool Climate Carbon Footprint Calculator, the Climate and Air Pollution Planning 

Assistant (CAPPA), Emission Solution’s Carbon Footprint Calculator, and the Clean Air software 

developed by the International Council for Local Environmental Initiatives (ICLEI), The United States 

Department of Transportation Federal Transit Administration (FTA), The Google PowerMeter, a free 

energy monitoring to calculate your home’s energy consumption online, The National Public Radio – 

U.S. Electric Grid, The International Code Council (ICC), the American Society of Heating, Refrigerating 

and Air-Conditioning Engineers (ASHRAE), The Local Energy Efficiency Policy Calculator (LEEP - C) 

released by the American Council for an Energy-Efficient Economy (ACEEE), and the World Resource 

Institute’s Carbon Value Analysis Tool (CVAT). 

Additionally, Brighter Planet, with its CM1 web service, has developed a model to estimated GHG 

emissions from electricity use that uses both the eGRID subregion GHG emission factors (EF) as well as 

the grid gross loss data for their estimates (Brighter Planet, 2010). 

The Center for Global Developments’ Carbon Monitoring for Action Database (CARMA) at carma.org, 

which contains information about carbon emissions for power plant and companies in the U.S. as well as 

other countries, used eGRID year 2005 data as a base, according to the Center’s David Wheeler (Wheeler, 

2007). eGRID data also underlie the Global Energy Observatory U.S. power plant database. 
8 

D. eGRID SOURCES 

eGRID is developed from a variety of data collected by the U.S. Environmental Protection Agency 

(EPA), and the Energy Information Administration (EIA). Federal data sources include: 

 EPA, Clean Air Markets (EPA/CAMD) Annual and Ozone Season Emissions data 

collected under 40 CFR Part 75 (EPA, 2011a); 

 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010 (EPA, 2012b); 

 EIA, EIA-860: Annual Electric Generator Report (EIA, 2011a); 

 EIA, EIA-861: Annual Electric Power Industry Report (EIA, 2011b); 

 EIA, EIA-923: Power Plant Operations Report (EIA, 2011c); 

 FERC, FERC-714: Annual Electric Balancing Authority Area and Planning Area Report 

(FERC, 2011); and 

 An additional source of eGRID data, the North American Electric Reliability Corporation 

(NERC) [formerly the North American Electric Reliability Council] (NERC, 2012a and 

2012b), is quasi-governmental since it was certified by FERC in July 2006 as the 

“electric reliability organization.” 

Data displayed in eGRID are derived from the above data sources; EPA does not collect data directly 

from electric generators for eGRID. Inconsistencies between data sources, missing data, and ambiguous 

data occasionally necessitate adjustments to values of individual data elements. When necessary, EPA 

substitutes data from secondary sources or default values. EPA also updates grid configuration data. In 

general, however, data are displayed as reported; this may lead to plant file outliers to which users should 

be alert. 
9 

SECTION III. eGRID METHODOLOGY 

This section describes eGRID development methodologies that are not transparent. Some methods used 

for eGRID2012 are modified or refined from previous editions of eGRID and are so noted in this section. 

A. ESTIMATION OF EMISSIONS 

Emissions (CO2, NOx, SO2, Hg, CH4, and N2O) in eGRID are estimated using data from a variety of 

sources from EPA and EIA (see SOURCEM variable in the eGRID plant file). Carbon dioxide (CO2) is a 

product of fossil fuel combustion and is the primary greenhouse gas (GHG) emitted by human activities 

that is contributing to global climate change; nitrogen oxides (NOx) is a product of fossil fuel combustion 

and is a precursor to the formation of ozone, or smog, and also contributes to acid rain and other 

environmental and human health impacts; sulfur dioxide (SO2) is an air pollutant emitted primarily by 

power plants burning fossil fuels, especially coal, which is a precursor to acid rain and is associated with 

other environmental and human health impacts; and mercury (Hg) is a toxic heavy metal that is a 

byproduct of the combustion of fossil fuels, especially coal. Methane (CH4) and nitrous oxide (N2O), two 

other GHG emitted by electric power generators, are included in eGRID for years 2009, 2007, and 2005, 

beginning at the plant level. The emissions data for the three GHG are used as default factors in a variety 

of climate protocols (including The Climate Registry, The California Climate Action Registry, 

California’s Mandatory GHG emissions reporting program (AB 32), and EPA’s Climate Leaders) for 

indirect emissions estimation calculations. 

Although many small units, as well as some nonutilities and cogenerators, are not subject to 

EPA/CAMD’s data reporting, the vast majority of emissions reported in eGRID are from the EPA/CAMD 

data. Sources that report to EPA/CAMD for year 2009 data are generally utility and nonutility steam 

units with at least 25 MW capacity, nonsteam units – gas turbines, combined cycles, internal combustion 

engines – that came on-line after 1990, and independent power producers/cogenerators that sell a specific 

amount of electricity. 

Plant level emissions in eGRID are built by summing its component parts – which could simply be unit 

level boilers and/or turbines or a combination of boilers and prime movers representing an aggregation of 

like generating units. In general, eGRID plant level emissions reflect a combination of monitored and 

estimated data. Emissions and emission rates in eGRID represent emissions and rates at the point(s) of 

generation. They do account for losses within the generating plants (net generation). However, they do 

not take into account any power purchases, imports or exports of electricity into a specific state or any 

other grouping of plants; and they do not account for any transmission and distribution losses between the 

points of generation and the points of consumption. Also, eGRID does not account for any precombustion emissions associated with the extraction, processing and transportation of fuels and other 

materials used at the plants or any emissions associated with the construction of the plants. 

eGRID emissions and heat input that are displayed in the boiler file are unadjusted, while both adjusted 

and unadjusted emissions and heat input are displayed in the plant file. Adjusted emissions and heat input 

as well as generation are used in calculating plant emission rates and for all aggregation emission values. 

1. Unadjusted Emission Estimates for Year 2009 

Emissions that are reported and estimated for eGRID are initially unadjusted, including biomass GHG 

values, and are displayed at the plant (and boiler) level. Adjusted emissions (and heat input) are included 

in the plant file and all subsequent aggregation files. All emission rates in the plant file and all 

aggregation files are based on adjusted emissions, net generation, and adjusted heat input. Depending on 
10 

the source of data and the emissions type, component emissions are adjusted for biomass and then 

summed to the plant level before making the CHP adjustment specific to eGRID. Both the source(s) of 

emissions data and adjustment flags are provided in the plant file. 

2. Annual Emission Estimates for CO2, SO2, and NOx

Mass emissions in eGRID are estimated using data from a variety of sources. eGRID’s primary source 

for CO2, SO2, and NOx, data is EPA/CAMD’s unit level emissions data. CO2 is a greenhouse gas, while 

SO2 and NOx are not. SO2 and NOx are acid rain pollutants and have been regulated under the Clean Air 

Act Amendments for many years. If EPA/CAMD emissions are not reported, the emissions are generally 

estimated using fuel consumption – on a boiler-fuel level if the data are in the EIA-923 boiler level, 

and/or on a prime mover-fuel level if the data are only in the EIA-923 prime mover level file. 

For estimating CO2, the Intergovernmental Panel on Climate Change (IPCC) (IPCC, 2007) greenhouse 

gas (GHG) methodology using fuel consumption, a fuel-specific carbon coefficient, and the fuel-related 

fraction of carbon oxidized (beginning with year 2005 data, the IPCC’s mandated change to a uniform 

oxidation fraction of 1 is used for all fossil fuels) is implemented. This method is also used in EPA’s 

Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010 (EPA, 2012b, Annex 2 tables). CO2 

emission factors (EF), which are actually carbon coefficients, for year 2009 are obtained from two 

sources: EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2010 (EPA, 2012b, Annex 

2 tables), The Climate Registry’s January 6, 2012 EF file (TCR, 2012), both of which use the EF from 

Table C-1 from EPA’s Final Mandatory Reporting of Greenhouse Gases Rule (EPA, 2009) as the basis 

for their EF. If CO2 emissions are estimated, whether for EPA/CAMD, EIA-923 boiler, or EIA-923 

prime mover data, the emission factor is applied to fuel consumption (usually in MMBtu). 

For SO2, EPA-approved uncontrolled EF based on EPA’s AP-42 EF (EPA, 2012a), sulfur content, and 

control efficiencies (if available), and fuel use are also used in the estimation of these emissions. 

 

The following describes how NOx emissions are estimated for cases in which EPA/CAMD emissions data 

are not reported or cannot be used. For steam boilers originating from the EIA-923, the controlled annual 

NOx emission rate and heat input are used. For data originating from the EIA-923 prime mover level, for 

steam prime movers, fuel use and EPA-approved uncontrolled emissions factors (EPA, 2012a) are used; 

and for EIA-923 nonsteam prime movers, beginning with year 2004 eGRID data, a better method is used 

to calculate NOx emissions for combined cycles, turbines, and internal combustion engines. NOx EF were 

developed based on the prime mover technology, size, and location. The location is important due to the 

differing stringency of air pollution controls in some areas with severe air quality problems. For larger 

nonsteam generators, the factors were based on data from the EPA Reasonably Available Control 

Technology/Best Available Control Technology/Lowest Achievable Emission Rate RACT/BACT/LAER) 

Clearinghouse (EPA, undated2). The methodology also reviewed current RACT requirements for large 

generating facilities in regions with stringent limits in areas such as the Ozone Transport Region (OTR), 

California, and Texas. For smaller nonsteam generators (including small combustion turbines, 

microturbines and reciprocating engines), the methodology draws from several sources including the EPA 

CHP Partnership Catalogue of CHP (EPA, undated1) and the U.S. Department of Energy (DOE) GasFired Distributed Energy Resource Technology Characterizations (DOE, 2003). 

Geothermal emissions, albeit minimal, are estimated for CO2, SO2, and NOx. While CO2 is a gas in the 

geothermal reservoir, SO2 and NOx result from hydrogen sulfide combustion. The three pollutants’ EF, 

obtained from a 2007 Geothermal Energy Association environmental guide (GEA, 2007), are applied to 

plant net generation, and differ depending on the type of geothermal plant (GEA, 2010, plus updates 

based on internet research). For a binary or flash/binary geothermal plant, there are no CO2, SO2, or NOx

EF; for a flash geothermal plant, there are no NOx EF and small CO2 and SO2 EF; and for a dry steam 
11 

geothermal plant, there are small CO2, SO2, and NOx EF. If a plant has operating (i.e., reported non-zero 

net generation) generators with different geothermal types, then the methodology is modified. In this 

case, appropriate geothermal type EF must be applied to the prime mover net generation for each of the 

different geothermal types of the plant generators. 

3. Annual Emission Estimates for CH4 and N2O 

In addition to CO2, electric power plants also emit some CH4, and N2O GHG emissions. CH4 and N2O 

emissions are reported in pounds and are estimated by multiplying the fuel specific heat input in MMBtu 

by appropriate EF from Table C-2 of EPA’s Final Mandatory Reporting of Greenhouse Gases Rule (EPA, 

2009). 

Nitrous oxide (N2O) is an oxide of nitrogen that is not part of the NOx subset of oxides of nitrogen. N2O 

is a greenhouse gas, the emissions of which are contributing toward global climate change; NOx is not a 

GHG. N2O should not be confused with NOX. 

a. Global Warming Potential 

Global Warming Potential (GWP) is a value assigned to a GHG so that the emissions of different gases 

can be assessed on an equivalent basis to the emissions of the reference gas, CO2, which has a GWP of 1. 

Traditionally, the 100-year GWPs are used when calculating overall CO2 equivalent emissions, which is 

the sum of the products of each GHG emission value and its GWP. Note: be sure when calculating the 

CO2 equivalent that each of the GHG emission values has the same measurement units (either all in tons 

or all in pounds) since in eGRID, CO2 are expressed in tons while both CH4 and N2O are expressed in 

pounds. Additionally, in order to compare emissions across previous data years’, the GWP for the second 

(1996) IPCC assessment (SAR), is used, although there have been subsequent third (2001) (TAR) and 

fourth (2006) (AR4) assessments. A comparison of the three GWP for the three electric power GHG 

gases is presented in Table III-1 (EPA, 2012b, Table 1-3). 

Table III-1. Comparison of 100-Year GWPs 

Gas SAR TAR AR4 

CO2 111

CH4 21 23 25

N2O 310 296 298

Beginning with year 2007 data, the CO2 equivalent emissions (tons) and total output emission rate (in 

lb/MWh) is calculated (using the SAR GWP) at the plant and aggregation levels; and beginning with year 

2009 data, the CO2 equivalent s non-baseload output emission rate (in lb/MWh) is also calculated, but at 

the eGRID subregion level. 

4. Annual Emission Estimates for Mercury (Hg) 

No mercury emissions are included for year 2009 data since the previously employed estimation methods 

are likely to produce an overestimate of the emissions for boilers for which we have original 1999/2002 

data. It is likely that air pollution control devices that affect Hg emissions have been installed on some of 

these boilers, but there are no Federal data available to measure their impact. Similarly, there are no 

currently available Federal Hg EFs for estimating mercury emissions for all electric power units. Because 

of current legal challenges relating to the regulation of Hg emissions from the electric power sector, EPA 

is not issuing any Hg data in eGRID in this edition. EPA may develop a new methodology for the 

estimation of Hg emissions in a future edition of eGRID. 
12 

5. Ozone Season Emission Estimates for NOx

The ozone season is the five-month period from May through September when excessive levels of ozone, 

or smog, are most likely to form in the atmosphere due to a chemical reaction of nitrogen oxides with 

other pollutants in the presence of sunlight. EPA/CAMD provides ozone season NOx emissions for many 

units that do not report annual emissions. Otherwise, for steam boilers and sampled plants with prime 

movers that report to the EIA-923 and are not covered by EPA/CAMD, monthly fuel quantity is provided 

so that five-month (May through September) ozone season NOx emissions can be estimated; if the plant 

prime mover reports only annually to the EIA-923, then ozone season estimates are calculated as the 

annual estimates multiplied by 5/12. 

6. Adjusted Emission Estimates 

Emissions reported in eGRID represent emissions from fuel utilized only for electricity generation. Thus, 

for certain plants, there are two possible cases for which eGRID adjusts the emission estimates: if the 

plant is a CHP facility; and if components of the plant burn biomass, including biogas (such as landfill, 

methane, and digester [other biomass] gas). A biomass facility’s adjusted emissions displayed in eGRID 

may be different from that reported in other EPA sources such as EPA/CAMD’s emissions data. 

There are two EPA Acid Rain Program (ARP) plants whose plant-prime mover EPA/CAMD emissions 

and heat input are adjusted to zero in eGRID; the unadjusted values are published for reference purposes. 

The net generation for two of these plant-prime movers is reported as zero even though positive fuel use 

is reported to the EIA-923. For 74th Street (ORISPL = 2504), the steam turbine prime mover data (the 

three unit level EPA reported emissions and heat input) are adjusted to zero, but the gas turbine adjusted 

emissions and heat input remain positive. A second plant, AES Redondo Beach LLC (ORISPL = 356), 

has five steam units that report positive emissions to EPA, but research revealed that one unit does not put 

electricity to the grid; this unit was assigned zero adjusted emissions and heat input. 

 

7. Adjustments for Biomass 

eGRID makes adjustments for biogas emissions, for biomass emissions other than biogas, and for solid 

waste emissions for specified pollutants. Solid waste typically consists of a mixture of biogenic materials 

– biomass such as wood, paper, and food waste – and “other fossil” materials – fossil-based materials 

such as plastics and tires. Thus, emissions from the biomass component of solid waste are adjusted 

exactly as non-biogas biomass emissions are adjusted, while emissions from the fossil component of solid 

waste are not adjusted. 

Solid waste is split into the two components in eGRID so that adjustments can be made as needed. EPA’s 

methodology for splitting MSW into the two components includes different splits for the MSW types. 

The MSW percentages for the MSW biomass component (called MSB) and the MSW fossil component 

(called MSF) are described in Table III-2 below (EIA, 2007). The type of MSW is obtained from an EPA 

data file (EPA, 2002). 
13 

Table III-2. Municipal Solid Waste MSB and MSF Splits 

MSW Type Variable(s) MSB Split (%) MSF Split (%) 

Mass Burn Heat Input, Generation 52.7% 47.3% 

Mass Burn Fuel Consumption 65.4% 34.6% 

Refuse Derived Fuel Heat Input, Generation 52.7% 47.3% 

Refuse Derived Fuel Fuel Consumption 75.1% 24.9% 

Unknown Heat Input, Generation 52.7% 47.3% 

Unknown Fuel Consumption 67.7% 32.3% 

As with all biomass generation, CO2 emissions from the biomass portion of solid waste are adjusted, but 

emissions from the remaining portion of solid waste are reported based on appropriate EF. The EF used 

don’t take in consideration any control devices that may be present because there is no readily available 

nationwide information. Generation from supplemental fossil fuels co-fired with solid waste is identified 

if known and reflected in emission rates. This methodology has not changed. However, beginning with 

the year 2007 data, the biomass portion of solid waste combustion is shown in the unadjusted CO2 

emissions. 

A flag in the plant file indicates whether there is any biomass adjustment and the type of adjustment. The 

possible adjustments for CO2, NOx, SO2, CH4, and N2O emissions (and heat input) are explained below. 

 

a. CO2

Biomass is a fuel derived from organic matter such as wood and paper products, agricultural waste, or 

methane (e.g., from landfills). eGRID assumes that these materials are subject to the natural carbon cycle 

and, therefore, do not contribute to global warming. eGRID assigns zero CO2 emissions to generation 

from the combustion of all biomass (including biogas) because these organic materials would otherwise 

release CO2 (or other greenhouse gases) to the atmosphere through decomposition. 

For those adjusted-for-biomass CO2 emissions that are estimated, the biomass components are zeroed out 

in this edition, just as they have been for previous years of eGRID data. However, in this edition of 

eGRID, the CO2 emissions from biomass are more comprehensively disclosed in the plant unadjusted 

emissions. The CO2 emissions from biomass can be determined at a plant level by comparing the 

emissions and the unadjusted emissions at plants that have a biomass adjustment flag. If the CHP 

adjustment flag is also 1, to determine the biomass emissions, first calculate how much of the adjustment 

is accounted for from CHP using the electric allocation factor (since the CHP plant adjustment is applied 

last). 

For the EPA/CAMD units that for a given prime mover whose matching EIA-923 prime mover burns 

some biomass fuel, the biomass fuel components’ CO2 CAMD emissions are adjusted by the same 

biomass fuel component percentage as reported in the EIA-923; prior to year 2007, these emissions, if 

CAMD-reported, were only zeroed out if the EPA/CAMD primary fuel was a biomass fuel. Beginning 

with year 2009 data, the biomass fuel components’ CO2 CAMD emissions are adjusted to zero by the 

same biomass fuel component percentage as that in the matching EIA-923 unit-level data (or if necessary, 

the matching EIA-923 prime mover level data). RMBMFLAG, the biomass flag, is assigned a value of 

7100 if there is a biomass adjustment to CAMD CO2 emissions. Similarly, the biogas fuel components’ 

CO2, CH4, N2O, SO2, and NOx emissions are adjusted by the same biogas fuel component percentage as 

that in the matching EIA-923 unit-level data (or if necessary, the matching EIA-923 prime mover level 

data). RMBMFLAG, the biomass flag, is assigned a value of 71 if there are biogas adjustments for 

CAMD emissions. 
14 

b. NOx, SO2, CH4, and N2O 

NOx, SO2, CH4, and N2O emissions from generation powered by biogas (landfill gas and digester gas) are 

also adjusted in eGRID. Landfill gas and digester gas emissions must be flared in most cases if the gas is 

not consumed as useful energy. Therefore, eGRID assumes that biogas would have been flared if not 

used to generate electricity, so that eGRID adjusted emissions are the amount of incremental emissions 

attributable to utilizing biogas to generate electricity. Thus, emissions from these fuels are adjusted by 

decreasing the uncontrolled EF (used to estimate the emissions) by the emission factor represented by a 

typical flare. This methodology has not changed. 

For NOx, the EPA-approved flare emission factor is assumed to be 40 lb per million cubic feet (MMcf) of 

methane, 20 lb per MMcf of methane for landfill gas, and 26 lb per MMcf of methane for digester gas, 

and is subtracted from the respective original EPA-approved uncontrolled EF before being applied. For 

SO2, CH4, and N2O, the EF are assumed to be the same as the flares’, so there are no incremental SO2, 

CH4, and N2O emissions attributable to utilizing biogas to generate electricity, and values of zero are 

assigned. 

In eGRID, there are no fuel adjustments for NOx, SO2, CH4, and N2O emissions for biomass other than 

biogas. Beginning with year 2009 data, the biogas components’ CAMD CH4, N2O, SO2, and NOx

emissions are also adjusted by the same biogas fuel component percentage as that in the matching EIA923 unit-level data (or if necessary, the matching EIA-923 prime mover level data) for the adjusted CH4, 

N2O, SO2, and NOx CAMD emissions. RMBMFLAG, the biomass flag, is assigned a value of 71 if there 

is a biogas adjustment to CAMD emissions. 

8. Adjustments for CHP 

CHP is a type of generating facility that produces electricity and another form of useful thermal energy 

(such as heat or steam) used for industrial, commercial, heating, or cooling purposes. CHP, also known 

as cogeneration, converts energy more efficiently than facilities that separately produce heat and 

electricity. The plants labeled as CHP in eGRID are an EPA designation based on a CHP file developed 

for DOE (EEA, 2011 updated). A flag in the plant file indicates if a plant is considered a CHP for 

purposes of eGRID. Since emissions reported in eGRID represent electricity generation only, emissions 

associated with useful thermal output – the amount of heat produced in a CHP facility that is used for 

purposes other than making electricity – are excluded from the adjusted emissions (and a plant’s 

emissions data reported in eGRID may be different from that reported in other EPA sources). As in 

eGRID2010, the unadjusted emissions are shown only in the plant file. 

eGRID’s methodology is designed to share CHP’s efficiency gains between electricity and useful thermal 

output. For CHP facilities in the year 2009 data, eGRID allocates emissions between electricity and 

thermal output using a plant level electric allocation factor that discounts the value of useful thermal 

output by 25%. If a plant is a CHP and has an electric allocation factor, it is applied to the emissions 

(and heat input) for the entire plant after any biomass adjustment has been made. Specifically, the 

adjusted value is the product of the electric allocation factor and the original value. 

The methodology for estimating an electric allocation factor is as follows: 

The useful thermal output value for year 2009 data can be calculated from EIA-923 data as 0.8 multiplied 

by (total heat input minus electricity heat input) MMBtu. The electric allocation factor is calculated as 

the ratio of the electricity heat output to the sum of the electricity and steam heat outputs, where 
15 

electricity heat output in MMBtu is the net generation MWh multiplied by 3.413 and steam heat output 

MMBtu is 0.75 multiplied by useful thermal output 

If the useful thermal output is unknown, the electric allocation factor (ELCALLOC) is estimated given 

specific conditions. But, if there are non-zero values for both annual net generation and annual total heat 

input, an 8,500 Btu per kilowatt-hour (kWh) median plant nominal heat rate is assumed. Since actual heat 

rate equals (electric allocation factor multiplied by 1000 multiplied by heat input MMBtu) divided by (net 

generation MWh), then the electric allocation factor for CHP plants without a given useful thermal output 

is initially calculated as: 

 ELCALLOC = (8.5 * plant net generation MWh) / (unadjusted plant heat input MMBtu). 

If, however, the plant’s CHP prime mover has been designated steam and the heat rate is less than 22,747 

Btu/kWh, then the electric allocation factor for the CHP plant is initially calculated as: 

 ELCALLOC = ((12.68 * plant net generation) / (unadjusted plant heat input)) - 0.17444. 

For calculated electric allocation factors that fall below a specified minimum, additional adjustments are 

made as summarized in Table III-3 below. 

Table III-3. Floors for Power to Heat Ratio and ELCALLOC 

Type of CHP Prime Mover Minimum ELCALLOC Minimum Power to Heat Ratio

Coal or MWC Boilers 0.11765 0.10 

All Other Boilers 0.06250 0.05 

Gas Turbines 0.30556 0.33 

Combined Cycles, IGCC 0.47183 0.67 

Internal Combustion Engines 0.40000 0.50 

The CHP electric allocation “floors” were derived from an analysis of the theoretical power-to-heat ratio 

of different CHP technologies and the actual operating characteristics of existing CHP systems. The 

power-to-heat ratio is largely a function of the CHP prime mover, its efficiency, and the amount and 

temperature of heat available from the system. In addition, the reported operating characteristics of a 

large number of CHP facilities as reported in the DOE ORNL CHP database (EEA, 2011) were reviewed. 

The combination of theoretical and reported characteristics was used to establish the minimum values for 

the electric allocation factors. 

This methodology has not changed. 

9. Emission Rate Estimates 

Both output and input emission rates are calculated for eGRID, beginning with the plant level of 

aggregation. In addition to emission values, annual and ozone season net generation and heat input values 

(adjusted heat input values if it is a CHP) are required for emission rate calculations. 

a. Generation 

Net generation, in MWh, is the amount of electricity produced by the generator and transmitted to the 

electric grid; it does not include any generation consumed by the plant. If the generation consumed by the 

plant is greater than the gross generation, negative net generation will occur and be displayed in eGRID; 

this can further result in negative emission rates. 
16 

Plant-fuel-prime mover net generation for all prime mover types can be obtained from the EIA-923; 

(most) steam and nuclear generator unit level net generation can also be obtained from the EIA-923. 

For sampled plants with EIA-923 net generation, generation is reported monthly and annually so that 

ozone season generation is calculated by summing up the generation for the five months of May through 

September. If there are no monthly data, ozone season generation is calculated as 5/12 of the annual 

generation. Net generation for those plant-prime movers (or entire plants) that did not report data to the 

EIA-923, but did report emissions to the EPA, is derived from EPA/CAMD data if there also is positive 

gross load generation in the EPA/CAMD data file. 

The following methodology was employed for obtaining year 2009 net generation data: 

Plant level net generation

To determine plant level net generation, use EIA-923 plant-prime mover annual and ozone season MWh 

net generation, if available. Ozone season net generation for those plants/generators that report monthly 

to the EIA-923 is calculated by summing the May through September net generation; for plants/units that 

report only annually to the EIA-923, the ozone season net generation is calculated as 5/12 of annual net 

generation. 

If plant-prime mover net generation is also needed because there is EPA/CAMD non-zero reported 

emissions without associated EIA-923 net generation, then CAMD’s reported annual gross load 

multiplied by a prime mover-level conversion factor found in Velocity Suite’s data (Ventyx, 2007) for the 

specific unit(s) is used to estimate annual net generation MWh, aggregated to the plant level by prime 

mover. Similarly, for estimating EPA/CAMD ozone season net generation, CAMD’s reported ozone 

season gross load multiplied by a prime mover-level conversion factor found in Velocity Suite’s data 

(Ventyx, 2007) for the specific unit(s) is used to estimate ozone season net generation MWh, aggregated 

to the plant level by prime mover. Otherwise, if net generation for that prime mover is zero, then the 

associated adjusted emissions is assigned a value of zero. 

Generation can be appropriately attributed to fuel type with the EIA-923 data. With the selected CAMD 

net generation, the fuel code of the plant primary fuel is assigned (see subsections C and D for further 

information about resource mix). 

Combustion net generation is also developed (as is non-combustion generation), based on the fuel type 

generation of each plant. For plants that are only composed of combustion generating units, the plant 

combustion net generation is the same as the total plant net generation. For plants that have both 

combustion and non-combustion generating units, the combustion net generation will be less than the 

total net generation for that plant. 

Generator level net generation

To determine generator level net generation for some units, use EIA-923 annual and ozone season net 

generation MWh for plants with one prime mover at a non-nuclear plant operating in year 2009. 

Additionally, for steam and nuclear generators, use EIA-923 nuclear unit-level reported annual and ozone 

season net generation. Most non-steam generators will not have a year 2009 value for net generation. 

b. Heat Input 

Heat input, in MMBtu, is the amount of heat energy consumed by a generating unit that combusts fuel. 

Annual boiler level heat input for eGRID is initially obtained from EPA/CAMD 12 month reported 
17 

emissions data. Ozone season heat input is also provided with these data. EPA heat input is based either 

on stack flow and CO2/O2 monitoring, or fuel flow and heat content of fuel. 

If these EPA data are unavailable, heat input is obtained from the EIA-923 prime mover level data; its 

value was calculated internally by EIA by multiplying the reported EIA fuel consumption by the reported 

heat content (the higher heating value [HHV]). If available monthly data, the EIA ozone season heat 

input is calculated by summing up the data for the five months of May through September; otherwise, the 

ozone season heat input is calculated as 5/12 of the annual heat input. 

If a plant reports heat input or data to calculate heat input for the same prime mover to EIA-923 and/or 

EPA/CAMD, the EPA/CAMD data are used first. If the sources are different for different components of 

the plant, then the heat input data are summed for the plant. 

c. Rates 

The units for output emission rates are lb/MWh for SO2, NOx, and CO2, and lb/GWh for Hg, CH4, and 

N2O. These rates are calculated as the emissions divided by the net generation and multiplied by a unit 

conversion factor. Beginning with year 2009 data, for fuel-based output emissions rates, rather than 

divide the total adjusted emissions by the total plant net generation (as done for year 2007 data and 

earlier), if a plant is partially a combustion plant (i.e., it includes both combustion and non-combustion 

generators), then the total plant emissions are instead divided by the combustion net generation for that 

plant. 

For input emission rates, the units are lb/MMBtu for SO2, NOx, and CO2, and lb/BBtu for Hg; these rates 

are calculated as the emissions divided by the heat input and multiplied by a unit conversion factor. 

eGRID output emission rates do not account for any line losses between the points of consumption and 

the points of generation. For example, because there are line losses, one kilowatt hour of electricity 

consumption requires a little more than one kilowatt hour of electricity generation. To account for 

transmission and distribution line losses when applying eGRID output emission rates to electricity 

consumption within a certain region, divide the consumption by (one minus the grid gross loss as a 

decimal). If reporting GHG emissions to The Climate Registry (TCR), the emissions without the line 

losses belong in scope 2, while just the emissions from line losses (the difference between the emissions 

including line losses and the emissions not including line losses) belong in scope 3. eGRID publishes 

grid gross loss factors, which can be used to account for line losses, in the eGRID Summary Tables. 

Beginning with year 2009 data, grid gross loss is derived from FERC-714 power control area/balancing 

authority interchange data (as well as FERC generation, EIA consumption, U.S. regional interchange, and 

FERC foreign [Canadian and Mexican] net imports) that are summed to the defined region. The 

eGRID2012 year 2009 estimated grid gross loss for each U.S. interconnect power grid (EIA, 2000) (see 

Table III-8 for eGRID subregion – U.S. interconnect power grid relationships) are included in the 

eGRID2012 year 2009 workbook and are also displayed in Table III-4. 
18 

Table III-4. eGRID2012 Year 2009 Grid Gross Loss (%) 

Power Grid Grid Gross Loss (%) 

Eastern 5.82 

Western 8.21 

ERCOT 7.99 

Alaska 5.84 

Hawaii 7.81 

U.S. 6.50 

i. Fuel-based Emission Rates 

Beginning at the state level, coal, oil, gas, and fossil fuel output and input emission rates are calculated 

based on plants’ fossil fuel category, which in turn is based on the plants’ primary fuel (see subsection C). 

If a plant’s primary fuel is in the coal, oil, gas, or other fossil category, then all of its adjusted emissions 

and heat input, and combustion net generation are included in the respective aggregation level for that 

fuel category. For example, all plants whose primary fuel is in the coal category and who are located in 

Alabama will have their emissions, heat input, and combustion net generation summed and then the 

appropriate calculations will be applied to determine the fuel-based output and input emission rates for 

Alabama. See Table III-5 for a list of primary fuels and fuel categories. 

The methodology used to determine fuel-based output emissions rates has changed (see Section II B, 

What’s New in eGRID2012). 

ii. Non-baseload Emission Rates 

Beginning at the state level, there are seven annual non-baseload emission rates which are the annual 

output emission rates for plants that combust fuel and have capacity factors less than 0.8, weighted by 

generation and a percent of generation determined by capacity factor. These data values are derived from 

plant level data and supplement, rather than replace, the fossil fuel output emission rates, which are 

sometimes used as a rough estimate to determine how much emissions could be avoided if energy 

efficiency and/or renewable energy displaces fossil fuel generation. These non-baseload output emission 

rates would somewhat improve this rough estimate by factoring out baseload generation, which is 

generally unaffected by measures that affect marginal generation. 

The plant level capacity factor is used as a surrogate for determining how much non-baseload generation 

and emissions occur at each facility. Although there are reasons that can influence a particular plant’s 

capacity factor besides dispatch or load order (e.g., repairs, etc.), capacity factor is being used as a 

surrogate for dispatch-order for this calculation. The non-baseload information is published in eGRID 

just at the aggregate level (state, PCA, etc.), but not for individual plants. 

The following describes the procedure used to generate these non-baseload emission rates. The emission 

rates are determined starting with plant level data. First, all generation from resources that do not 

combust fuel is removed from each plant. Plants with 100% hydro, nuclear, wind, solar, and/or 

geothermal generation are removed from the non-baseload calculation. For any plants that have partial 

generation from the combustion of fuel, the emissions from the plant are retained and the generation from 

resources that do not combust fuel is subtracted out for this calculation, and the plant’s output emission 

rate is recalculated. Next, a capacity factor relationship is used to determine the percent of the plant’s 

generation and emissions to be considered non-baseload generation. All generation at plants with low 

capacity factors (greater than 0.0 and less than 0.2) would be considered non-baseload. No generation at 

plants with high capacity factors (0.8 and greater) would be considered non-baseload generation. No 
19 

generation at plants with negative generation from combustion sources would be considered non-baseload 

generation. A linear relationship would determine the percent generation that is non-baseload at plants 

with capacity factors between these 0.2 and 0.8. The non-baseload generation of each plant is multiplied 

by the plant’s output emission rate, to determine the non-baseload emissions. Finally, the total nonbaseload generation and the total non-baseload emissions are summed up at each level of aggregation 

(state, PCA, eGRID subregion, NERC region, and U.S. Total) and are used to calculate the non-baseload 

output emission rates. 

eGRID non-baseload values can be useful when attempting to estimate the emissions benefits of 

reductions in electricity use. For example, if one is interested in estimating the carbon dioxide emission 

reductions associated with the installation of energy efficient equipment or products (e.g., an 

ENERGYSTAR heating, ventilating, and air conditioning (HVAC) system); or the installation of building 

envelop technologies (e.g., sealing air leaks and insulation improvements), then one could use the eGRID 

subregion non-baseload CO2 output emission rate and the expected or actual energy savings resulting 

from the installation to estimate the CO2 emission reductions. Non-baseload values may be less 

appropriate when attempting to determine the emissions benefits of some intermittent resources, such as 

wind power. Non-baseload values should not be used for assigning an emission value for electricity use 

in carbon-footprinting exercises or GHG emissions inventory efforts. 

eGRID subregion total output emission rates are recommended for scope 2 emissions and the eGRID 

subregion non-baseload output emission rates are recommended to estimate emission reductions from 

renewable energy or energy efficiency projects that reduce consumption of grid supplied electricity. 

The methodology used to determine non-baseload emissions rates has not changed. 

iii. Combustion Emission Rates 

Combustion output emission rates for all pollutants are estimated, beginning at the plant level. Whereas 

the generation used in the denominator for calculating the traditional total output emission rate is the total 

net generation, the denominator used for calculating the combustion output emission rate is the net 

generation associated with emissions, namely, the combustion generation only. Thus, generation from 

nuclear, hydro, geothermal, solar, and wind will not be included in the calculation of this rate. This 

methodology has not changed. 

B. TREATMENT OF PLANT OWNERSHIP 

Beginning with year 2009 data, the owner(s) and operator of a plant are taken directly from those 

provided in the 2009 EIA-860. Since ownership is reported in eGRID only on the plant level, but in the 

EIA-860 on the generator level, the generators’ owner companies and percentages must be aggregated to 

the plant level, which is accomplished for each plant by MW-weighting each generator’s ownership and 

then summing to the plant level. Although eGRID’s methodology for assigning ownership on a plant 

level has not changed, eGRID has not tracked ownership or nonutility front company data as was done in 

the past, and is taking ownership data directly from the EIA-860 for year 2009 data. 

Unfortunately, there are some plants for which this plant level ownership methodology will result in 

misleading percentages. For example, if one company owns only one of several generators and that one 

generator is connected to a “clean” boiler that has emissions whose ratio to the entire plant’s emissions is 

much less than its MW’s ratio to the entire plant’s MW, that one company will, because of its MW-toplant MW ratio, have a higher plant ownership percentage attributed to it than its actual emissions plant 
20 

percentage; thus, that company will be associated with greater emissions and generation than it actually 

has. 

This situation is not typical since most plants do not have “jointly owned” generators or different owners 

for all the plant’s generators. It affects only some plants and companies and some percentage of 

emissions and generation associations in this situation. One example that does not benefit from this 

methodology is Ohio’s Cardinal plant (ORISPL = 2828), which has three generators and three boilers, 

associated on a one-to-one basis. Each generator has about the same nameplate capacity. One generator 

is owned by Ohio Power, and two by Buckeye Power Inc. The Cardinal plant ownership is approximately 

33% Ohio Power and 67% Buckeye, so 67% of the plant emissions would be attributable to Buckeye 

Power using eGRID methodology. However, the reported SO2 emissions for the two boilers associated 

with Buckeye’s two generators combined are over 90% of the Cardinal plant’s reported SO2 emissions 

total (the largest boiler has no SO2 control), and the reported NOx emissions for the two boilers associated 

with Buckeye’s two generators combined are over 70% of the Cardinal plant’s reported NOx emissions 

total (the largest boiler has an additional NOx control [selective catalytic reduction]). 

C. DETERMINATION OF PLANT PRIMARY FUEL 

The primary fuel of a plant that consumes any amount of combustible fuel is determined solely by the fuel 

that has the maximum heat input for year 2009 data. This methodology has not changed. 

For plants that do not consume any combustible fuel, the primary “fuel” is determined by the resource 

associated with the prime mover (nuclear, solar, wind, geothermal, or hydro/pumped storage) with the 

maximum generation associated with that prime mover. 

The possible original fuel codes and fuel categories for the plant primary fuel data variable (PLPRMFL in 

the eGRID plant file) are as shown in Table III-5 below. 
21 

Table III-5. Plant Primary Fuel 

Fuel Code Description Fuel Category Fuel Group 

AB agricultural byproducts biomass solid 

BG bagasse biomass solid 

BLQ black liquor biomass solid 

DG digester gas biomass gas 

LFG landfill gas biomass gas 

ME methane biomass gas 

MSB MSW biomass part biomass solid 

OBL other biomass liquid biomass liquid 

OBS other biomass solids biomass solid 

PP paper pellets biomass solid 

SLW sludge waste biomass solid 

WDL wood (waste) liquids biomass liquid 

WDS wood (waste) solids biomass solid 

ANT anthracite coal coal solid 

BIT bituminous coal coal solid 

LIG lignite coal coal solid 

SUB subbituminous coal coal solid 

SC syncoal coal solid 

RC refined coal coal solid 

WC waste coal coal solid 

SGC coal-derived synthetic gas coal gas 

NG natural gas gas gas 

PG propane gas/LPG gas gas 

BU butane gas gas gas 

DFO distillate/diesel oil oil liquid 

JF jet fuel oil liquid 

KER kerosene oil liquid 

OO other oil oil liquid 

OTL other liquid oil liquid 

PC petroleum coke oil solid 

RG refinery gas oil gas 

RFO residual oil oil liquid 

WO waste oil oil liquid 

BFG blast furnace gas other fossil gas 

COG coke oven gas other fossil gas 

HY hydrogen other fossil gas 

LB liquid byproduct other fossil liquid 

MH methanol other fossil liquid 

MSF MSW other fossil part other fossil solid 

OG other gas other fossil gas 

OTS other solid other fossil solid 

TDF tire-derived fuel other fossil solid 

Note that since solid waste plants are broken down into biomass and fossil components, a solid waste 

plant will have “MSB” as the primary fuel. 

Since the plant primary fuel variable is based solely on heat input, a partially combustible fueled plant, 

i.e., one that burns some combustible fuel but is mainly a nuclear, hydro, or solar plant, the plant primary 

fuel designation can be misleading. Thus, a new variable, plant primary fuel generation category, was 

developed for the plant file, beginning with year 2007 data. This new variable is based on the maximum 
22 

net generation fuel category and can be one of eleven values (the same as the number of plant annual net 

generation fuel categories) as shown in Table III-6. 

Table III-6. Plant Primary Fuel Generation Category 

Fuel Category Description 

CL Coal 

OL Oil 

GS Gas 

NC Nuclear 

HY Hydro 

BM Biomass 

WI Wind 

SO Solar 

GT Geothermal 

OF Other Fossil 

OP Other Unknown/Purchased/Waste Heat 

D. ESTIMATION OF RESOURCE MIX 

Resource mix is a collection of nonrenewable and renewable resources that are used to generate 

electricity. Nonrenewable resources include fossil fuels (e.g., coal, oil, gas, and other fossil) and nuclear 

energy source; renewable energy resources include biomass, solar, wind, geothermal, and hydro. A 

percentage is assigned to each resource or group of resources. Resource mix is displayed in eGRID and 

expressed in both MWh and generation percent. 

For cases in which there is only one fuel and its generation is negative, that fuel’s generation percent is 

assigned 100%. For cases in which there are fuels with both negative and positive net generation, the 

generation percents only include the positive generation in both the denominator and numerator. For 

cases in which there are only two fuels and both net generations are negative, both fuels’ generation 

percents are assigned 0%. 

For the three grouped aggregate categories – total net generation from nonrenewable, total net generation 

from all renewables, and total net generation from renewables minus hydro, the sum of the total net 

generation from renewables and from all nonrenewables equals the total net generation. In cases for 

which there is both positive and negative fuel generation in the nonrenewables category (it is unlikely to 

happen in the renewables category), the category percentages may be misleading since only the positive 

generation components are considered in calculating the generation percents for total renewables and 

nonrenewables. Similarly, for the two grouped aggregated categories of combustion net generation and 

noncombustion net generation, their sum equals the total net generation. For cases in which there is more 

than one negative nonrenewables (or combustion) net generation value and there is no renewables (or 

noncombustion) net generation, the total nonrenewables (or combustion) resource mix is assigned 100 %. 

The methodology for the determination of resource mix has not changed. 

eGRID plant resource mix and net generation are derived from the EIA-923 prime mover level data, 

which provides the information on a plant-prime mover-fuel level. However, there are some cases for 

which only the EPA/CAMD-based net generation is available for use in eGRID. In these cases, the 

primary fuel (based on the maximum heat input value) is assigned 100% of the generation for the 

resource mix. 
23 

E. DETERMINATION OF PLANT AGGREGATION LINKS 

The plant’s state, operator, and owner(s), as well as the utility service territory EGCs (updated as needed) 

are already associated with each plant and based on EIA data. 

A graphic representation of examples of relationships among plants, utility service territories, PCAs, 

eGRID subregions, and NERC regions is depicted below in Figure III-1. 

Figure III-1. Examples of Plant Through NERC Linkages 

1. NERC Region 

NERC region refers to a region designated by the North American Electric Reliability Corporation. Each 

NERC region listed in eGRID represents one of ten regional portions of the North American electricity 

transmission grid: eight in the contiguous United States, plus Alaska and Hawaii (which are not part of 

the formal NERC regions, but are considered so in eGRID). The NERC regions themselves have not 

changed from those in eGRID2010; the Electric Reliability Council of Texas (ERCOT) NERC region did 

change its name to the Texas Reliability Entity (TRE) between eGRID years 2006 and 2007 data. Note, 

however, that some plants operating in each NERC region do change from year to year. The ten NERC 

region names and their acronyms for eGRID are displayed in Table III-7. 
24 

Table III-7. NERC Region Acronym and Names for eGRID 

NERC Region NERC Name 

ASCC Alaska Systems Coordinating Council 

FRCC Florida Reliability Coordinating Council 

HICC Hawaiian Islands Coordinating Council 

MRO Midwest Reliability Organization 

NPCC Northeast Power Coordinating Council 

RFC Reliability First Corporation 

SERC SERC Reliability Corporation 

SPP Southwest Power Pool 

TRE Texas Regional Entity 

WECC Western Electricity Coordinating Council 

Although some NERC regions include portions of Canada and/or Mexico that are integrated with U.S. 

grids, eGRID aggregation data are limited to generation within the United States. 

A representation of the NERC region map used for eGRID2012 is included in Appendix B. This map, 

which is a representational one, shows approximate boundaries because they are based on companies, not 

on strictly geographical boundaries. Since NERC regions are based not on location but on companies, the 

linkage is between a plant and its transmission/distribution/utility service territory, which in turn is linked 

to a PCA, which is associated with a NERC region. 

2. eGRID Subregion 

eGRID subregions are developed as subsets of NERC regions. In eGRID2002 and earlier, these grid 

regions were similar to EPA’s IPM subregions (except for the New York and California areas). Many of 

these older subregions no longer exist since their NERC regions no longer exist. At this juncture, NERC 

has only defined subregions for the WECC NERC region. Thus, for the WECC NERC region and for 

those other NERC regions that did not change configuration, the newer eGRID subregions will remain in 

effect. Definitions of the eGRID subregions were made by EPA after consultation with NERC staff. 

A representation of the eGRID subregion map used for eGRID2012 is included in Appendix B. This 

map, which is a representational one, shows approximate boundaries because they are based on 

companies, not on strictly geographical boundaries. Since plant-associated eGRID subregions are based 

on companies, the linkage is between a plant and its transmission/distribution/utility service territory, not 

the plant location. Thus, there is no shape file or subregion layer available for eGRID subregions. 

eGRID subregions are identified and defined by EPA – using the NERC regions and PCAs as a guide. 

An eGRID subregion is often, but not always, equivalent to an Integrated Planning Model (IPM) 

subregion. The 26 eGRID subregions are subsets of the NERC regions as configured on December 2010. 

The plant’s associated PCA determines the plant’s associated eGRID subregion, which is defined as a 

subset of the NERC region, and is composed of entire PCAs – with the exception of PJM Interconnection 

and New York Independent System Operator PCAs, which are each associated with three eGRID 

subregions. The eGRID subregions themselves have not changed since eGRID2002 year 2000 data. 

Note, however, that some plants operating in each eGRID subregion do change from year to year. The 26 

eGRID subregion names and their acronyms are displayed in Table III-8, along with the U.S interconnect 

power grid that they are part of. Note that the five eGRID subregions within the SERC NERC region are 

also known by other names; specifically, SERC Midwest is also called Gateway, SERC Mississippi 

Valley is also called Delta, SERC Tennessee Valley is also called Central, SERC South is also called 

Southeastern, and SERC Virginia/Carolina is also called VACAR. 
25 

Table III-8. eGRID Subregion Acronym and Names for eGRID 

eGRID Subregion eGRID Subregion Name Power Grid 

FRCC FRCC All Eastern 

MROE MRO East Eastern 

MROW MRO West Eastern 

NEWE NPCC New England Eastern 

NYCW NPCC NYC/Westchester Eastern 

NYLI NPCC Long Island Eastern 

NYUP NPCC Upstate NY Eastern 

RFCE RFC East Eastern 

RFCM RFC Michigan Eastern 

RFCW RFC West Eastern 

SRMW SERC Midwest Eastern 

SRMV SERC Mississippi Valley Eastern 

SRSO SERC South Eastern 

SRTV SERC Tennessee Valley Eastern 

SRVC SERC Virginia/Carolina Eastern 

SPNO SPP North Eastern 

SPSO SPP South Eastern 

CAMX WECC California Western 

NWPP WECC Northwest Western 

RMPA WECC Rockies Western 

AZNM WECC Southwest Western 

ERCT ERCOT All ERCOT 

AKGD ASCC Alaska Grid Alaska 

AKMS ASCC Miscellaneous Alaska 

HIOA HICC Oahu Hawaii 

HIMS HICC Miscellaneous Hawaii 

3. Power Control Area 

A Power Control Area (PCA) (or Balancing Authority, as NERC now terms it) is a portion of an 

integrated power grid for which a single dispatcher has operational control of all electric generators. 

PCAs range in size from small municipal utilities such as Columbia MO City of, to large power pools 

such as PJM Interconnection. There have been some changes to PCAs from eGRID2010 to eGRID2012 

(NERC, 2012a). 

In Alaska, isolated electric utility systems, which are not part of an integrated power grid, have been 

grouped into a nominal PCA called “Alaska Misc.” In Hawaii, isolated electric utility systems, which are 

not part of an integrated power grid, have been grouped into a nominal PCA called “Hawaii Misc.” These 

two PCAs have dummy (negative) codes since there are none available from EIA: -1 for Alaska Misc and 

-2 for Hawaii Misc. Otherwise, PCA IDs are assigned based on the EIA-861 (EIA, 2011b) if possible; if 

the name is essentially the same as an EGC’s, then the EIA EGC code from the EIA-860 is used (EIA, 

2011a). 

In eGRID, a PCA associated with a plant is determined by the transmission lines connecting the PCA and 

the plant through a utility entity (previously thought of/known as a utility service area) and now reported 

to EIA as “the owner of the transmission or distribution facilities to which the plant is interconnected” 

(EIA, 2011a) and that eGRID terms a utility service territory. 
26 

PCAs are assigned according to the utility service territory in which the plant is physically located. 

The PCA associated with a plant is determined by the owner of the transmission/distribution 

utility/regulated EGC (not parent company) associated with the plant. At present, there is not one Federal 

file that can be used to link year 2009 utility EGCs with their PCAs, but the PCAs in eGRID have been 

updated and reported by NERC to reflect a March 2012 configuration (NERC, 2012a). 

The PCA link to the NERC region has been determined by NERC, as has the PCA association with the 

Midwest Independent Transmission System Operator (MISO) for 26 PCAs. The plant’s associated 

PCA determines the plant’s associated NERC region, except for the PJM Interconnection PCA, which 

has plants in two NERC regions. NERC provides the linkage used in eGRID between PCAs and 

NERC regions by publishing the currently registered balancing authorities (PCAs) in the NERC 

Compliance Registry (NERC, 2012a). The NERC acronyms are also assigned by NERC. The 

possible relationships between the 129 PCAs (119 PCAs are displayed in eGRID2012 year 2009 data) 

and 10 NERC regions are shown below in Table III-9. 

Table III-9. PCA – NERC Region Relationship 

PCA Name NERC Region NERC Name 

Alaska Misc ASCC Alaska Systems Coordinating Council 

Anchorage Municipality of ASCC Alaska Systems Coordinating Council 

Chugach Electric Assn Inc ASCC Alaska Systems Coordinating Council 

Golden Valley Elec Assn Inc ASCC Alaska Systems Coordinating Council 

Florida Municipal Power Pool FRCC Florida Reliability Coordinating Council 

Florida Power & Light Company FRCC Florida Reliability Coordinating Council 

Gainesville Regional Utilities FRCC Florida Reliability Coordinating Council 

Homestead City of FRCC Florida Reliability Coordinating Council 

JEA FRCC Florida Reliability Coordinating Council 

New Smyrna Beach Utilities Commission of FRCC Florida Reliability Coordinating Council 

Progress Energy Florida FRCC Florida Reliability Coordinating Council 

Seminole Electric Cooperative FRCC Florida Reliability Coordinating Council 

Tallahassee City of FRCC Florida Reliability Coordinating Council 

Tampa Electric Company FRCC Florida Reliability Coordinating Council 

Hawaii Electric Light Co Inc HICC Hawaiian Islands Coordinating Council 

Hawaii Misc HICC Hawaiian Islands Coordinating Council 

Hawaiian Electric Co Inc HICC Hawaiian Islands Coordinating Council 

Alliant - East MRO Midwest Reliability Organization 

Alliant - West MRO Midwest Reliability Organization 

Dairyland Power Cooperative MRO Midwest Reliability Organization 

Great River Energy MRO Midwest Reliability Organization 

Lincoln Electric System MRO Midwest Reliability Organization 

Madison Gas and Electric Company MRO Midwest Reliability Organization 

MidAmerican Energy Company MRO Midwest Reliability Organization 

Minnesota Power MRO Midwest Reliability Organization 

Muscatine Power and Water MRO Midwest Reliability Organization 

Nebraska Public Power District MRO Midwest Reliability Organization 

Northern States Power MRO Midwest Reliability Organization 

Omaha Public Power District MRO Midwest Reliability Organization 

Otter Tail Power Company MRO Midwest Reliability Organization 

Southern Minnesota Municipal Power Agcy MRO Midwest Reliability Organization 

Upper Peninsula Power Company MRO Midwest Reliability Organization 
27 

Table III-9 (continued). 

PCA Name NERC Region NERC Name 

WAPA - Upper Great Plains East MRO Midwest Reliability Organization 

Wisconsin Public Service Corporation MRO Midwest Reliability Organization 

New Brunswick System Operator NPCC Northeast Power Coordinating Council

New England ISO NPCC Northeast Power Coordinating Council

New York ISO NPCC Northeast Power Coordinating Council

Consumers Energy Company RFC Reliability First Corporation 

Detroit Edison Company RFC Reliability First Corporation 

Duke Energy Corporation RFC Reliability First Corporation 

Hoosier Energy REC RFC Reliability First Corporation 

Indianapolis Power & Light Company RFC Reliability First Corporation 

Michigan Electric Coordinated Systems RFC Reliability First Corporation 

Northern Indiana Public Service Company RFC Reliability First Corporation 

Ohio Valley Electric Corporation RFC Reliability First Corporation 

PJM Interconnection 

RFC, 

SERC 

Reliability First Corporation, 

SERC Reliability Corporation 

Southern Indiana Gas & Electric Company RFC Reliability First Corporation 

Wisconsin Energy Corporation RFC Reliability First Corporation 

Alcoa Power - Yadkin Division SERC SERC Reliability Corporation 

Ameren Services Company SERC SERC Reliability Corporation 

Associated Electric Cooperative Inc SERC SERC Reliability Corporation 

Benton City of SERC SERC Reliability Corporation 

Big Rivers Electric Corporation SERC SERC Reliability Corporation 

CECD - Batesville SERC SERC Reliability Corporation 

Columbia MO City of SERC SERC Reliability Corporation 

Conway City of SERC SERC Reliability Corporation 

Duke Energy Carolinas SERC SERC Reliability Corporation 

East Kentucky Power Cooperative SERC SERC Reliability Corporation 

Electric Energy Inc SERC SERC Reliability Corporation 

Entergy SERC SERC Reliability Corporation 

LG&E and KU Services Company SERC SERC Reliability Corporation 

Louisiana Generating SERC SERC Reliability Corporation 

North Little Rock AR City of SERC SERC Reliability Corporation 

Osceola AR City of SERC SERC Reliability Corporation 

Plum Point Energy Associates SERC SERC Reliability Corporation 

PowerSouth Energy Cooperative SERC SERC Reliability Corporation 

Progress Energy Carolinas SERC SERC Reliability Corporation 

Ruston LA City of SERC SERC Reliability Corporation 

South Carolina Electric & Gas Company SERC SERC Reliability Corporation 

South Carolina Public Service Authority SERC SERC Reliability Corporation 

South Mississippi Electric Power Assn SERC SERC Reliability Corporation 

Southeastern Power Administration SERC SERC Reliability Corporation 

Southern Company Services SERC SERC Reliability Corporation 

Southern Illinois Power Cooperative SERC SERC Reliability Corporation 

Springfield IL - CWLP City of SERC SERC Reliability Corporation 

Tennessee Valley Authority SERC SERC Reliability Corporation 

Union Power Partners SERC SERC Reliability Corporation 

West Memphis AR City of SERC SERC Reliability Corporation 

AEP - PSO/SWEPCO SPP Southwest Power Pool 

Cleco Corporation SPP Southwest Power Pool 

Empire District Electric Company SPP Southwest Power Pool 
28 

Table III-9 (continued). 

PCA Name NERC Region NERC Name 

Grand River Dam Authority SPP Southwest Power Pool 

Independence MO City of SPP Southwest Power Pool 

Kansas City Board of Public Utilities SPP Southwest Power Pool 

Kansas City Power & Light Co-GMO SPP Southwest Power Pool 

Kansas City Power & Light Company SPP Southwest Power Pool 

Lafayette Utilities System SPP Southwest Power Pool 

Louisiana Energy & Power Authority SPP Southwest Power Pool 

Oklahoma Gas and Electric Company SPP Southwest Power Pool 

Southwestern Power Administration SPP Southwest Power Pool 

Southwestern Public Service Company SPP Southwest Power Pool 

Springfield MO City Utilities of SPP Southwest Power Pool 

Sunflower Electric Power Corporation SPP Southwest Power Pool 

Westar Energy SPP Southwest Power Pool 

Western Farmers Electric Cooperative SPP Southwest Power Pool 

ERCOT ISO TRE Texas Regional Entity 

Arizona Public Service Company WECC Western Electricity Coordinating Council 

Arlington Valley WECC Western Electricity Coordinating Council 

Avista Corporation WECC Western Electricity Coordinating Council 

Balancing Authority of Northern California WECC Western Electricity Coordinating Council 

Bonneville Power Administration WECC Western Electricity Coordinating Council 

California ISO WECC Western Electricity Coordinating Council 

El Paso Electric Company WECC Western Electricity Coordinating Council 

Gila River Power WECC Western Electricity Coordinating Council 

Griffith Energy WECC Western Electricity Coordinating Council 

Idaho Power Company WECC Western Electricity Coordinating Council 

Imperial Irrigation District WECC Western Electricity Coordinating Council 

Los Angeles Department of Water and Power WECC Western Electricity Coordinating Council 

NaturEner Power Watch WECC Western Electricity Coordinating Council 

Nevada Power Company WECC Western Electricity Coordinating Council 

New Harquahala Generating Company WECC Western Electricity Coordinating Council 

NorthWestern Corporation WECC Western Electricity Coordinating Council 

PUD No. 1 of Chelan County WECC Western Electricity Coordinating Council 

PUD No. 1 of Douglas County WECC Western Electricity Coordinating Council 

PUD No. 2 of Grant County WECC Western Electricity Coordinating Council 

PacifiCorp WECC Western Electricity Coordinating Council 

Portland General Electric Company WECC Western Electricity Coordinating Council 

Public Service Company of Colorado WECC Western Electricity Coordinating Council 

Public Service Company of New Mexico WECC Western Electricity Coordinating Council 

Puget Sound Energy WECC Western Electricity Coordinating Council 

Salt River Project WECC Western Electricity Coordinating Council 

Seattle City Light WECC Western Electricity Coordinating Council 

Sierra Pacific Power Company WECC Western Electricity Coordinating Council 

Tacoma Power WECC Western Electricity Coordinating Council 

Tucson Electric Power WECC Western Electricity Coordinating Council 

Turlock Irrigation District WECC Western Electricity Coordinating Council 

WAPA - Desert Southwest Region WECC Western Electricity Coordinating Council 

WAPA - Rocky Mountain Region WECC Western Electricity Coordinating Council 

WAPA - Upper Great Plains West WECC Western Electricity Coordinating Council 
29 

The 2009 EIA-860 (EIA, 2011a) specifies each plant’s owner of the transmission/distribution 

utility/regulated EGC (also called utility service territory), but there appear to be many that are incorrect. 

TS|Pechan has used a WECC document, “Existing Generation and Significant Additions and Changes to 

System Facilities Data as of January 1, 2007” (WECC, 2007) and independent research to provide PCAs 

and eGRID subregions (then the WECC plants’ utility service territories were updated as needed). The 

other nine NERC regions’ utility service territories were also reviewed and updated as needed, as were 

the PCAs, eGRID subregions, and NERC regions. 

Since PCAs are not strictly geographically based, there are no shape files available for mapping them. 

Several years ago, the NERC website, www.nerc.com, had a PCA “bubble map” available to show the 

relationship between the PCAs and their approximate relationship to NERC regions, but it was simply an 

approximation. A recent PCA bubble map does not seem to be available from NERC 

The relationship among PCAs, eGRID subregions, and NERC regions, as well as the PCA-MISO 

association is depicted in Table III-10 below. 

Table III-10. PCA – MISO – eGRID Subregion – NERC Region Relationship 

PCA Name MISO? eGRID Subregion NERC Region 

AEP - PSO/SWEPCO SPSO SPP 

Alaska Misc AKMS ASCC 

Alcoa Power - Yadkin Division SRVC SERC 

Alliant - East Y MROE MRO 

Alliant - West Y MROW MRO 

Ameren Services Company Y SRMW SERC 

Anchorage Municipality of AKGD ASCC 

Arizona Public Service Company AZNM WECC 

Arlington Valley AZNM WECC 

Associated Electric Cooperative Inc SRTV SERC 

Avista Corporation NWPP WECC 

Balancing Authority of Northern California CAMX WECC 

Benton City of SRMV SERC 

Big Rivers Electric Corporation Y SRTV SERC 

Bonneville Power Administration NWPP WECC 

CECD - Batesville SRMV SERC 

California ISO CAMX WECC 

Chugach Electric Assn Inc AKGD ASCC 

Cleco Corporation SPSO SPP 

Columbia MO City of Y SRMW SERC 

Consumers Energy Company Y RFCM RFC 

Conway City of SRMV SERC 

Dairyland Power Cooperative Y MROW MRO 

Detroit Edison Company Y RFCM RFC 

Duke Energy Carolinas SRVC SERC 

Duke Energy Corporation RFCW RFC 

ERCOT ISO ERCT TRE 

East Kentucky Power Cooperative SRTV SERC 

El Paso Electric Company AZNM WECC 

Electric Energy Inc SRTV SERC 

Empire District Electric Company SPNO SPP 

Entergy SRMV SERC 
30 

Table III-10 (continued). 

PCA Name MISO? eGRID Subregion NERC Region 

Florida Municipal Power Pool FRCC FRCC 

Florida Power & Light Company FRCC FRCC 

Gainesville Regional Utilities FRCC FRCC 

Gila River Power AZNM WECC 

Golden Valley Elec Assn Inc AKGD ASCC 

Grand River Dam Authority SPSO SPP 

Great River Energy Y MROW MRO 

Griffith Energy AZNM WECC 

Hawaii Electric Light Co Inc HIMS HICC 

Hawaii Misc HIMS HICC 

Hawaiian Electric Co Inc HIOA HICC 

Homestead City of FRCC FRCC 

Hoosier Energy REC Y RFCW RFC 

Idaho Power Company NWPP WECC 

Imperial Irrigation District AZNM WECC 

Independence MO City of SPNO SPP 

Indianapolis Power & Light Company Y RFCW RFC 

JEA FRCC FRCC 

Kansas City Board of Public Utilities SPNO SPP 

Kansas City Power & Light Co-GMO SPNO SPP 

Kansas City Power & Light Company SPNO SPP 

LG&E and KU Services Company SRTV SERC 

Lafayette Utilities System SPSO SPP 

Lincoln Electric System MROW MRO 

Los Angeles Department of Water and Power CAMX WECC 

Louisiana Energy & Power Authority SPSO SPP 

Louisiana Generating SRMV SERC 

Madison Gas and Electric Company Y MROE MRO 

Michigan Electric Coordinated Systems Y RFCM RFC 

MidAmerican Energy Company Y MROW MRO 

Minnesota Power Y MROW MRO 

Muscatine Power and Water Y MROW MRO 

NaturEner Power Watch NWPP WECC 

Nebraska Public Power District MROW MRO 

Nevada Power Company AZNM WECC 

New Brunswick System Operator NEWE NPCC 

New England ISO NEWE NPCC 

New Harquahala Generating Company AZNM WECC 

New Smyrna Beach Utilities Commission of FRCC FRCC 

New York ISO NYCW NPCC 

New York ISO NYLI NPCC 

New York ISO NYUP NPCC 

North Little Rock AR City of SRMV SERC 

NorthWestern Corporation NWPP WECC 

Northern Indiana Public Service Company Y RFCW RFC 

Northern States Power Y MROW MRO 

Ohio Valley Electric Corporation RFCW RFC 

Oklahoma Gas and Electric Company SPSO SPP 

Omaha Public Power District MROW MRO 
31 

Table III-10 (continued). 

PCA Name MISO? eGRID Subregion NERC Region 

Osceola AR City of SRMV SERC 

Otter Tail Power Company Y MROW MRO 

PJM Interconnection RFCE RFC 

PJM Interconnection RFCW RFC 

PJM Interconnection SRVC SERC 

PUD No. 1 of Chelan County NWPP WECC 

PUD No. 1 of Douglas County NWPP WECC 

PUD No. 2 of Grant County NWPP WECC 

PacifiCorp NWPP WECC 

Plum Point Energy Associates SRMV SERC 

Portland General Electric Company NWPP WECC 

PowerSouth Energy Cooperative SRSO SERC 

Progress Energy Carolinas SRVC SERC 

Progress Energy Florida FRCC FRCC 

Public Service Company of Colorado RMPA WECC 

Public Service Company of New Mexico AZNM WECC 

Puget Sound Energy NWPP WECC 

Ruston LA City of SRMV SERC 

Salt River Project AZNM WECC 

Seattle City Light NWPP WECC 

Seminole Electric Cooperative FRCC FRCC 

Sierra Pacific Power Company NWPP WECC 

South Carolina Electric & Gas Company SRVC SERC 

South Carolina Public Service Authority SRVC SERC 

South Mississippi Electric Power Assn SRSO SERC 

Southeastern Power Administration SRVC SERC 

Southern Company Services SRSO SERC 

Southern Illinois Power Cooperative Y SRMW SERC 

Southern Indiana Gas & Electric Company Y RFCW RFC 

Southern Minnesota Municipal Power Agcy Y MROW MRO 

Southwestern Power Administration SPSO SPP 

Southwestern Public Service Company SPSO SPP 

Springfield IL - CWLP City of Y SRMW SERC 

Springfield MO City Utilities of SPSO SPP 

Sunflower Electric Power Corporation SPNO SPP 

Tacoma Power NWPP WECC 

Tallahassee City of FRCC FRCC 

Tampa Electric Company FRCC FRCC 

Tennessee Valley Authority SRTV SERC 

Tucson Electric Power AZNM WECC 

Turlock Irrigation District CAMX WECC 

Union Power Partners SRMV SERC 

Upper Peninsula Power Company Y MROE MRO 

WAPA - Desert Southwest Region AZNM WECC 

WAPA - Rocky Mountain Region RMPA WECC 

WAPA - Upper Great Plains East MROW MRO 

WAPA - Upper Great Plains West NWPP WECC 

West Memphis AR City of SRMV SERC 

Westar Energy SPNO SPP 
32 

Table III-10 (continued). 

PCA Name MISO? eGRID Subregion NERC Region 

Western Farmers Electric Cooperative SPSO SPP 

Wisconsin Energy Corporation Y RFCW RFC 

Wisconsin Public Service Corporation Y MROE MRO 

F. TREATMENT OF AGGREGATION LEVELS 

All aggregation levels are based on the plant file. The state file data are developed by summing up the 

plant data (adjusted heat input, adjusted emissions, adjusted fuel-based emissions, net generation, fuelbased net generation, nameplate capacity, and the plant data values needed to calculate non-baseload 

emission rates), based on the state in which the plant is located. The PCA, eGRID subregion, and NERC 

region files are developed by summing up the plant data for each of the values for each aggregation level. 

This methodology has not changed. 

The totals from the plant, state, PCA, eGRID subregion, NERC region, and U.S. files’ adjusted heat 

input, adjusted emissions, adjusted fuel-based emissions, net generation, fuel-based net generation, and 

nameplate capacity data should be the same, after accounting for rounding. 
33 

SECTION IV. SPECIFIC eGRID IDENTIFIER CODES, NAME 

CHANGES AND ASSOCIATIONS 

eGRID2012 generally uses identifier (ID) codes (for plants, companies, etc.) assigned by EIA. However, 

identifiers (IDs) and certain corresponding names have been changed in eGRID2012 in order to minimize 

confusion. If needed, entities that do not have an EIA designated ID are assigned values in eGRID. The 

specifics are delineated below. 

A. PLANT LEVEL 

One plant, Laramie River Station (ORISPL = 6204) in Wyoming, has three boilers and generators that 

supply power to two different power grids. Consequently, the first boiler (1) has become a separate plant 

in eGRID2012 with a dummy ORISPL = 6204.1 because it is operated within a PCA that is in the Eastern 

grid; while the second and third boilers have become a separate plant with a dummy ORISPL = 6204.2 

because they are operated within a PCA that is in the Western grid. This plant representation occurs in all 

editions of eGRID. 

B. EGC, COMPANY LEVEL 

EGCs, for purposes of eGRID files, are operators, owners, and utility service territories of power plants 

for the given year. Each EGC has a unique code assigned by EIA. 

Several other companies, as utility service territories, were broken up and given dummy IDs because the 

company operates in more than one power control area or do not have an EIA company code in any 

published EIA electric power survey data. These include: 

 Basin Electric Power Coop EGC (ID = -7304), which is broken up into two divisions: 

Basin Electric Power Coop-East EGC (ID = 1307.1) and Basin Electric Power CoopWest EGC (ID = 1307.2); 

 PacifiCorp EGC (ID = 14354), which is broken up into two divisions: PacifiCorp-Rocky 

Mtn EGC (ID = 14354.1) and PacifiCorp-Pacific EGC (ID = 14354.2); and

 Liberty Utilities (ID = 66666). 
34 

[This page intentionally left blank.] 
THE BLR FILE 

35 

SECTION V. DESCRIPTION OF DATA ELEMENTS 

For year 2009 data, eGRID2012 has 8 aggregation files named BLR (boiler), GEN (generator), PLNT 

(plant), ST (state), PCAL (PCA), SRL (eGRID subregion), NRL (NERC region), and US (United States 

total). The regional grid gross loss factor data are also included. Appendix A provides the file structure 

for the eGRID2012 2007 data year, which include variable descriptions and original data sources. 

Definitions for like variables are not repeated after the description in the plant file. For example, in the 

plant file, the net generation in MWh is defined at the plant level for the data element PLNGENAN. For 

each subsequent file, the net generation, nnNGENAN (where nn is ST, PC, SR, NR, or US) is not 

described in Appendix A; it is simply the sum of PLNGENAN attributed to the aggregation entity. 

A. THE BLR (BOILER) FILE 

There are 34 variables in the first file, BLR, which contains unit level data. The one new variable for this 

data year is the first one. The one replacement variable (previously NBPFLAG) is PRGCODE, which 

displays all – not just one -- of the EPA programs to which the unit is subjected. Note that summing the 

boiler unadjusted emissions to the plant level may not result in the same values as the plant unadjusted 

emissions since additional emissions from prime movers not covered by the EPA/CAMD boiler level data 

may be included in the plant emissions values. 

1. eGRID2012 year 2009 File Boiler Sequence Number (SEQBLR09) –

The boiler records in this year 2009 data file are sorted by state postal code abbreviation, 

plant name, plant code, and boiler ID, and are assigned a unique sequential number 

beginning with 1. This sequence number is unlikely to be the same as the sequence 

number in the year 2007 eGRID file for the same entity. 

This is a new field in eGRID2012. 

2. Plant State Abbreviation (PSTATABB) –

This field contains the two character postal code abbreviation of the state in which the 

plant is located. 

 Source: EIA-860 

3. Plant Name (PNAME) –

This field is the name associated with each plant. 

 Source: EIA-860 + updates 

4. DOE/EIA ORIS Plant or Facility Code (ORISPL) –

This plant code corresponds to PNAME and was originally developed for power plants 

by the Office of the Regulatory Information System (ORIS), which was a part of the 

Federal Power Commission. It is now assigned by EIA and is used as a unique plant 

identification code for many EPA electric power databases, too. One plant code, that for 

Laramie River, has been altered. See Section IV for details. 

 Source: EIA-860 + updates 

5. Boiler ID (BLRID) –

This field identifies the unit ID for the unit that produces the emissions. The unit may be 

a steam boiler, combustion turbine, or engine. 

 Sources: EPA/CAMD, EIA-923 
THE BLR FILE 

36 

6. Acid Rain Program Flag (ARPFLAG) – 

This field indicates if the unit reports EPA/CAMD emissions data annually under Title 

IV of the Clean Air Act Amendments of 1990 as part of the Acid Rain Program (1=Yes). 

 Source: EPA/CAMD 

7. Program Codes (PRGCODE) – 

This field lists, as reported to EPA/CAMD, the programs that the unit is subject to. 

Values may be combined and separated by commas. The individual values possible are: 

 ARP =Acid Rain Program 

 CAIRNOX =Clean Air Interstate Rule for NOx (annual) 

 CAIROS =Clean Air Interstate Rule for NOx (ozone season) 

 CAIRSO2 =Clean Air Interstate Rule for SO2

 NHNOX =New Hampshire’s special NOx program 

 RGGI =Regional Greenhouse Gas Initiative (CO2) 

 SIPNOX =NOx SIP Call 

See http://epa.gov/airmarkets/progsregs/index.html#current for additional information. 

This field, beginning with year 2009 data, replaces the more limiting field, NBPFLAG, 

from earlier eGRID data years. 

 Source: EPA/CAMD 

 8. Boiler Bottom and Firing Type (BOTFIRTY) – 

This field displays the boiler bottom type followed by the firing type. This field is based 

on the “best” data source display in field #24. 

Possible values are: 

For bottom type: 

 = Blank 

DRY = Dry bottom 

WET = Wet bottom 

 

For firing type: 

 = Blank 

ARCH = Arch firing 

CELL 

CONCEN/TANG 

= Cell 

= Concentric (tangentially-fired) 

CYCLONE = Cyclone firing 

DUCTBURNER = Duct burner 

FLUIDIZED 

FRONT/WALL 

N/A 

OPPOS/WALL 

OTHER 

REAR/WALL 

SIDE/WALL 

= Fluidized bed firing 

= Front firing (wall-fired) 

= Not available 

= Opposite firing (wall-fired) 

= Other 

= Rear firing (wall-fired0 

= Side firing (wall-fired) 

STOKER = Stoker (spreader) 

TANGENTIAL = Tangential firing 

TURBO = Turbo 

VERTICAL = Vertical firing 

WALL = Wall firing 

 Source: EPA/CAMD, EIA-860 
THE BLR FILE 

37 

9. Number of Associated Generators (NUMGEN) –

This field provides the number of generators associated with each EIA-860 boiler in the 

file. 

 Source: EIA-860 

 

 10. Boiler Primary Fuel (FUELB1) – 

This field specifies the primary fuel determined from EIA-923 boiler reported data or the 

primary fuel reported to EPA/CAMD. This field is based on the “best” data source 

display in field #24. 

Possible values are: 

AB = Agricultural byproduct 

BFG 

BG 

= Blast furnace gas 

= Butane gas 

BIT = Bituminous coal 

BLQ = Black liquor 

COG = Coke oven gas 

DFO = Distillate fuel oil, light fuel oil, FO2, diesel oil 

DG = Digester gas (other biomass gas) 

HY = Hydrogen 

JF = Jet fuel 

KER = Kerosene 

LFG = Landfill gas 

LIG = Lignite coal 

MSB = Municipal solid waste biomass component 

NG = Natural gas 

OBS = Other biomass solid 

OG = Other gas 

OO 

OTH 

= Other oil 

= Other 

PC = Petroleum coke 

PRG = Process gas 

RFO = Residual fuel oil, heavy fuel oil, petroleum 

RG = Refinery gas 

SC = Synthetic coal (syncoal) 

SLW = Sludge waste 

SUB = Subbituminous coal 

TDF = Tire-derived fuel 

WC = Waste coal 

WDL = Wood, wood waste liquid 

WDS = Wood, wood waste solid 

WO = Waste oil 

Source: EPA/CAMD, EIA-923 

 

11. Unit Operating Hours (HRSOP) –

 This field is the number of hours that an EPA/CAMD unit reported operating during the 

 year. 

 Source: EPA/CAMD 

 
THE BLR FILE 

38 

12. Boiler Unadjusted Annual EPA/CAMD Heat Input (HTIEAN) –

This field, in MMBtu, is the unit’s unadjusted annual total heat input assigned by 

EPA/CAMD, based on the values reported to EPA/CAMD. When not available, it is 

zero. 

 Source: EPA/CAMD 

13. Boiler Unadjusted Ozone Season EPA/CAMD Heat Input (HTIEOZ) –

This field, in MMBtu, is the unit’s unadjusted ozone season (May through September) 

heat input, based on the values reported to EPA/CAMD. When not available, it is zero. 

 Source: EPA/CAMD 

14. Boiler Unadjusted Annual Total EIA-Based Calculated Heat Input (HTIFAN) –

This field, in MMBtu, provides the boiler’s unadjusted annual total heat input, calculated 

using EIA-923 boiler data, when available. When not available, it is zero. 

Source: EIA-923 

15. Boiler Unadjusted Ozone Season EIA-Based Calculated Heat Input (HTIFOZ) –

This field, in MMBtu, provides the boiler’s unadjusted ozone season (May through 

September) heat input, calculated using EIA-923 boiler data, when available. If EIA-923 

boiler ozone season data are not available, but EIA-923 boiler annual data are, then the 

value in this field is calculated as 5/12 of the annual value. Otherwise, the value is zero. 

Source: EIA-923 

16. Boiler Unadjusted Annual EPA/CAMD NOx Emissions (NOXEAN) –

This field, in tons, is the unit’s unadjusted NOx emissions assigned by EPA/CAMD based 

on the values reported to EPA/CAMD. When not available, it is zero. 

 Source: EPA/CAMD 

17. Boiler Unadjusted Ozone Season EPA/CAMD NOx Emissions (NOXEOZ) –

This field, in tons, is the unit’s unadjusted ozone season (May through September) NOx

emissions based on values reported to EPA/CAMD. When not available, it is zero. 

Source: EPA/CAMD 

18. Boiler Unadjusted Annual EIA-Based Calculated NOx Emissions (NOXFAN) –

This field, in tons, is the boiler’s unadjusted annual NOx emissions calculated using EIA923 boiler reported data, when available, and the EPA-approved EF. When not available, 

it is zero. 

Source: EIA-923 

19. Boiler Unadjusted Ozone Season EIA-Based Calculated NOx Emissions 

 (NOXFOZ) –

This field, in tons, is the boiler’s unadjusted ozone season (May through September) NOx

emissions calculated from EIA-923 boiler reported data and EPA-approved EF. If EIA923 boiler ozone season data are not available, but EIA-923 annual data are, then the 

value in this field is calculated as 5/12 of the annual value. Otherwise, the value is zero. 

Source: EIA-923 

20. Boiler Unadjusted Annual EPA/CAMD SO2 Emissions (SO2EAN) –

This field, in tons, is the unit’s unadjusted annual SO2 emissions assigned by 

EPA/CAMD and based on the values reported to EPA/CAMD. When not available, it is 

zero. Units that are NBP and not ARP do not report annual SO2 emissions, so the 
THE BLR FILE 

39 

emissions were estimated using fuel quantity (back calculated from reported EPA/CAMD 

heat input and average hear content) and the appropriate EPA-approved emission factor. 

 Source: EPA/CAMD 

21. Boiler Unadjusted Annual EIA-Based Calculated SO2 Emissions (SO2FAN) – 

This field, in tons, is the boiler’s unadjusted annual SO2 emissions calculated using EIA923 boiler reported data, when available, and the EPA-approved EF. When not available, 

it is zero. 

Source: EIA-923 

22. Boiler Unadjusted Annual EPA/CAMD CO2 Emissions (CO2EAN) –

This field, in tons, is the unit’s unadjusted annual CO2 emissions assigned by 

EPA/CAMD based on the values reported to EPA/CAMD. Units that are NBP and not 

ARP do not report annual CO2 emissions, so the emissions were estimated using reported 

EPA/CAMD heat input and the appropriate IPCC GHG carbon coefficient. When not 

available, it is zero. If the fuel for this boiler is biomass, the CO2 emissions are assigned 

a zero value (see the Methodology Section for the rationale for biomass adjustments for 

CO2). 

 Source: EPA/CAMD 

23. Boiler Unadjusted Annual EIA-Based Calculated CO2 Emissions (CO2FAN) – 

This field, in tons, is the boiler’s unadjusted annual CO2 emissions calculated using EIA923 boiler reported data, when available, and IPCC GHG carbon coefficients. When not 

available, it is zero. If the fuel for this boiler is biomass, the CO2 emissions are assigned 

a zero value (see the Methodology Section). 

Source: EIA-923 

24. Source of “Best” Data from EPA/CAMD or EIA-923 Boiler Level (SRCBEST) –

This field describes the one source of the “best” variables (HTIBAN, NOXBAN, 

SO2BAN, CO2BAN, HTIBOZ, NOXBOZ) – either EPA CAMD or EIA-923. 

25. Boiler Unadjusted Annual Best Heat Input (HTIBAN) –

This field, in MMBtu, contains the “best” unadjusted annual heat input value by taking 

HTIEAN as its value, if it exists; otherwise, HTIFAN’s value is used. 

26. Boiler Unadjusted Ozone Season Best Heat Input (HTIBOZ) –

This field, in MMBtu, contains the “best” unadjusted ozone season (May through 

September) heat input value by taking HTIEOZ as its value, if it exists; otherwise, 

HTIFOZ’s value is used. 

27. Boiler Unadjusted Annual Best NOx Emissions (NOXBAN) –

This field, in tons, contains the “best” unadjusted annual NOx value by taking NOXEAN 

as its value, if it exists; otherwise NOXFAN’s value is used. 

28. Boiler Unadjusted Ozone Season Best NOx Emissions (NOXBOZ) –

This field, in tons, contains the “best” unadjusted ozone season (May through September) 

NOx value by taking NOXEOZ as its value, if it exists; otherwise NOXFOZ’s value is 

used. 
THE BLR FILE 

40 

29. Boiler Unadjusted Annual Best SO2 Emissions (SO2BAN) –

This field, in tons, contains the “best” unadjusted annual SO2 value by taking SO2EAN 

as its value, if it exists; otherwise SO2FAN’s value is used. 

30. Boiler Unadjusted Annual Best CO2 Emissions (CO2BAN) –

This field, in tons, contains the “best” unadjusted annual CO2 value by taking CO2EAN 

as its value, if it exists; otherwise CO2FAN’s value is used. 

31. Boiler SO2 (Scrubber) First Control Device (SO2CTLDV) – 

This field contains the first reported SO2 control device. Values may be combined and 

separated by commas. This field is based on the “best” data source display in field #24. 

Possible values are: 

 = blank 

 BR = Jet bubbling reactor 

 CD = Circulating dry scrubber 

 DA = Dual alkali 

 DL FGD = Dry lime flue gas desulfurization unit 

 DP = Dry powder injection type 

 FBL = Fluidized bed 

 MA = Mechanically aided type 

 MO = Magnesium oxide 

 OT = Other 

 PA = Packed type 

 SB = Sodium based 

 SD = Spray dryer type 

 SP = Spray type 

 TR = Tray type 

 VE = Venturi type 

 WL FGD = Wet lime flue gas desulfurization unit 

 WLS = Wet limestone 

 Sources: EPA/CAMD, EIA-860 

 32. Boiler NOx First Control Device (NOXCTLDV) – 

This field contains the first reported NOx control device. Values may be combined and 

separated by commas. This field is based on the “best” data source display in field #24. 

Possible values are: 

 = Blank 

AA = Advanced overfire air 

BF = Biased firing 

CF = Fluidized bed combustor 

CM = Combustion modification/fuel reburning 

DLNB = Dry low NOx premixed technology 

FR = Flue gas recirculation 

FU = Fuel reburning 

H2O = Water injection 

LA = Low excess air 

LNB or LN = Low NOx burner 

LNBO = Low NOx burner with overfire air 

LNC1 = Low NOx burner technology with close-coupled overfire air 

LNC2 = Low NOx burner technology with separated OFA 
THE BLR FILE 

41 

LNC3 = Low NOx burner technology with close-coupled and separated 

 overfire air 

LNCB 

NA 

= Low NOx burner technology for cell burners 

= Not applicable 

NH3 = Ammonia injection 

OFA or OV 

OT 

= Overfire air 

= Other 

SC = Slagging 

SCR or SR = Selective catalytic reduction 

SNCR or SN 

ST or STM 

= Selective noncatalytic reduction 

= Steam injection 

 Sources: EPA/CAMD, EIA-860 

 33. Boiler Hg Activated Carbon Injected System Flag (HGCTLDV) –

This field contains an activated carbon injection mercury control flag (1=Yes), based on 

EIA data. 

Source: EIA-860 

 

34. Boiler Year On-Line (BLRYRONL) –

The field provides the four digit boiler year on-line. This field is based on the “best” data 

source display in field #24. 

 Source: EPA/CAMD, EIA-860 
THE GEN FILE 

42 

B. THE GEN (GENERATOR) FILE 

There are 15 variables in the second file, GEN, which contains generator level data. Note that summing 

the generator generation to the plant level may not result in the same values as the plant generation. This 

file includes generation from steam boilers and nuclear units in the EIA-923 and from those plant-prime 

movers in the EIA-923 that have only one generator in the EIA-860. The one new variable for this data 

year is the first one. 

1. eGRID2012 year 2009 File Generator Sequence Number (SEQGEN09) –

The generator records in this year 2009 data file are sorted by state postal code 

abbreviation, plant name, plant code, and generator ID, and are assigned a unique 

sequential number beginning with 1. This sequence number is unlikely to be the same as 

the sequence number in the year 20075 eGRID file for the same entity. 

2. Plant State Abbreviation (PSTATABB) –

This field contains the two character postal code abbreviation of the state in which the 

plant is located. 

 Source: EIA-860 

3. Plant Name (PNAME) –

This field is the name associated with each plant. 

 Source: EIA-860 + updates 

4. DOE/EIA ORIS Plant or Facility Code (ORISPL) –

This plant code corresponds to PNAME and was originally developed for power plants 

by the Office of the Regulatory Information System (ORIS), which was a part of the 

Federal Power Commission. It is now assigned by EIA and is used as a unique plant 

identification code for many EPA electric power databases, too. One plant code, that for 

Laramie River, has been altered. See Section IV for details. 

 Source: EIA-860 + updates 

5. Generator ID (GENID) –

This field identifies the electrical generation unit (generator). In the majority of cases, 

there is a 1-to-1 correspondence with the boiler ID if it is a steam generator. 

 Sources: EIA-860 

6. Number of Associated Boilers (NUMBLR) –

This field provides the number of EIA-860 boilers associated with each generator in the 

file. 

Sources: EIA-860 

7. Generator Status (GENSTAT) – 

This field indicates the reported generator status at the end of the given year. 

Possible values are: 

BU = Back-up 

OA = Out of service (returned or will be returned to service) 

OP = Operating – in service 

OS = Out of service (not expected to be returned to service) 

RE = Retired – no longer in service 

SB = Stand-by (long-term storage) 
THE GEN FILE 

43 

TS = Testing, construction complete, but not yet in commercial operation 

V = Under constructions, more than 50% constructed 

Generators with one of these above generator status values are considered potentially 

operating generators (including generators with status = ‘RE’, if the retirement date is the 

data year or later). 

 Source: EIA-860 

 8. Generator Prime Mover Type (PRMVR) – 

 This field indicates the reported generator’s electric generator type. 

Possible values are: 

BT = Binary cycle turbine 

CA = Combined cycle steam turbine 

CC = Combined cycle - total unit 

CE = Compressed air energy storage 

CS = Combined cycle - single shaft 

CT = Combined cycle combustion turbine 

FC = Fuel cell 

GT = Combustion (gas) turbine 

HY = Hydraulic turbine 

IC 

IG 

= Internal combustion (diesel) 

= Integrated gasification combustion turbine 

OT = Other turbine 

PS = Hydraulic turbine - reversible (pumped storage) 

PV = Photovoltaic 

ST = Steam turbine (boiler, nuclear, geothermal, and solar steam) 

WT = Wind turbine 

 Source: EIA-860 

9. Generator Primary Fuel (FUELG1) – 

This field indicates the potential primary fuel reported for the generator. 

Possible values are: 

AB = Agricultural byproduct 

BFG = Blast furnace gas 

BIT = Bituminous coal 

BLQ = Black liquor 

DFO = Distillate fuel oil, light fuel oil, FO2, diesel oil 

DG = Digester gas (other biomass gas) 

GEO = Geothermal 

JF = Jet fuel 

KER = Kerosene 

LFG = Landfill gas 

LIG = Lignite coal 

MSB = Municipal solid waste biomass component 

NG = Natural gas 

NUC = Nuclear materiel 

OBL = Other biomass liquid 

OBS = Other biomass solid 

OG = Other gas 

OTH = Other unknown 

PC = Petroleum coke 

PUR = Purchased steam 
THE GEN FILE 

44 

RFO = Residual fuel oil, heavy fuel oil, petroleum 

SC = Synthetic coal (syncoal) 

SUB = Subbituminous coal 

SUN = Solar 

TDF = Tire-derived fuel 

WAT = Water 

WC = Waste coal 

WDL = Wood, Wood waste liquid 

WDS = Wood, Wood waste solid 

WH = Waste heat 

WND = Wind 

WO = Waste oil 

 Source: EIA-860 

10. Generator Nameplate Capacity (NAMEPCAP) –

This field indicates the nameplate capacity, in MW, of the generator. 

 Source: EIA-860 

11. Generator Capacity Factor (CFACT) –

This field is calculated at the generator level: 

CFACT = (GENNTAN) / (NAMEPCAP * 8760). 

The value should be between 0 and 1 exclusive. However, there are outliers. 

12. Generator Annual Net Generation (GENNTAN) –

This field is the reported net generation in MWh. Note that summing the net generation 

of the generators in a plant may not provide a value that is the same as the plant 

generation value, PLNGENAN, since the data sources are often different. 

 Sources: EIA-923 

13. Generator Ozone Season Net Generation (GENNTOZ) –

This field is the generator five month ozone season (May through September) net 

generation in MWh. For plants that reported monthly data, it is based on monthly 

generator generation data. Otherwise, it is calculated as 5/12 of the annual value. 

 Sources: EIA-923 

14. Generation Data Source (GENERSRC) – 

This field describes the data source of the generator net generation data. The values are 

as follows: 

F860 = EIA-860 generator level, 

F923NK = EIA-923 nuclear unit 

F923NONK = EIA-923 only generator at that plant’s prime mover 

F923ST = EIA-923 ST unit 

 15. Generator Year On-Line (GENYRONL) –

This field provides the four digit generator year on-line. 

 Source: EIA-860 
THE PLNT FILE 

45 

C. THE PLNT (PLANT) FILE 

There are 164 variables in PLNT. Some data may be outliers and should be viewed with caution. 

1. eGRID2012 year 2009 File Plant Sequence Number (SEQPLT09) –

The plant records in this year 2009 data file are sorted by state postal code abbreviation, 

plant name, and boiler ID, and are assigned a unique sequential number beginning with 1. 

This sequence number is unlikely to be the same as the sequence number in the year 2007 

eGRID2010 file for the same entity. 

This is a new field in eGRID2012. 

2. Plant State Abbreviation (PSTATABB) –

This field contains the two character postal code abbreviation of the state in which the 

plant is located. 

 Source: EIA-860 

3. Plant Name (PNAME) –

 This field is the name associated with each plant. 

 Source: EIA-860 + updates 

4. DOE/EIA ORIS Plant or Facility Code (ORISPL) –

This plant code corresponds to PNAME and was originally developed for power plants 

by the Office of the Regulatory Information System (ORIS), which was a part of the 

Federal Power Commission. It is now assigned by EIA and is used as a unique plant 

identification code for many EPA electric power databases, too. One plant code, that for 

Laramie River, has been altered. See Section IV for details. 

 Source: EIA-860 + updates 

5. Plant EPA Facility Registry System FRS Identification Code (FRSID) – 

This field is the EPA Facility Registry System (FRS) code associated with the ORISPL. 

This field is blank for year 2009 data because of data inconsistencies. 

 Source: EPA FRS 

6. Plant Operator Name (OPRNAME) –

The name associated with each operating company (EGC) is contained in this field. 

 Source: EIA-860 

7. Plant Operator ID (OPRCODE) –

This field contains the operating company ID. Each operating company has a unique 

company code assigned by EIA, with some exceptions. Some operator names do not 

have associated codes assigned by EIA and are EPA-assigned. See Section IV for details. 

 Source: EIA-860 

8. Utility Service Territory Name (UTLSRVNM) –

This field contains the name of the owner of the transmission/distribution company/EGC, 

also known as the utility service territory (a utility company or EGC) [and previously 

known as the utility service area] in which the plant is located. See Section IV for further 

details. 

 Source: EIA-860 + updates 
THE PLNT FILE 

46 

9. Utility Service Territory ID (UTLSRVID) –

This field contains the unique ID code associated with the utility service territory name. 

 Source: EIA-860 + updates 

10. ID of the Operator’s Parent Company (OPPRNUM) –

This field contains the ID of the plant’s operator’s parent company, if it exists. It is zero 

otherwise. EIA did not assign IDs for most parent companies; thus, EPA assigned unique 

negative integer IDs beginning with -7001 as parent company IDs. It is zero for year 

2009 data. 

11. Name of the Operator’s Parent Company (OPPRNAME) –

This field contains the name of the plant’s operator’s parent company, if it exists. It is 

blank otherwise. It is blank for year 2009 data. 

12. Power Control Area Name (PCANAME) –

This field contains the name of the power control area for the plant. The PCA is 

associated with the plant’s eGRID subregion and NERC region. See the Methodology 

Section for further information about PCAs. 

 Sources: NERC, EIA-861 + updates 

13. Power Control Area ID (PCAID) –

This field contains the ID of the power control area for the plant. See the Methodology 

Section for further information about PCAs. 

Sources: NERC, EIA-861 + updates 

14. NERC Region Acronym (NERC) –

This field contains the acronym for the NERC region in which the plant is located. The 

NERC region is associated with the plant’s PCA and eGRID subregion. See the 

Methodology Section for further information about NERC regions. A representation of 

the eGRID2012 NERC region map is included in Appendix B. 

 Source: NERC 

 

 15. eGRID Subregion Acronym (SUBRGN) –

This field contains the acronym for the eGRID subregion in which the plant is located. 

The eGRID subregion is associated with the plant’s PCA and NERC region. See the 

Methodology Section for further information about eGRID subregions. A representation 

of the eGRID2012 eGRID subregion map is included in Appendix B. 

 Source: EPA 

16. eGRID Subregion Name (SRNAME) –

This field contains the name of the eGRID subregion in which the plant is located. See 

the Methodology Section for further information about eGRID subregions. 

 Source: EPA 

17. Plant associated ISO/RTO Territory (ISORTO) –

 This field contains the name, if applicable, of the Independent System Operator (ISO) or 

 Regional Transmission Organization (RTO) associated with the plant. 

 Possible values are CAISO, ERCOT, ISONE, MISO, NYISO, PJM, SPP, OTHER, or 

 blank. 

This is a new field in eGRID2012. 

 Source: EIA-860 (2010) + updates 
THE PLNT FILE 

47 

18. Plant FIPS State Code (FIPSST) –

This field contains the two digit Federal Information Processing Standards (FIPS) state 

character code of the state in which the plant is located. The codes are from the National 

Institute of Standards and technology (NIST, undated). 

 Source: NIST based 

19. Plant FIPS County Code (FIPSCNTY) –

This field contains the three digit FIPS county character code of the county in which the 

plant is located. The codes are from the National Institute of Standards and technology 

(NIST, undated). 

 Source: NIST based 

20. Plant County Name (CNTYNAME) –

This field corresponds to FIPSST and contains the name of the county in which the plant 

is located. 

 Source: EIA-860, EPA/CAMD 

21. Plant Latitude (LAT) –

This field contains the latitude, in degrees to four decimal places, associated with the 

plant. When not available, the plant’s county centroid’s y-coordinate is used. 

 Source: EPA/CAMD, EIA + updates 

22. Plant Longitude (LON) –

This field contains the longitude, in degrees to four decimal places, associated with the 

plant. When not available, the plant’s county centroid’s x-coordinate is used. 

 Source: EPA/CAMD, EIA + updates 

23. Country Centroid flag (CCFLAG) – 

This field indicates if the plant’s latitude and longitude (fields # 20 and # 21) are based 

on the county centroid (1= county centroid used). 

 

24. Number of Boilers (NUMBLR) –

This field contains the number of operating boilers or turbines within a plant. Note that 

the meaning and sources of these data are different from the data element of the same 

name in the generator file. 

 Source: EPA/CAMD, EIA-860 calculated 

25. Number of Generators (NUMGEN) –

This field contains the number of potentially operating generators within a plant. Note 

that the meaning and source of these data are different from the data element of the same 

name in the boiler file. 

 Source: EIA-860 calculated 

 26. Plant combustion status (COMBUST) –

This field contains the plant combustion status: Possible values are: 1= Combusts, 

0 = No combustion, 0.5 = Partial combustion. 

27. Plant Emissions Source(s) (SOURCEM) – 

This field describes the source(s) of emissions data for the plant. Values may be 

combined and separated by commas. 
THE PLNT FILE 

48 

Possible values are: 

EPA CAMD = NOx, SO2, and CO2 emissions reported to EPA's Emissions tracking

 System/Continuous Emissions Monitoring System (EPA/CAMD) if 

 in the ARP program; otherwise estimated by applying EPA- 

 approved EF to EPA/CAMD data for year 2009. 

 CH4 and N2O emission estimated by applying EPA-approved 

 EF to EPA/CAMD data for year 2009. 

EIA-923 

EIA-906 

= NOx, SO2, CO2, CH4, and N2O emissions estimated by applying 

 EPA-approved EF to EIA-923 boiler-level data for 

 year 2009. 

= NOx, SO2, CO2, CH4, and N2O emissions estimated by applying 

 EPA-approved EF to EIA-923 plant-prime mover-level data for 

 year 2009. 

28. Plant Primary Fuel (PLPRMFL) – 

This field contains the plant’s primary fuel based on maximum heat input if the plant 

combusts any fuel or assignment if the plant does not combust any fuel. Possible values 

are: 

AB = Agricultural byproduct 

BFG 

BG 

= Blast furnace gas 

= Bagasse 

BIT = Bituminous coal 

BLQ = Black liquor 

COG = Coke oven gas 

DFO = Distillate fuel oil, light fuel oil, FO2, diesel oil 

DG = Digester gas (other biomass gas) 

GEO = Geothermal steam 

HY = Hydrogen 

JF = Jet fuel 

KER = Kerosene 

LFG = Landfill gas 

LIG = Lignite coal 

MSB = Municipal solid waste biomass component 

NG = Natural gas 

NUC = Nuclear materiel 

OBL = Other biomass liquid 

OBS = Other biomass solid 

OG = Other gas 

OO = Other oil check that it is not OOL 

OTH 

OTL 

= Other (unknown) 

= Other liquid 

PC = Petroleum coke 

PG = Propane gas/LPG 

PP = Paper pellets 

PRG = Process gas 

PUR = Purchased fuel (unknown) 

RFO = Residual fuel oil, heavy fuel oil, petroleum 

RG = Refinery gas 

SC = Synthetic coal (syncoal) 

SLW = Sludge waste 
THE PLNT FILE 

49 

SUB = Subbituminous coal 

SUN = Sun 

TDF = Tire-derived fuel 

WAT = Water 

WC = Waste coal 

WDL = Wood, wood waste liquid 

WDS = Wood, wood waste solid 

WND = Wind 

WO = Waste oil 

29. Plant Primary Coal/Oil/Gas/Other Fossil Fuel Category (PLFUELCT) –

The value of this field is “COAL” if PLPRMFL is derived from coal, “OIL” if it is 

derived from oil, “GAS” if it is derived from gas, or “OFSL” if it is other fossil. Fossil 

fuel refers to any naturally occurring organic fuel, such as petroleum, coal, and natural 

gas. See the Methodology Section for a complete list of fuel codes and categories. 

 30. Plant Primary Fuel Generation Category (PLPFGNCT) –

This field contains the plant’s primary fuel based on maximum net generation if the plant 

generates. Possible values are based on the 11 that are used for resource mix: COAL, 

OIL, GAS, NUCLEAR, HYDRO, BIOMASS, WIND, SOLAR, GEOTHERMAL, 

OTHRFOSL, and WSTHTOTPUR (Other Unknown/Purchased/Waste Heat). 

 31. Flag indicating if the plant burned or generated any amount of coal 

 (COALFLAG) –

This field contains a flag to indicate if the plant burned or, if it has positive heat input and 

generated electricity from coal (1= Yes). If a plant has negative coal generation and no 

coal heat input for a given year, the coal flag does not have the value of 1; this condition 

is new for year 2009 data. 

 32. Plant Capacity Factor (CAPFAC) –

This field contains the plant capacity factor, expressed with four decimal places. It is 

calculated as follows: 

 CAPFAC = (PLNGENAN / (NAMEPCAP * 8760)) 

Although the value should be between 0 and 1 inclusive, there are outliers. 

33. Plant Nameplate Capacity (NAMEPCAP) –

This field contains the nameplate capacity of the plant, in MW. 

 Source: EIA-860 summed 

34. Biogas/Biomass Plant Adjustment Flag (RMBMFLAG) –

This field contains the biogas (landfill gas, digester gas)/biomass adjustment flag. A 

biomass facility’s emissions reported in eGRID may be different from that reported in 

other EPA sources such as EPA/CAMD’s emissions data. 

Possible values are: 

 0 = No biomass 

 1 = Biogas included 

 100 = Other biomass included 

 71 = Biogas adjustments for CAMD emissions 

 7100 = Biomass adjustment for CAMD CO2

For details, see the Methodology Section. 
THE PLNT FILE 

50 

 

35. Combined Heat and Power (CHP) Plant Adjustment Flag (CHPFLAG) –

This field contains a flag to indicate if the plant is a CHP facility (1=Yes). A CHP 

facility’s emissions and heat input reported in eGRID may be different from that reported 

in other EPA sources such as EPA/CAMD’s emissions data. For details, see the 

Methodology Section. 

Source: eGRID CHP list 

36. CHP Plant Useful Thermal Output (USETHRMO) –

This field, in MMBtu, contains the useful thermal output estimated for a CHP facility. 

Source: EIA-923 calculated 

37. CHP Plant Power to Heat Ratio (PWRTOHT) –

This field contains the power to heat ratio for a CHP facility, which is the ratio of the heat 

value of electricity generated (3413 * kWh output) to the facility’s useful thermal output. 

There are outliers. 

38. CHP Plant Electric Allocation Factor (ELCALLOC) –

This field contains the CHP plant’s decimal fraction of the emissions that is attributed to 

electricity. It is derived as the ratio of the electric heat output to the sum of the electric 

and steam heat outputs, where the steam output is 75% of the useful thermal output. The 

electric allocation factor is used to allocate emissions from a CHP facility to both 

electricity generation and useful thermal output. For non-CHP plants, eGRID uses an 

electric allocation factor of 1.0. See the Methodology Section for further information. 

39. Plant Pumped Storage Flag (PSFLAG) –

This field indicates if the plant has at least one pumped storage generator (1= Yes). 

 Source: EIA-860 

40. Plant Annual Heat Input (PLHTIAN) –

This field is the total annual heat input, in MMBtu, for the plant. For CHP plants, the 

value is adjusted by the electric allocation factor. See the Methodology Section for 

details. 

41. Plant Ozone Season Heat Input (PLHTIOZ) –

This field is the five month ozone season (May through September) heat input, in MWh, 

for the plant. For CHP plants, the value is adjusted by the electric allocation factor. See 

the Methodology Section for details. 

42. Plant Annual Net Generation (PLNGENAN) –

This field is the total reported annual net generation, in MWh, for the plant. 

 Sources: EIA-923, EPA/CAMD calculated 

43. Plant Ozone Season Net Generation (PLNGENOZ) –

This field, in MWh, is the five month ozone season (May through September) net 

generation for the plant. 

 Sources: EIA-923, EPA/CAMD calculated 
THE PLNT FILE 

51 

44. Plant Annual NOx Emissions (PLNOXAN) –

This field, in tons, is the total annual NOx emissions for the plant. Biogas components 

are adjusted. For CHP plants, the value is adjusted by the electric allocation factor. See 

the Methodology Section for details. 

This adjusted emissions field is estimated by first making the biogas adjustment (if it 

exists) and then applying the electric allocation factor (if the plant is a CHP). See the 

Methodology Section for details. 

 

45. Plant Ozone Season NOx Emissions (PLNOXOZ) –

This field, in tons, is the five month ozone season (May through September) NOx

emissions for the plant. Biogas components are adjusted. For CHP plants, the value is 

adjusted by the electric allocation factor. See the Methodology Section for details. 

This adjusted emissions field is estimated by first making the biogas adjustment (if it 

exists) and then applying the electric allocation factor (if the plant is a CHP). See the 

Methodology Section for details. 

46. Plant Annual SO2 Emissions (PLSO2AN) –

This field, in tons, is the total annual SO2 emissions for the plant. Biogas components are 

adjusted. For CHP plants, the value is adjusted by the electric allocation factor. See the 

Methodology Section for details. 

This adjusted emissions field is estimated by first making the biogas adjustment (if it 

exists) and then applying the electric allocation factor (if the plant is a CHP). See the 

Methodology Section for details. 

47. Plant Annual CO2 Emissions (PLCO2AN) –

This field, in tons, is the total annual CO2 emissions for the plant. All estimated CO2

emissions from biomass fuels are adjusted to zero. The biomass fuel components’ CO2

CAMD emissions are excluded (adjusted to zero) by the same biomass fuel component 

percentage as that in the EIA-923 for the adjusted CO2 CAMD emissions; prior to year 

2007, these emissions, if CAMD-reported, were only zeroed out if the primary fuel was a 

biomass fuel. For CHP plants, the value is adjusted by the electric allocation factor. 

This adjusted emissions field is estimated by first making the biomass adjustment (if it 

exists) and then applying the electric allocation factor (if the plant is a CHP). See the 

Methodology Section for details. 

 48. Plant Annual CH4 Emissions (PLCH4AN) –

This field, in lbs, is the total annual CH4 emissions for the plant. Biogas biomass 

components are adjusted. For CHP plants, the value is adjusted by the electric allocation 

factor. See the Methodology Section for details. 

This adjusted emissions field is estimated by first making the biomass adjustment (if it 

exists) and then applying the electric allocation factor (if the plant is a CHP). See the 

Methodology Section for details. 
THE PLNT FILE 

52 

 49. Plant Annual N2O Emissions (PLN2OAN) –

This field, in lbs, is the total annual N2O emissions for the plant. Biogas biomass 

components are adjusted. For CHP plants, the value is adjusted by the electric allocation 

factor. See the Methodology Section for details. 

This adjusted emissions field is estimated by first making the biomass adjustment (if it 

exists) and then applying the electric allocation factor (if the plant is a CHP). See the 

Methodology Section for details. 

 50. Plant Annual CO2 Equivalent Emissions (PLCO2EQA) –

This field, in U.S. tons, is the annual CO2 equivalent emissions for the plant. This value 

is a universal standard of measurement. The GWPs from the second IPCC assessment 

are used per EPA for the calculation; the formula used is as follows: 

PLCO2EQA = ((1* PLCO2AN) + (21* PLCH4AN / 2000) + (310 * PLN2OAN / 2000)). 

This value can be converted to metric tonnes by dividing by 1.1023. See the 

Methodology Section for details. 

51. Plant Annual Hg Emissions (PLHGAN) –

This field, in lbs, is the total annual Hg emissions for the plant. For CHP plants, the 

value is adjusted by the electric allocation factor. See the Methodology Section for 

details. 

52. Plant Annual NOx Total Output Emission Rate (PLNOXRTA) –

This field, in lb/MWh, is calculated as follows: 

PLNOXRTA = 2000 * (PLNOXAN / PLNGENAN). 

53. Plant Ozone Season NOx Total Output Emission Rate (PLNOXRTO) –

This field, in lb/MWh, is calculated as follows: 

PLNOXRTO = 2000 * (PLNOXOZ / PLNGENOZ). 

54. Plant Annual SO2 Total Output Emission Rate (PLSO2RTA) –

This field, in lb/MWh, is calculated as follows: 

PLSO2RTA = 2000 * (PLSO2AN / PLNGENAN). 

55. Plant Annual CO2 Total Output Emission Rate (PLCO2RTA) –

This field, in lb/MWh, is calculated as follows: 

PLCO2RTA = 2000 * (PLCO2AN / PLNGENAN). 

 56. Plant Annual CH4 Total Output Emission Rate (PLCH4RTA) –

This field, in lb/GWh, is calculated as follows: 

 PLCH4RTA = PLCH4AN / (PLNGENAN / 1000). 

 

 57. Plant Annual N2O Total Output Emission Rate (PLN2ORTA) –

This field, in lb/GWh, is calculated as follows: 

PLN2ORTA = PLN2OAN / (PLNGENAN / 1000). 

 

 58. Plant Annual CO2 Equivalent Total Output Emission Rate (PLC2ERTA) –

This field, in lb/MWh, is calculated as follows: 

PLC2ERTA = 2000 * (PLCO2EQA / PLNGENAN). 
THE PLNT FILE 

53 

 

59. Plant Annual Hg Total Output Emission Rate (PLHGRTA) –

This field, in lb/GWh, is calculated as follows: 

 PLHGRTA = PLHGAN / (PLNGENAN / 1000). 

60. Plant Annual NOx Input Emission Rate (PLNOXRA) –

This field, in lb/MMBtu, is calculated as follows: 

PLNOXRA = 2000 * (PLNOXAN / PLHTIAN). 

61. Plant Ozone Season NOx Input Emission Rate (PLNOXRO) –

This field, in lb/MMBtu, is calculated as follows: 

PLNOXRO = 2000 * (PLNOXOZ / PLHTIOZ). 

62. Plant Annual SO2 Input Emission Rate (PLSO2RA) –

This field, in lb/MMBtu, is calculated as follows: 

PLSO2RA = 2000 * (PLSO2AN / PLHTIAN). 

63. Plant Annual CO2 Input Emission Rate (PLCO2RA) –

This field, in lb/MMBtu, is calculated as follows: 

PLCO2RA = (2000 * (PLCO2AN / PLHTIAN). 

64. Plant Annual Hg Input Emission Rate (PLHGRA) – 

This field, in lb/BBtu, is calculated as follows: 

 PLHGRA = PLHGAN / (PLHTIAN / 1000). 

 65. Plant Annual NOx Combustion Output Emission Rate (PLNOXCRT) –

This field, in lb/MWh, is calculated as follows: 

PLNOXCRT = 2000 * (PLNOXAN / PLGENACY). 

66. Plant Ozone Season NOx Combustion Output Emission Rate 

 (PLNOXCRO) –

This field, in lb/MWh, is calculated as follows: 

PLNOXCRO = 2000 * (PLNOXOZ / ((PLGENACY * PLNGENOZ) / PLNGENAN)). 

67. Plant Annual SO2 Combustion Output Emission Rate (PLSO2CRT) –

This field, in lb/MWh, is calculated as follows: 

PLSO2CRT = 2000 * (PLSO2AN / PLGENACY). 

68. Plant Annual CO2 Combustion Output Emission Rate (PLCO2CRT) –

This field, in lb/MWh, is calculated as follows: 

PLCO2CRT = 2000 * (PLCO2AN / PLGENACY). 

69. Plant Annual CH4 Combustion Output Emission Rate (PLCH4CRT) – 

This field, in lb/GWh, is calculated as follows: 

 PLCH4CRT = PLCH4AN / (PLGENACY / 1000). 

 

 70. Plant Annual N2O Combustion Output Emission Rate (PLN2OCRT) – 

This field, in lb/GWh, is calculated as follows: 

 PLN2OCRT = PLN2OAN / (PLGENACY / 1000). 

 
THE PLNT FILE 

54 

 71. Plant Annual Hg Combustion Output Emission Rate (PLHGCRT) – 

This field, in lb/GWh, is calculated as follows: 

 PLHGCRT = PLHGAN / (PLGENACY / 1000). 

 

 72. Plant Unadjusted Annual NOx Emissions (UNNOX) –

This field, in tons, is the total plant level unadjusted annual NOx emissions. See the 

Methodology Section for details. 

73. Plant Unadjusted Ozone Season NOx Emissions (UNNOXOZ) –

This field, in tons, is the unadjusted five month ozone season (May through September) 

NOx emissions for the plant. See the Methodology Section for details. 

74. Plant Unadjusted Annual SO2 Emissions (UNSO2) –

This field, in tons, is the total plant level unadjusted annual SO2 emissions. See the 

Methodology Section for details. 

75. Plant Unadjusted Annual CO2 Emissions (UNCO2) –

This field, in tons, is the total plant level unadjusted annual CO2 emissions. Beginning in 

year 2007, the biomass fuel components’ CO2 emissions will be included in the 

unadjusted CO2 plant emissions. See the Methodology Section for details. 

 76. Plant Unadjusted Annual CH4 Emissions (UNCH4) –

This field, in lbs, is the total plant level unadjusted annual CH4 emissions. See the 

Methodology Section for details. 

 77. Plant Unadjusted Annual N2O Emissions (UNN2O) –

This field, in lbs, is the total plant level unadjusted annual N2O emissions. See the 

Methodology Section for details. 

78. Plant Unadjusted Annual Hg Emissions (UNHG) –

This field, in lbs, is the total plant level unadjusted annual Hg emissions. Mercury 

emissions are reported for year 2002 for coal plants and for year 2000 for large municipal 

waste combustors, and for eGRID, are estimated for year 2005. See the Methodology 

Section for details. 

79. Plant Unadjusted Annual Heat Input (UNHTI) –

This field, in MMBtu, is the total plant level unadjusted annual heat input. See the 

Methodology Section for details. 

 Sources: EPA/CAMD, EIA-923 

80. Plant Unadjusted Ozone Season Heat Input (UNHTIOZ) –

This field, in MMBtu, is the five month ozone season (May through September) heat 

input for the plant. See the Methodology Section for details. 

 Sources: EPA/CAMD, EIA-923 

81. Plant Nominal Heat Rate (PLHTRT) –

This field, in Btu/kWh, contains the plant nominal heat rate for at least partially 

combusted plants. It is calculated as follows: 

 PLHTRT = 1000 * (PLHTIAN / PLNGENAN) for combustion plants; and 

 PLHTRT = 1000 * (PLHTIAN / PLGENACY) for partial combustion plants. 
THE PLNT FILE 

55 

For CHP plants, the value is, in effect, adjusted by the electric allocation factor, since the 

heat input has been adjusted. 

This field’s definition has been modified for eGRID2012. 

82. Plant Annual Coal Net Generation (PLGENACL) –

This field, in MWh, contains the plant annual net generation for coal. Fuel codes that are 

included in coal are BIT, SUB, LIG, WC, and SC. 

83. Plant Annual Oil Net Generation (PLGENAOL) –

This field, in MWh, contains the plant annual net generation for oil. Fuel codes included 

in oil are DFO, JF, KER, OO, PC, RFO, RG, and WO. 

84. Plant Annual Gas Net Generation (PLGENAGS) –

This field, in MWh, contains the plant annual net generation for natural gas. Fuel codes 

included in gas are NG and PG. 

 

85. Plant Annual Nuclear Net Generation (PLGENANC) –

This field, in MWh, contains the plant annual net generation for nuclear if the fuel code is 

NUC. Note that one plant, North Anna, has both nuclear and hydro prime movers, but 

the greater generation is associated with nuclear 

 

86. Plant Annual Hydro Net Generation (PLGENAHY) –

This field, in MWh, contains the plant annual net generation for hydro if the fuel code is 

WAT. 

 

87. Plant Annual Biomass Net Generation (PLGENABM) –

This field, in MWh, contains the plant annual net generation for biomass. Biomass is a 

fuel derived from organic matter such as wood and paper products, agricultural waste, or 

methane (e.g., from landfills). The renewable portion of solid waste, fuel code MSB, is 

included as biomass, as are AB, BLQ, DG, LFG, ME, OBL, OBS, PP, SLW, WDL, and 

WDS. See the Methodology Section for more information. 

88. Plant Annual Wind Net Generation (PLGENAWI) –

This field, in MWh, contains the plant annual net generation for wind if the fuel code is 

WND. 

 

89. Plant Annual Solar Net Generation (PLGENASO) –

This field, in MWh, contains the plant annual net generation for solar if the fuel code is 

SUN. 

90. Plant Annual Geothermal Net Generation (PLGENAGT) – 

 This field, in MWh, contains the plant annual net generation for geothermal if the fuel 

code is GEO. 

91. Plant Annual Other Fossil Net Generation (PLGENAOF) –

This field, in MWh, contains the plant annual net generation for other fossil fuel that 

cannot be categorized as coal, oil, or gas. Other fossil fuel codes include BFG, COG, 

HY, LB, MH, MSF, OG, PRG, and TDF. 
THE PLNT FILE 

56 

92. Plant Annual Other Unknown/ Purchased Fuel Net Generation (PLGENAOP) –

This field, in MWh, contains the plant annual net generation for other 

unknown/purchased if the fuel code is OTH or PUR or WH. 

93. Plant Annual Total Nonrenewables Net Generation (PLGENATN) –

This field, in MWh, contains the annual total nonrenewables net generation for the plant. 

Nonrenewables are exhaustible energy resources such as coal, oil, gas, other fossil, 

nuclear power, and other unknown/purchased fuel. This field is the sum of PLGENACL, 

PLGENAOL, PLGENAGS, PLGENAOF, PLGENANC, and PLGENAOP. 

94. Plant Annual Total Renewables Net Generation (PLGENATR) –

This field, in MWh, contains the annual total renewables net generation for the plant. 

Renewables are inexhaustible energy resources such as biomass, wind, solar, geothermal, 

and hydro. This field is the sum of PLGENABM, PLGENAWI, PLGENASO, 

PLGENAGT, and PLGENAHY. 

95. Plant Annual Total Nonhydro Renewables Net Generation (PLGENATH) –

This field, in MWh, contains the annual total nonhydro renewables net generation for the 

plant. This field is the sum of PLGENABM, PLGENAWI, PLGENASO, and 

PLGENAGT. 

 96. Plant Annual Total Combustion Net Generation (PLGENACY) –

This field, in MWh, contains the annual total combustion net generation for the plant. 

This field is the sum of PLGENACL, PLGENAOL, PLGENAGS, PLGENAOF, 

PLGENABM, and PLGENAOP. 

 

 97. Plant Annual Total Noncombustion Net Generation (PLGENACN) –

 This field, in MWh, contains the annual total noncombustion net generation for the plant. 

This field is the sum of PLGENANC, PLGENAHY, PLGENAWI, PLGENASO, and 

PLGENAGT. 

 98. Plant Coal Generation Percent (PLCLPR) – 

This field, the coal resource mix expressed as a percent of plant annual net generation, is 

calculated as follows: 

PLCLPR = 100 * (PLGENACL / PLNGENAN). 

99. Plant Oil Generation Percent (PLOLPR) – 

This field, the oil resource mix expressed as a percent of plant annual net generation, is 

calculated as follows: 

PLOLPR = 100 * (PLGENAOL / PLNGENAN). 

100. Plant Gas Generation Percent (PLGSPR) – 

This field, the gas resource mix expressed as a percent of plant annual net generation, is 

calculated as follows: 

PLGSPR = 100 * (PLGENAGS / PLNGENAN). 

101. Plant Nuclear Generation Percent (PLNCPR) – 

This field, the nuclear resource mix expressed as a percent of plant annual net generation, 

is calculated as follows: 

PLNCPR = 100 * (PLGENANC / PLNGENAN). 
THE PLNT FILE 

57 

102. Plant Hydro Generation Percent (PLHYPR) –

This field, the hydro resource mix expressed as a percent of plant annual net generation, 

is calculated as follows: 

PLHYPR = 100 * (PLGENAHY / PLNGENAN). 

103. Plant Biomass Generation Percent (PLBMPR) –

This field, the biomass resource mix expressed as a percent of plant annual net 

generation, is calculated as follows: 

PLBMPR = 100 * (PLGENABM / PLNGENAN). 

104. Plant Wind Generation Percent (PLWIPR) – 

This field, the wind resource mix expressed as a percent of plant annual net generation, is 

calculated as follows: 

PLWIPR = 100 * (PLGENAWI / PLNGENAN). 

105. Plant Solar Generation Percent (PLSOPR) – 

This field, the solar resource mix expressed as a percent of plant annual net generation, is 

calculated as follows: 

PLSOPR = 100 * (PLGENASO / PLNGENAN). 

106. Plant Geothermal Generation Percent (PLGTPR) –

This field, the geothermal resource mix expressed as a percent of plant annual net 

generation, is calculated as follows: 

PLGTPR = 100 * (PLGENAGT / PLNGENAN). 

107. Plant Other Fossil Generation Percent (PLOFPR) –

This field, the other fossil resource mix expressed as a percent of plant annual net 

generation, is calculated as follows: 

 PLOFPR = 100 * (PLGENAOF / PLNGENAN). 

108. Plant Other Unknown/Purchased Fuel Generation Percent (PLOPPR) –

This field, the other unknown/purchased fuel/waste heat resource mix expressed as a 

percent of plant annual net generation, is calculated as follows: 

PLOPPR = 100 * (PLGENAOP / PLNGENAN). 

109. Plant Total Nonrenewables Generation Percent (PLTNPR) –

This field, the total nonrenewables resource mix expressed as a percent of plant annual 

net generation, is calculated as follows: 

 PLTNPR = 100 * (PLGENATN / PLNGENAN). 

110. Plant Total Renewables Generation Percent (PLTRPR) –

This field, the total renewables resource mix expressed as a percent of plant annual net 

generation, is calculated as follows: 

 PLTRPR = 100 * (PLGENATR / PLNGENAN). 

 111. Plant Total Nonhydro Renewables Generation Percent (PLTHPR) –

This field, the total nonhydro renewables resource mix expressed as a percent of plant 

annual net generation, is calculated as follows: 

 PLTHPR = 100 * (PLGENATH / PLNGENAN). 
THE PLNT FILE 

58 

 112. Plant Total Combustion Generation Percent (PLCYPR) –

This field, the total combustion resource mix expressed as a percent of plant annual net 

generation, is calculated as follows: 

 PLCYPR = 100 * (PLGENACY / PLNGENAN). 

 

 113. Plant Total Noncombustion Generation Percent (PLCNPR) –

This field, the total noncombustion resource mix expressed as a percent of plant annual 

net generation, is calculated as follows: 

 PLCNPR = 100 * (PLGENACN / PLNGENAN). 

 

 114. Plant Owner Name (First) (OWNRNM01) –

This field contains the name of the first plant owner, a company or EGC. 

 Sources: EIA-860 

 115. Plant Owner Code (First) (OWNRUC01) –

This field contains the unique company code associated with OWNRNM01 and assigned 

by EIA, with some exceptions. Some owner names do not have associated codes 

assigned by EIA and are EPA-assigned. If no information on ownership is provided, then 

it is assumed that the operator has 100% ownership. See the Methodology Section and 

Section IV for details. 

 Source: EIA-860 

116. Plant Owner Percent (First) (OWNRPR01) –

This field contains the percent of the plant that is owned by OWNRNM01. It is 

calculated based on reported generator ownership data. If no information on ownership is 

provided, then it is assumed that the operator has 100% ownership. See the 

Methodology Section and Section IV for details. 

Source: EIA-860 

 117. Plant Owner Name (Second) (OWNRNM02) –

This field contains the name of the second plant owner. 

 Source: EIA-860 

 118. Plant Owner Code (Second) (OWNRUC02) –

This field contains the unique EIA-assigned number associated with OWNRNM02. 

Some owner names do not have associated codes assigned by EIA and are EPA-assigned. 

If no information on ownership is provided, then it is assumed that the operator has 100% 

ownership. 

See the Methodology Section and Section IV for details. 

Source: EIA-860 

 119. Plant Owner Percent (Second) (OWNRPR02) –

This field contains the percent of the plant that is owned by OWNRNM02. It is 

calculated based on reported generator ownership data. 

Some owner names do not have associated codes assigned by EIA and are EPA-assigned. 

If no information on ownership is provided, then it is assumed that the operator has 100% 

ownership. 

See the Methodology Section and Section IV for details. 

Source: EIA-860. 
THE PLNT FILE 

59 

 120. – Plant Owner Name, Plant Owner Code, and Plant Owner Percent (Third - 

 161. Sixteenth) –

The description of these fields contains the information for the third through sixteenth 

plant owners. See the descriptions in fields #113 through #115 above. 

 Source: EIA-860 

 162. eGRID2006 year 2004 File Plant Sequence Number (SEQPLT04) –

This field contains the sequence number of the plant in the year 2004 data, if one exists. 

This sequence number is unlikely to be the same as the sequence number in the year 2005 

eGRID2007 file for the same plant. 

 163. eGRID2007 year 2005 File Plant Sequence Number (SEQPLT05) –

This field contains the sequence number of the plant in the year 2005 data, if one exists. 

This sequence number is unlikely to be the same as the sequence number in the year 2007 

eGRID2010 file for the same plant. 

 164. eGRID2010 year 2005 File Plant Sequence Number (SEQPLT05) –

This field contains the sequence number of the plant in the year 2007 data, if one exists. 

This sequence number is unlikely to be the same as the sequence number in the year 2009 

eGRID2012 file for the same plant. 
THE ST FILE

60 

D. THE ST (STATE) FILE 

There are 111 variables in the fourth file, ST, which contains state level data. All size, heat input, 

generation, and emission values are derived by aggregating from the plant level based on the state in 

which the plant is located. Variables that are either identical to those in the plant file or different from 

those in the plant file by the first two letters of their names (e.g., STHTIAN instead of PLHTIAN) are not 

re-described. Aggregated variable names generally begin with “ST.” The one new variable for this data 

year is the first one. 

1. eGRID2012 year 2009 File State Sequence Number (SEQST09) –

The state records in this year 2009 data file are sorted by state postal code abbreviation 

and are assigned a unique sequential number beginning with 1. This is a new field in 

eGRID2012. 

2. State Abbreviation (PSTATABB) –

3. FIPS State Code (FIPSST) –

4. State Nameplate Capacity (NAMEPCAP) –

5. State Annual Heat Input (STHTIAN) –

6. State Ozone Season Heat Input (STHTIOZ) –

7. State Annual Net Generation (STNGENAN) –

8. State Ozone Season Net Generation (STNGENOZ) –

9. State Annual NOx Emissions (STNOXAN) –

10. State Ozone Season NOx Emissions (STNOXOZ) –

11. State Annual SO2 Emissions (STSO2AN) –

12. State Annual CO2 Emissions (STCO2AN) – 

 

 13. State Annual CH4 Emissions (STCH4AN) –

 

14. State Annual N2O Emissions (STN2OAN) –

 

 15. State Annual CO2 Equivalent Emissions (STCO2EQA) – 

This field, in tons, is the sum of each state’s plants’ PLCO2EQA. 

16. State Annual Hg Emissions (STHGAN) –

17. State Annual NOx Total Output Emission Rate (STNOXRTA) –

This field, in lb/MWh, is calculated as follows: 

STNOXRTA = 2000 * (STNOXAN / STNGENAN). 
THE ST FILE

61 

18. State Ozone Season NOx Total Output Emission Rate (STNOXRTO) –

This field, in lb/MWh, is calculated as follows: 

STNOXRTO = 2000 * (STNOXOZ / STNGENOZ). 

19. State Annual SO2 Total Output Emission Rate (STSO2RTA) –

This field, in lb/MWh, is calculated as follows: 

STSO2RTA = 2000 * (STSO2AN / STNGENAN). 

20. State Annual CO2 Total Output Emission Rate (STCO2RTA) –

This field, in lb/MWh, is calculated as follows: 

 STCO2RTA = 2000 * (STCO2AN / STNGENAN). 

 21. State Annual CH4 Total Output Emission Rate (STCH4RTA) –

This field, in lb/GWh, is calculated as follows: 

 STHCH4RTA = STCH4AN / (STNGENAN / 1000). 

 

 22. State Annual N2O Total Output Emission Rate (STN2ORTA) –

This field, in lb/GWh, is calculated as follows: 

 STN2ORTA = STN2OAN / (STNGENAN / 1000). 

 

 23. State Annual CO2 Equivalent Total Output Emission Rate (STC2ERTA) – 

This field, in lb/MWh, is calculated as follows: 

STC2ERTA = 2000 * (STCO2EQA / STNGENAN). 

24. State Annual Hg Total Output Emission Rate (STHGRTA) –

This field, in lb/GWh, is calculated as follows: 

 STHGRTA = STHGAN / (STNGENAN / 1000). 

25. State Annual NOx Input Emission Rate (STNOXRA) –

This field, in lb/MMBtu, is calculated as follows: 

STNOXRA = 2000 * (STNOXAN / STHTIAN). 

26. State Ozone Season NOx Input Emission Rate (STNOXRO) –

This field, in lb/MMBtu, is calculated as follows: 

STNOXRO = 2000 * (STNOXOZ / STHTIOZ). 

27. State Annual SO2 Input Emission Rate (STSO2RA) –

This field, in lb/MMBtu, is calculated as follows: 

STSO2RA = 2000 * (STSO2AN / STHTIAN). 

28. State Annual CO2 Input Emission Rate (STCO2RA) –

This field, in lb/MMBtu, is calculated as follows: 

STCO2RA = 2000 * (STCO2AN / STHTIAN). 

29. State Annual Hg Input Emission Rate (STHGRA) –

This field, in lb/BBtu, is calculated as follows: 

 STHGRA = STHGAN / (STHTIAN / 1000). 
THE ST FILE

62 

 30. State Annual NOx Combustion Output Emission Rate (STNOXCRT) –

This field, in lb/MMBtu, is calculated as follows: 

STNOXCRT =2000 * (STNOXAN / STGENACY). 

31. State Ozone Season NOx Combustion Output Emission Rate (STNOXCRO) –

This field, in lb/MMBtu, is calculated as follows: 

STNOXCRO = 2000 * (STNOXOZ / ((STGENACY*STNGENOZ)/STNGENAN)). 

32. State Annual SO2 Combustion Output Emission Rate (STSO2CRT) –

This field, in lb/MMBtu, is calculated as follows: 

STSO2CRT = 2000 * (STSO2AN / STGENACY). 

33. State Annual CO2 Combustion Output Emission Rate (STCO2CRT) –

This field, in lb/MMBtu, is calculated as follows: 

STCO2CRT = 2000 * (STCO2AN / STGENACY). 

34. State Annual CH4 Combustion Output Emission Rate (STCH4CRT) – 

This field, in lb/BBtu, is calculated as follows: 

 STCH4CRT = STCH4AN / (STGENACY / 1000). 

 

 35. State Annual N2O Combustion Output Emission Rate (STN2OCRT) – 

This field, in lb/BBtu, is calculated as follows: 

 STN2OCRT = STN2OAN / (STGENACY / 1000). 

 36. State Annual Hg Combustion Output Emission Rate (STHGCRT) – 

This field, in lb/BBtu, is calculated as follows: 

 STHGCRT = STHGAN / (STGENACY / 1000). 

 

37. State Annual NOx Coal Output Emission Rate (STCNOXRT) – 

 This field, in lb/MWh, is calculated as the sum of the annual NOx emissions from all 

plants in the state that have coal as its primary fuel (PLPRMFL) divided by the sum of 

the annual combustion net generation from the same set of plants, and multiplied by a 

unit conversion factor. The methodology is new, beginning with year 2009 data, for all 

the fuel-based output emission rates. 

38. State Annual NOx Oil Output Emission Rate (STONOXRT) –

This field, in lb/MWh, is calculated as the sum of the annual NOx emissions from all 

plants in the state that have oil as its primary fuel (PLPRMFL) divided by the sum of the 

annual combustion net generation from the same set of plants, and multiplied by a unit 

conversion factor. The methodology is new, beginning with year 2009 data, for all the 

fuel-based output emission rates. 

39. State Annual NOx Gas Output Emission Rate (STGNOXRT) –

This field, in lb/MWh, is calculated as the sum of the annual NOx emissions from all 

plants in the state that have natural gas as its primary fuel (PLPRMFL) divided by the 

sum of the annual combustion net generation from the same set of plants, and multiplied 

by a unit conversion factor. The methodology is new, beginning with year 2009 data, for 

all the fuel-based output emission rates. 
THE ST FILE

63 

40. State Annual NOx Fossil Fuel Output Emission Rate (STFSNXRT) –

This field, in lb/MWh, is calculated as the sum of the annual NOx emissions from all 

plants in the state that have a fossil fuel (coal, oil, gas, or other fossil) as its primary fuel 

(PLPRMFL) divided by the sum of the annual combustion net generation from the same 

set of plants, and multiplied by a unit conversion factor. The methodology is new, 

beginning with year 2009 data, for all the fuel-based output emission rates. 

41. - State Ozone Season NOx Coal, Oil, Gas, and Fossil Fuel Output Emission Rates –

44. The descriptions of these fields, in lb/MWh, contain the same information for ozone 

season NOx as fields #37 through #40, respectively, do for annual NOx. The state ozone 

season combustion net generation, used in the denominator of the equations used to 

calculate these state fuel-based output emission rates is calculated as the ratio of the state 

annual to ozone season net generation for that fuel times the state annual combustion net 

generation. The methodology is new, beginning with year 2009 data, for all the fuelbased output emission rates. 

45. - State Annual SO2 Coal, Oil, Gas, and Fossil Fuel Output Emission Rates –

48. The descriptions of these fields, in lb/MWh, contain the same information for annual SO2

as fields #37 through #40, respectively, do for annual NOx. 

49. - State Annual CO2 Coal, Oil, Gas, and Fossil Fuel Output Emission Rates –

52. The descriptions of these fields, in lb/MWh, contain the same information for annual CO2

as fields #37 through #40, respectively, do for annual NOx. 

53. - State Annual Hg Coal and Fossil Fuel Output Emission Rates –

54. The descriptions of these fields, in lb/GWh, contain the same information for annual Hg 

as fields #37 and #40, respectively, do for annual NOx. 

55. - State Annual NOx, Ozone Season NOx, Annual SO2, Annual CO2 Coal, Oil, Gas, 

 72. and Fossil Fuel Input Emission Rates; and Annual Hg Coal and Fossil Fuel Input 

Emission Rates –

The description of these fields, primary fuel-specific input emission rates, contains the 

same information that fields #37 through #54 do for primary fuel-specific output 

emission rates – except that the calculations include heat input, rather than net generation. 

Note that for Hg input emission rates, the units are lb/BBtu, not lb/MMBtu. These values 

are calculated in the same manner as are any input emission rates. 

73. State Annual NOx Non-baseload Output Emission Rate (STNBNOX) –

This field, in lb/MWh, is the sum of the annual non-baseload NOx emissions divided by 

the sum of annual non-baseload net generation in the state and then multiplied by a unit 

conversion factor. This field is intended to provide a more refined estimate of avoided 

emissions than the fossil-fuel average output emission rate. The non-baseload emissions 

and generation include only emissions and generation from combustion sources and 

exclude emissions and generation from plants that have high capacity factors. The 

remaining emissions and generation are weighted by a factor which is a function of 

capacity factor. For more information, see the Methodology Section. 

74. State Ozone Season NOx Non-baseload Output Emission Rate (STNBNXO) –

The description of this field, in lb/MWh, contains the same information as field #73 does, 

but for the ozone season.
THE ST FILE

64 

 75. State Annual SO2 Non-baseload Output Emission Rate (STNBSO2) –

The description of this field, as well as fields #76 through #79, in lb/MWh, contain the 

same information as field #73 does, but for the appropriate pollutant. 

 76. State Annual CO2 Non-baseload Output Emission Rate (STNBCO2) –

 77. State Annual CH4 Non-baseload Output Emission Rate (STNBCH4) – 

 

 78. State Annual N2O Non-baseload Output Emission Rate (STNBN2O) – 

 

 79. State Annual Hg Non-baseload Output Emission Rate (STNBHG) –

80. State Annual Coal Net Generation (STGENACL) –

81. State Annual Oil Net Generation (STGENAOL) –

82. State Annual Gas Net Generation (STGENAGS) –

83. State Annual Nuclear Net Generation (STGENANC) –

84. State Annual Hydro Net Generation (STGENAHY) –

85. State Annual Biomass Net Generation (STGENABM) –

86. State Annual Wind Net Generation (STGENAWI) –

87. State Annual Solar Net Generation (STGENASO) –

88. State Annual Geothermal Net Generation (STGENAGT) –

89. State Annual Other Fossil Net Generation (STGENAOF) –

90. State Annual Other Unknown/Purchased Fuel Net Generation (STGENAOP) –

91. State Annual Total Nonrenewables Net Generation (STGENATN) –

92. State Annual Total Renewables Net Generation (STGENATR) –

93. State Annual Total Nonhydro Renewables Net Generation (STGENATH) – 

 94. State Annual Total Combustion Net Generation (STGENACY) – 

 

 95. State Annual Total Noncombustion Net Generation (STGENACN) – 

 

96. State Coal Generation Percent (STCLPR) – 

97. State Oil Generation Percent (STOLPR) –

98. State Gas Generation Percent (STGSPR) –

99. State Nuclear Generation Percent (STNCPR) –
THE ST FILE

65 

 100. State Hydro Generation Percent (STHYPR) –

 101. State Biomass Generation Percent (STBMPR) –

102. State Wind Generation Percent (STWIPR) –

 103. State Solar Generation Percent (STSOPR) –

 104. State Geothermal Generation Percent (STGTPR) – 

 105. State Other Fossil Generation Percent (STOFPR) –

 106. State Other Unknown/Purchased Fuel Generation Percent (STOPPR) –

 107. State Total Nonrenewables Generation Percent (STTNPR) –

 

108. State Total Renewables Generation Percent (STTRPR) –

 

 109. State Total Nonhydro Renewables Generation Percent (STTHPR) – 

 110. State Total Combustion Generation Percent (STCYPR) – 

 

 111. State Total Noncombustion Generation Percent (STCNPR) – 
66 

E. THE PCAL (PCA) FILE 

There are 111 variables in the fifth file, PCAL, which contains location (operator)-based power control 

area (PCA) data. All generation and emission values are derived by aggregating from the plant level 

based on the associated PCA. 

The one new variable for this data year is the year 2009 sequence number. There are no other variables 

that have not been described in previous file variable descriptions. Aggregated variable names generally 

begin with “PC.” 

F. THE SRL (eGRID SUBREGION) FILE 

There are 113 variables in the sixth file, SRL, which contains location (operator-based) eGRID 

subregions. All generation and emission values are derived by aggregating from the plant level based on 

the associated eGRID subregion. 

One new variable added to this file in eGRID2012 is the eGRID subregion annual CO2 equivalent nonbaseload output emission rate (SRNBC2ER). The other new variable for this data year is the year 2009 

sequence number. There are no other variables that have not been described in previous file variable 

descriptions. Aggregated variable names generally begin with “SR.” 

G. THE NRL (NERC REGION) FILE 

There are 111 variables in the seventh file, NRL, which contains location (operator)-based NERC region 

data. All generation and emission values are derived by aggregating from the plant level based on the 

associated NERC region. 

The only variable in this file that has not been described in a previous file variable description is 

NERCNAME, the NERC region name associated with the NERC region acronym (see subsection E.1. of 

the Methodology Section). The other new variable for this data year is the year 2009 sequence number. 

Aggregated variable names generally begin with “NR.” 

H. THE US (U.S.) FILE 

There are 109 variables in the eighth file, US, which contains data for the entire United States. All 

generation and emission values are derived by aggregating from the plant level. The one new variable for 

this data year is the year 2009 sequence number. There are no other variables that have not been 

described in previous file variable descriptions. Aggregated variable names generally begin with “US.” 

I. THE REGIONAL GRID GROSS LOSS FILE 

There are seven variables in this newly added ninth file, GGL, for year 2009 data. The grid gross loss 

values can be used when applying eGRID GHG factors (eGRID subregion annual GHG total output 

emission rates) to consumption. Specifically, to account for indirect emissions associated with 

consumption of electricity (both from generation and from transmission and distribution line losses) 

divide the product of the electricity consumption and the generation based eGRID total output emission 

rates by (one minus the grid gross loss as a decimal). See the equation below: 

 GHG emis cons = GHG emis rate * Consumption /(1-ggl%/100)/2000; 
67 

where 

 GHG emis cons = a specified GHG emission associated with a certain amount of electricity 

 consumption (generation and line losses) in tons, 

 GHG emis rate = eGRID subregion annual total output emission rate in lb/MWh 

for a specified GHG, 

 Consumption = the given electricity consumption in MWh (= kWh/1000), and 

 Ggl% = the estimated regional grid gross loss as a percent. 

If reporting the indirect emissions for the electricity generation (scope 2 emissions) separately from the 

indirect emissions as a result of transmission and distribution line losses (scope 3 emissions), then the 

scope 2 emissions are simply the consumption in MWh multiplied by the eGRID subregion annual total 

output emission rate in lb/MWh, and the scope 3 emissions are calculated in the following equation: 

GHG emis ll = GHG emis rate * Consumption * (ggl%/100) / (1-ggl%/100)/2000; 

where 

 GHG emis ll = a specified GHG emission associated with the line losses of a certain 

 amount of electricity consumption in tons, 

 GHG emis rate = eGRID subregion annual total output emission rate in lb/MWh 

for a specified GHG, 

 Consumption = the given electricity consumption in MWh (= kWh/1000), and 

 Ggl% = the estimated regional grid gross loss as a percent. 

The variables in the regional grid gross loss file are as follows: 

1. REGION – 

This field is one of the three interconnect power grids in the U.S. (plus Alaska, Hawaii, 

and the entire U.S.) 

2. GENERAT – 

The field is the regional total net generation in MWh. These data originally are at the 

PCA level plus MISO and are subsequently summed to the power grid region. 

Source: 2009 FERC-714, eGRID2012 year 2009 net generation (for Alaska and Hawaii) 

3. FRGNINTC – 

This field is the regional total net interchange in MWh with Canada and Mexico. These 

data originally are at the PCA level plus MISO and are subsequently summed to the 

power grid region. Note that imports will have a positive value. 

Source: 2009 FERC-714 updated by EIA 

4. INTRCHNG – 

This field is the regional total net interchange (= generation imported - generation 

exported) in MWh with a different U.S. region. These data originally are at the PCA 

level plus MISO and are subsequently summed to the power grid region. Note that 

imports will have a positive value. 

Source: 2009 FERC-714 + updates 

5 CONSUMP – 

This field is the regional total consumption in MWh. Consumption is the sum of total 

retail sales to ultimate customers, energy furnished without charge, and energy consumed 
68 

by the respondent without charge. These data, originally at the utility service territory 

level, are subsequently summed to the power grid region. 

Source: 2009 EIA-861 Files 1 and 2 + updates 

6. GGRSLOSS – 

This field is the estimated grid gross loss as a percent. The algorithm used is GGRLOSS = (100 * (GENERAT + FRGNINTC + INTRCHNG - CONSUMP) / GENERAT). 

The grid gross loss values are also included in Table III-4. 

7. YEAR – 

This field is the year of data. 
69 

SECTION VI. REFERENCES 

Brighter Planet, 2010: Brighter Planet, Electricity Use carbon model, 2010. 

http://brighterplanet.github.com/electricity_use/impact_model.html

CARB, 2007: California Air Resources Board “Regulation for the Mandatory Reporting of Greenhouse 

Gas Emissions (AB 32 requirements)” Table 5 in Appendix A, December 2007. 

http://www.arb.ca.gov/regact/2007/ghg2007/frofinoal.pdf

Diem, Rothschild, and Quiroz, 2011: Diem, A., S. Rothschild, and C. Quiroz, “eGRID: An Efficient 

Way to Value the GHG Emissions Reduction Effects of Energy Efficiency,” a paper 

accompanying the poster presentation at the International Energy Program Evaluation 

Conference, Boston, MA, August 2011. 

Diem, Rothschild, and Quiroz, 2012a: Diem, A., S. Rothschild, and C. Quiroz, “eGRID Data for Carbon 

Footprinting Electricity Purchases,” presented at EUEC 2012 Environmental Conference, 

Phoenix, AZ, January 2012. 

Diem, Rothschild, and Quiroz, 2012b: Diem, A., S. Rothschild, and C. Quiroz, “When to Use Which 

eGRID Data Year of GHG Emission Factors: Several Scenarios Presented” to be presented at the 

U.S. Environmental Protection Agency 2012 International Emission Inventory 

Conference, Tampa, Florida, August 2012 (forthcoming). 

DVRPC, 2010: Delaware Valley Regional Planning Commission, Regional Greenhouse Gas Emissions 

Inventory, revised December 2010. 

http://www.dvrpc.org/reports/09038A.pdf

DOE, 2003: U.S. Department of Energy, Gas-Fired Distributed Energy Resource Technology 

Characterizations, November 2003. 

http://www.nrel.gov/docs/fy04osti/34783.pdf

EEA, 2011 updated: Energy and Environmental Analysis, an ICF International Company, “Combined 

Heat and Power Installation Database, maintained for DOE ORNL,” Washington, DC, 2011, 

updated. 

http://www.eea-inc.com/chpdata/index.html 

EIA, 2000: Energy Information Administration, The Main Interconnections of the U.S. Electric Power 

Grid and the 10 North American Electric Reliability Council Regions in “The Changing Structure 

of the Electric Power Industry 2000: An Update (Figure 7)”, October 2000. 

http://www.eia.gov/cneaf/electricity/chg_stru_update/fig7.html

EIA, 2007: Energy Information Administration. Tables B1 and B2, 

http://www.eia.doe.gov/cneaf/solar.renewables/page/mswaste/msw.pdf . Tables and updates 

based on EIA-EPA email exchanges from October 23, 2007 through November 15, 2007. 

EIA, 2011a: Energy Information Administration, “2009 Annual Electric Generator Report,” Form EIA860, Washington, DC, 2011. 

http://www.eia.gov/cneaf/electricity/page/eia860.html
70 

EIA, 2011b: Energy Information Administration, “2009 Annual Electric Power Industry Report,” Form 

EIA-861, Washington, DC, 2011. 

http://www.eia.gov/cneaf/electricity/page/eia861.html

EIA, 2011c: Energy Information Administration, “2009 Power Plant Operations Report,” Form EIA-923, 

Washington, DC, 2011. 

http://www.eia.gov/cneaf/electricity/page/eia906_920.html

EIA, 2011d: Energy Information Administration, The Electricity Module of the National Energy 

Modeling System Model Documentation Report (Figure 3), July 2011. 

ftp://ftp.eia.doe.gov/modeldoc/m068(2011).pdf

EIA, 2011e: Energy Information Administration, “Plant Coordinates (2010), attached file from EIA’s 

 Stan Kaplan, December 6, 2011. 

EPA, 2002: U.S. Environmental Protection Agency, “Large Municipal Waste Combustor 2000 

 Database,” 2002. 

EPA, 2009: U.S. Environmental Protection Agency, Final Mandatory Reporting of Greenhouse Gases 

Rule (Tables C-1 and C-2), Washington, D.C., October 30, 2009. 

http://www.epa.gov/climatechange/emissions/downloads09/GHG-MRR-Full%20Version.pdf

EPA, 2011a: U.S. Environmental Protection Agency, 2009 Annual and Ozone Season EPA/CAMD 

database, Washington, DC, downloaded October 31, 2011 from

http://camddataandmaps.epa.gov/gdm/. 

EPA, 2011b: U.S. Environmental Protection Agency, Apps for the Environment, November 2011. 

http://www.epa.gov/appsfortheenvironment/

EPA, 2012a: U.S. Environmental Protection Agency, Compilation of Air Pollutant Emission Factors, 

AP-42 – uncontrolled criteria pollutant emission factors (EF) with EPA-approved updates, 

February 2012. 

EPA, 2012b: U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990-2010, Washington, D.C., April 2012. 

http://epa.gov/climatechange/emissions/usinventoryreport.html 

EPA, undated1: U.S. Environmental Protection Agency’s EPA CHP Partnership, Catalogue of CHP 

Technologies. 

http://www.epa.gov/chp/documents/catalog_chptech_full.pdf (updated link) 

EPA, undated2: U.S. Environmental Protection Agency, RACT/BACT/LAER Clearinghouse. 

Washington, DC. 

http://cfpub1.epa.gov/RBLC/

FERC, 2011: Federal Energy Regulatory Commission, Form FERC-714 year 2009 data. Obtained from 

EIA on July 6, 2011. 

Galvin, 2011: Galvin Electricity Initiative, Perfect Power Seal of Approval: Metrics and Scoring System 

(beta version), April 20, 2011. 
71 

GEA, 2007: Alyssa Kagel, Diana Bates, and Karl Gawell. Table 3, Air Emissions Summary, in “A 

Guide to Geothermal Energy and the Environment”, Geothermal Energy Association, 

Washington, D.C., April 2007. 

http://geo-energy.org/reports/Environmental%20Guide.pdf

GEA, 2010: Geothermal generator type from state-plant information displayed on the 

 Geothermal Energy Association website, http://www.geo-energy.org/, Washington, D.C., 

 August 2010. 

IPCC, 2007: The Intergovernmental Panel on Climate Change (IPCC), “2006 IPCC Guidelines for 

National Greenhouse Gas Inventories”, volume 2 (Energy), April 2007. 

http://www.ipccnggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_2_Ch2_Stationary_Combustion.pdf

Maryland, 2010: Maryland Department of the Environment, Technical Support Document for 

Amendments to COMAR 26.09 MD CO2 Budget Training Program, Baltimore, MD, October 25, 

2010. 

http://www.mde.state.md.us/aboutmde/AboutMDEHome/Documents/RGGI-VERSA_TSD.PDF

NERC, 2012a: “Currently Registered BAs in NERC Compliance Registry as of March 28, 2012” Excel 

spreadsheet. Downloaded NERC_Compliance_Registry_Matrix_Excel20120328.xls from 

http://www.nerc.com/page.php?cid=3|25 . 

NERC, 2012b: North American Electric Reliability Corporation, NERC Regions map, 

http://www.nerc.com/fileUploads/File/AboutNERC/maps/NERC_Regions_color.jpg. 

NIST, undated: National Institute of Standards and Technology, Federal Information Processing 

Standards Publications. 

http://www.itl.nist.gov/fipspubs/index.htm.

Rothschild and Diem, 2009: Rothschild, S. and A. Diem, 2009. “Total, Non-baseload, eGRID Subregion, 

State? Guidance on the Use of eGRID Output Emission Rates,” presented at the U.S. 

Environmental Protection Agency Emission Inventory Conference, Baltimore, MD, May 2009. 

http://www.epa.gov/ttn/chief/conference/ei18/session5/rothschild.pdf

Rothschild, Diem, Quiroz, Salhotra, 2010: Rothschild, S, A. Diem, C. Quiroz, and M. Salhotra, 2010. 

“The Value of eGRID and eGRIDweb to GHG Inventories,” presented at EUEC 2010 

Environmental Conference, Phoenix, AZ, February 2010. 

http://www.epa.gov/cleanenergy/documents/egridzips/The_Value_of_eGRID_Dec_2009.pdf 

TCR, 2012: The Climate Registry updated emission factor file, January 6, 2012. 

TS|Pechan, 2003a: TranSystems|E.H. Pechan, “The Emissions & Generation Resource Integrated 

Database for 2002 (eGRID2002) Version 2.1 Technical Support Document,” prepared for the 

U.S. Environmental Protection Agency, Acid Rain Division, Washington, DC, May 2003. 

TS|Pechan, 2003b: TranSystems|E.H. Pechan, “The Emissions & Generation Resource Integrated 

Database for 2002 (eGRID2002) Version 2.1 Users Manual,” prepared for the U.S. 

Environmental Protection Agency, Acid Rain Division, Washington, DC, April 2003. 
72 

TS|Pechan, 2007: TranSystems|E.H. Pechan, “The Emissions & Generation Resource Integrated 

Database for 2006 (eGRID2006) Technical Support Document,” prepared for the U.S. 

Environmental Protection Agency, Climate Protection Partnership Division, Washington, DC, 

May 2007. 

TS|Pechan, 2008: TranSystems|E.H. Pechan, “The Emissions & Generation Resource Integrated 

Database for 2007 (eGRID2007) Technical Support Document,” prepared for the U.S. 

Environmental Protection Agency, Climate Protection Partnership Division, Washington, DC, 

September 2008. 

TS|Pechan, 2009: TranSystems|E.H. Pechan, “The Emissions & Generation Resource Integrated 

Database eGRIDweb Version 1.0 Users Manual,” prepared for U.S. Environmental Protection 

Agency, Washington, DC, April 2009. 

TS|Pechan, 2010: TranSystems|E.H. Pechan, “The Emissions & Generation Resource Integrated 

Database for 2010 (eGRID2010) Technical Support Document,” prepared for the U.S. 

Environmental Protection Agency, Acid Rain Division, Washington, DC, December 2010. 

TS|Pechan, 2012: TranSystems|E.H. Pechan, “The Emissions & Generation Resource Integrated 

Database for 2012 (eGRID2012) Technical Support Document,” prepared for the U.S. 

Environmental Protection Agency, Acid Rain Division, Washington, DC, April 2012. 

UCS, 2012: Union of Concerned Scientists, “State of Charge: Electric Vehicles’ Global Warming 

Emissions and Fuel-Cost Savings Across the United States, April 2012. 

http://www.ucsusa.org/clean_vehicles/technologies_and_fuels/hybrid_fuelcell_and_electric_vehi

cles/emissions-and-charging-costs-electriccars.html?utm_source=SP&utm_medium=head&utm_campaign=EV%2BReport

Ventyx, 2007: Ventyx’ Global Energy Decisions’ Velocity Suites 2006 data, downloaded on a trial basis 

with company permission, October-November 2007. 

WECC, 2007: “Existing Generation and Significant Additions and Changes to System Facilities 

(2006 -2016) Data as of January 1, 2007,” prepared by WECC staff, downloaded as 

SIGADD07Final.pdf on May 18, 2010 at 

http://www.wecc.biz/committees/StandingCommittees/PCC/LRS/Shared%20Documents/LRS%2

0Reports/Year%202007/SIGADD07Final.pdf. 

Wheeler, 2007: David Wheeler, Senior Fellow, Center for Global Development, CARMA developer, 

personal communication, November 30, 2007. 
A-1 

APPENDIX A. eGRID2012 FILE STRUCTURE - VARIABLE 

DESCRIPTIONS FOR 2009 DATA YEAR 

The year 2009 data for eGRID2012 are initially in database format and are then transformed into Excel 

spreadsheets. The structure of the nine database files – including descriptions of the variables, unit of 

measurement, and original source(s) of data – are delineated below in the file structure. NOTE: Italics 

indicates new field; bold indicates methodological change. 

Table A-1 

eGRID2012 Version 1.0 File Structure 

Year 2009 BLR Boiler File* 

Field Name Description Unit Source(s) 

1 SEQBLR09 eGRID2012 year 2009 file boiler sequence number 

2 PSTATABB Plant state abbreviation EIA-860 

3 PNAME Plant name EIA-860 + updates 

4 ORISPL DOE/EIA ORIS plant or facility code EIA-860 + updates 

5 BLRID Boiler ID EPA/CAMD, EIA-923 

6 ARPFLAG Acid Rain Program flag: 1 = Yes EPA/CAMD 

7 PRGCODE Program code(s) EPA/CAMD 

8 BOTFIRTY Boiler bottom and firing type EPA/CAMD, EIA-860 

9 NUMGEN Number of associated generators EIA-860

10 FUELB1 Boiler primary fuel EPA/CAMD, EIA-923 

11 HRSOP Unit operating hours hours EPA/CAMD 

12 HTIEAN Boiler unadjusted annual EPA/CAMD heat input MMBtu EPA/CAMD 

13 HTIEOZ Boiler unadjusted ozone season EPA/CAMD heat input MMBtu EPA/CAMD 

14 HTIFAN Boiler unadjusted annual total EIA-based calculated heat input MMBtu EIA-923 

15 HTIFOZ Boiler unadjusted ozone season EIA-based calculated heat input MMBtu EIA-923 

16 NOXEAN Boiler unadjusted annual EPA/CAMD NOx emissions tons EPA/CAMD 

17 NOXEOZ Boiler unadjusted ozone season EPA/CAMD NOx emissions tons EPA/CAMD 

18 NOXFAN Boiler unadjusted annual EIA-based calculated NOx emissions tons EIA-923 

19 NOXFOZ Boiler unadjusted ozone season EIA-based calculated NOx emissions tons EIA-923 

20 SO2EAN Boiler unadjusted annual EPA/CAMD SO2 emissions tons EPA/CAMD 

21 SO2FAN Boiler unadjusted annual EIA-based calculated SO2 emissions tons EIA-923 

22 CO2EAN Boiler unadjusted annual EPA/CAMD CO2 emissions tons EPA/CAMD 

23 CO2FAN Boiler unadjusted annual EIA-based calculated CO2 emissions tons EIA-923 

24 SRCBEST Source of “best” data from EPA/CAMD or EIA-923 boiler level 

25 HTIBAN Boiler unadjusted annual best heat input MMBtu 

26 HTIBOZ Boiler unadjusted ozone season best heat input MMBtu 

27 NOXBAN Boiler unadjusted annual best NOx emissions tons 

28 NOXBOZ Boiler unadjusted ozone season best NOx emissions tons 

29 SO2BAN Boiler unadjusted annual best SO2 emissions tons 

30 CO2BAN Boiler unadjusted annual best CO2 emissions tons 

31 SO2CTLDV Boiler SO2 (scrubber) first control device EPA/CAMD, EIA-860 

32 NOXCTLDV Boiler NOx first control device EPA/CAMD, EIA-860 

33 HGCTLDV Boiler Hg activated carbon injection system flag: 1 = Yes EIA-860 

34 BLRYRONL Boiler year on-line EPA/CAMD, EIA-860 

*Note that summing the boiler unadjusted emissions to the plant level may not result in the same values as the plant unadjusted 

emissions since additional emissions from prime movers not covered by the EPA/CAMD or EIA-923 boiler level data may be included

in the plant emissions values. 
A-2 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 GEN Generator File** 

Field Name Description Unit Source(s) 

1 SEQGEN09 eGRID2012 year 2009 file generator sequence number 

2 PSTATABB Plant state abbreviation EIA-860 

3 PNAME Plant name EIA-860 + updates 

4 ORISPL DOE/EIA ORIS plant or facility code EIA-860 + updates 

5 GENID Generator ID EIA-860 

6 NUMBLR Number of associated boilers EIA-860 

7 GENSTAT Generator status EIA-860 

8 PRMVR Generator prime mover type EIA-860 

9 FUELG1 Generator primary fuel EIA-860 

10 NAMEPCAP Generator nameplate capacity MW EIA-860 

11 CFACT Generator capacity factor 

12 GENNTAN Generator annual net generation MWh EIA-923 

13 GENNTOZ Generator ozone season net generation MWh EIA-923 

14 GENERSRC Generation data source 

15 GENYRONL Generator year on-line EIA-860 

**Note that summing the generator generation to the plant level may not result in the same values as the plant generation. This file 

includes generation from nuclear units in the EIA-923, steam generators in the unit-level EIA-923, and those plant-prime movers in the 

EIA-923 that have only one generator in the EIA-860. 
A-3 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 PLNT Plant File 

Field Name Description Unit Source(s) 

1 SEQPLT09 eGRID2012 year 2009 file plant sequence number 

2 PSTATABB Plant state abbreviation EIA-860 

3 PNAME Plant name EIA-860 + updates 

4 ORISPL DOE/EIA ORIS plant or facility code EIA-860 + updates 

5 FRSID Plant EPA Facility Registry System (FRS) identification code EPA FRS 

6 OPRNAME Plant operator name EIA-860 

7 OPRCODE Plant operator ID EIA-860 

8 UTLSRVNM Utility service territory name EIA-860 + updates 

9 UTLSRVID Utility service territory ID EIA-860 + updates 

10 OPPRNUM ID of the operator's parent company 

11 OPPRNAME Name of the operator's parent company 

12 PCANAME Power control area name NERC, EIA-861 + updates 

13 PCAID Power control area ID NERC, EIA-861 + updates 

14 NERC NERC region acronym NERC 

15 SUBRGN eGRID subregion acronym EPA 

16 SRNAME eGRID subregion name EPA 

17 ISORTO Plant associated ISO/RTO Territory EIA-860 (2010) + updates 

18 FIPSST Plant FIPS state code NIST based 

19 FIPSCNTY Plant FIPS county code NIST based 

20 CNTYNAME Plant county name EIA-860, EPA/CAMD 

21 LAT Plant latitude EPA/CAMD, EIA + updates 

22 LON Plant longitude EPA/CAMD, EIA + updates 

23 CCFLAG County centroid flag: 1 = County centroid used 

24 NUMBLR Number of boilers EPA/CAMD, EIA-860 

calculated 

25 NUMGEN Number of generators EIA-860 calculated 

26 COMBUST Plant combustion status: 1 = Combusts, 0 = No combustion, 

0.5 = Partial combustion 

 

27 SOURCEM Plant emissions source(s): EPA or EIA-923 

28 PLPRMFL Plant primary fuel 

29 PLFUELCT Plant primary coal/oil/gas/other fossil fuel category 

30 PLPFGNCT Plant primary fuel generation category       31 COALFLAG Flag indicating if the plant burned or generated any amount 

of coal: 1 = Yes 

 

32 CAPFAC Plant capacity factor 

33 NAMEPCAP Plant nameplate capacity MW EIA-860 summed 

34 RMBMFLAG Biogas/biomass plant adjustment flag: 0 = No biomass; 1 = 

Biogas included; 100 = Other biomass included; 71 = CAMD 

emissions biogas adjustments; 7100 = CAMD CO2 biomass 

adjustment 

 

35 CHPFLAG Combined heat and power (CHP) plant adjustment flag: 1 = 

Yes 

 eGRID CHP List 

36 USETHRMO CHP plant useful thermal output MMBtu EIA-923 calculated 

37 PWRTOHT CHP plant power to heat ratio 

38 ELCALLOC CHP plant electric allocation factor 

39 PSFLAG Plant pumped storage flag: 1 = Yes EIA-860 

40 PLHTIAN Plant annual heat input MMBtu 

41 PLHTIOZ Plant ozone season heat input MMBtu 

42 PLNGENAN Plant annual net generation MWh EIA-923, EPA/CAMD 

calculated 
A-4 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 PLNT Plant File (continued). 

Field Name Description Unit Source(s) 

43 PLNGENOZ Plant ozone season net generation MWh EIA-923, EPA/CAMD 

calculated 

44 PLNOXAN Plant annual NOx emissions tons 

45 PLNOXOZ Plant ozone season NOx emissions tons 

46 PLSO2AN Plant annual SO2 emissions tons 

47 PLCO2AN Plant annual CO2 emissions tons 

48 PLCH4AN Plant annual CH4 emissions lbs 

49 PLN2OAN Plant annual N2O emissions lbs 

50 PLCO2EQA Plant annual CO2 equivalent emissions ((1 * PLCO2AN ) + 

(21 * PLCH4AN/2000) + (310 * PLN2OAN/2000)) 

tons 

51 PLHGAN Plant annual Hg emissions lbs 

52 PLNOXRTA Plant annual NOx total output emission rate lb/MWh 

53 PLNOXRTO Plant ozone season NOx total output emission rate lb/MWh 

54 PLSO2RTA Plant annual SO2 total output emission rate lb/MWh 

55 PLCO2RTA Plant annual CO2 total output emission rate lb/MWh 

56 PLCH4RTA Plant annual CH4 total output emission rate lb/GWh 

57 PLN2ORTA Plant annual N2O total output emission rate lb/GWh 

58 PLC2ERTA Plant annual CO2 equivalent total output emission rate lb/MWh 

59 PLHGRTA Plant annual Hg total output emission rate lb/GWh 

60 PLNOXRA Plant annual NOx input emission rate lb/MMBtu 

61 PLNOXRO Plant ozone season NOx input emission rate lb/MMBtu 

62 PLSO2RA Plant annual SO2 input emission rate lb/MMBtu 

63 PLCO2RA Plant annual CO2 input emission rate lb/MMBtu 

64 PLHGRA Plant annual Hg input emission rate lb/BBtu 

65 PLNOXCRT Plant annual NOx combustion output emission rate lb/MWh 

66 PLNOXCRO Plant ozone season NOx combustion output emission rate lb/MWh 

67 PLSO2CRT Plant annual SO2 combustion output emission rate lb/MWh 

68 PLCO2CRT Plant annual CO2 combustion output emission rate lb/MWh 

69 PLCH4CRT Plant annual CH4 combustion output emission rate lb/GWh 

70 PLN2OCRT Plant annual N2O combustion output emission rate lb/GWh 

71 PLHGCRT Plant annual Hg combustion output emission rate lb/GWh 

72 UNNOX Plant unadjusted annual NOx emissions tons 

73 UNNOXOZ Plant unadjusted ozone season NOx emissions tons 

74 UNSO2 Plant unadjusted annual SO2 emissions tons 

75 UNCO2 Plant unadjusted annual CO2 emissions tons 

76 UNCH4 Plant unadjusted annual CH4 emissions lbs 

77 UNN2O Plant unadjusted annual N2O emissions lbs 

78 UNHG Plant unadjusted annual Hg emissions lbs 

79 UNHTI Plant unadjusted annual heat input MMBtu EPA/CAMD, EIA-923 

80 UNHTIOZ Plant unadjusted ozone season heat input MMBtu EPA/CAMD, EIA-923 

81 PLHTRT Plant nominal heat rate Btu/kWh 

82 PLGENACL Plant annual coal net generation MWh 

83 PLGENAOL Plant annual oil net generation MWh 

84 PLGENAGS Plant annual gas net generation MWh 

85 PLGENANC Plant annual nuclear net generation MWh 

86 PLGENAHY Plant annual hydro net generation MWh 

87 PLGENABM Plant annual biomass net generation MWh 

88 PLGENAWI Plant annual wind net generation MWh 
A-5 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 PLNT Plant File (continued). 

Field Name Description Unit Source(s) 

89 PLGENASO Plant annual solar net generation MWh 

90 PLGENAGT Plant annual geothermal net generation MWh 

91 PLGENAOF Plant annual other fossil net generation MWh 

92 PLGENAOP Plant annual other unknown/purchased fuel net generation MWh 

93 PLGENATN Plant annual total nonrenewables net generation MWh 

94 PLGENATR Plant annual total renewables net generation MWh 

95 PLGENATH Plant annual total nonhydro renewables net generation MWh 

96 PLGENACY Plant annual total combustion net generation MWh 

97 PLGENACN Plant annual total noncombustion net generation MWh 

98 PLCLPR Plant coal generation percent (resource mix) 

99 PLOLPR Plant oil generation percent (resource mix) 

100 PLGSPR Plant gas generation percent (resource mix) 

101 PLNCPR Plant nuclear generation percent (resource mix) 

102 PLHYPR Plant hydro generation percent (resource mix) 

103 PLBMPR Plant biomass generation percent (resource mix) 

104 PLWIPR Plant wind generation percent (resource mix) 

105 PLSOPR Plant solar generation percent (resource mix) 

106 PLGTPR Plant geothermal generation percent (resource mix) 

107 PLOFPR Plant other fossil generation percent (resource mix) 

108 PLOPPR Plant other unknown/purchased fuel generation percent 

(resource mix) 

 

109 PLTNPR Plant total nonrenewables generation percent (resource mix) 

110 PLTRPR Plant total renewables generation percent (resource mix) 

111 PLTHPR Plant total nonhydro renewables generation percent 

(resource mix) 

 

112 PLCYPR Plant total combustion generation percent (resource mix) 

113 PLCNPR Plant total noncombustion generation percent (resource mix) 

114 OWNRNM01 Plant owner name (first) EIA-860 

115 OWNRUC01 Plant owner code (first) EIA-860 

116 OWNRPR01 Plant owner percent (first) EIA-860 

117 OWNRNM02 Plant owner name (second) EIA-860 

118 OWNRUC02 Plant owner code (second) EIA-860 

119 OWNRPR02 Plant owner percent (second) EIA-860 

120 OWNRNM03 Plant owner name (third) EIA-860 

121 OWNRUC03 Plant owner code (third) EIA-860 

122 OWNRPR03 Plant owner percent (third) EIA-860 

123 OWNRNM04 Plant owner name (fourth) EIA-860 

124 OWNRUC04 Plant owner code (fourth) EIA-860 

125 OWNRPR04 Plant owner percent (fourth) EIA-860 

126 OWNRNM05 Plant owner name (fifth) EIA-860 

127 OWNRUC05 Plant owner code (fifth) EIA-860 

128 OWNRPR05 Plant owner percent (fifth) EIA-860 

129 OWNRNM06 Plant owner name (sixth) EIA-860 

130 OWNRUC06 Plant owner code (sixth) EIA-860 

131 OWNRPR06 Plant owner percent (sixth) EIA-860 

132 OWNRNM07 Plant owner name (seventh) EIA-860 

133 OWNRUC07 Plant owner code (seventh) EIA-860 

134 OWNRPR07 Plant owner percent (seventh) EIA-860 
A-6 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 PLNT Plant File (continued). 

Field Name Description Unit Source(s) 

135 OWNRNM08 Plant owner name (eighth) EIA-860 

136 OWNRUC08 Plant owner code (eighth) EIA-860 

137 OWNRPR08 Plant owner percent (eighth) EIA-860 

138 OWNRNM09 Plant owner name (ninth) EIA-860 

139 OWNRUC09 Plant owner code (ninth) EIA-860 

140 OWNRPR09 Plant owner percent (ninth) EIA-860 

141 OWNRNM10 Plant owner name (tenth) EIA-860 

142 OWNRUC10 Plant owner code (tenth) EIA-860

143 OWNRPR10 Plant owner percent (tenth) EIA-860 

144 OWNRNM11 Plant owner name (eleventh) EIA-860 

145 OWNRUC11 Plant owner code (eleventh) EIA-860 

146 OWNRPR11 Plant owner percent (eleventh) EIA-860 

147 OWNRNM12 Plant owner name (twelfth) EIA-860 

148 OWNRUC12 Plant owner code (twelfth) EIA-860 

149 OWNRPR12 Plant owner percent (twelfth) EIA-860 

150 OWNRNM13 Plant owner name (thirteenth) EIA-860 

151 OWNRUC13 Plant owner code (thirteenth) EIA-860 

152 OWNRPR13 Plant owner percent (thirteenth) EIA-860 

153 OWNRNM14 Plant owner name (fourteenth) EIA-860 

154 OWNRUC14 Plant owner code (fourteenth) EIA-860 

155 OWNRPR14 Plant owner percent (fourteenth) EIA-860 

156 OWNRNM15 Plant owner name (fifteenth) EIA-860 

157 OWNRUC15 Plant owner code (fifteenth) EIA-860 

158 OWNRPR15 Plant owner percent (fifteenth) EIA-860 

159 OWNRNM16 Plant owner name (sixteenth) EIA-860 

160 OWNRUC16 Plant owner code (sixteenth) EIA-860 

161 OWNRPR16 Plant owner percent (sixteenth) EIA-860 + updates EIA-860 

162 SEQPLT04 eGRID2006 year 2004 file plant sequence number 

163 SEQPLT05 eGRID2007 year 2005 file plant sequence number 

164 SEQPLT07 eGRID2010 year 2007 file plant sequence number 
A-7 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 ST State File 

Field Name Description Unit 

1 SEQST09 eGRID2012 year 2009 file state sequence number 

2 PSTATABB State abbreviation 

3 FIPSST FIPS state code 

4 NAMEPCAP State nameplate capacity MW 

5 STHTIAN State annual heat input MMBtu 

6 STHTIOZ State ozone season heat input MMBtu 

7 STNGENAN State annual net generation MWh 

8 STNGENOZ State ozone season net generation MWh 

9 STNOXAN State annual NOx emissions tons 

10 STNOXOZ State ozone season NOx emissions tons 

11 STSO2AN State annual SO2 emissions tons 

12 STCO2AN State annual CO2 emissions tons 

13 STCH4AN State annual CH4 emissions lbs 

14 STN2OAN State annual N2O emissions lbs 

15 STCO2EQA State annual CO2 equivalent emissions tons 

16 STHGAN State annual Hg emissions lbs 

17 STNOXRTA State annual NOx total output emission rate lb/MWh 

18 STNOXRTO State ozone season NOx total output emission rate lb/MWh 

19 STSO2RTA State annual SO2 total output emission rate lb/MWh 

20 STCO2RTA State annual CO2 total output emission rate lb/MWh 

21 STCH4RTA State annual CH4 total output emission rate lb/GWh 

22 STN2ORTA State annual N2O total output emission rate lb/GWh 

23 STC2ERTA State annual CO2 equivalent total output emission rate lb/MWh 

24 STHGRTA State annual Hg total output emission rate lb/GWh 

25 STNOXRA State annual NOx input emission rate lb/MMBtu 

26 STNOXRO State ozone season NOx input emission rate lb/MMBtu 

27 STSO2RA State annual SO2 input emission rate lb/MMBtu 

28 STCO2RA State annual CO2 input emission rate lb/MMBtu 

29 STHGRA State annual Hg input emission rate lb/BBtu 

30 STNOXCRT State annual NOx combustion output emission rate lb/MWh 

31 STNOXCRO State ozone season NOx combustion output emission rate lb/MWh 

32 STSO2CRT State annual SO2 combustion output emission rate lb/MWh 

33 STCO2CRT State annual CO2 combustion output emission rate lb/MWh 

34 STCH4CRT State annual CH4 combustion output emission rate lb/GWh 

35 STN2OCRT State annual N2O combustion output emission rate lb/GWh 

36 STHGCRT State annual Hg combustion output emission rate lb/GWh 

37 STCNOXRT State annual NOx coal output emission rate lb/MWh 

38 STONOXRT State annual NOx oil output emission rate lb/MWh 

39 STGNOXRT State annual NOx gas output emission rate lb/MWh 

40 STFSNXRT State annual NOx fossil fuel output emission rate lb/MWh 

41 STCNXORT State ozone season NOx coal output emission rate lb/MWh 

42 STONXORT State ozone season NOx oil output emission rate lb/MWh 

43 STGNXORT State ozone season NOx gas output emission rate lb/MWh 

44 STFSNORT State ozone season NOx fossil fuel output emission rate lb/MWh 

45 STCSO2RT State annual SO2 coal output emission rate lb/MWh 

46 STOSO2RT State annual SO2 oil output emission rate lb/MWh 

47 STGSO2RT State annual SO2 gas output emission rate lb/MWh 

48 STFSS2RT State annual SO2 fossil fuel output emission rate lb/MWh 
A-8 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 ST State File (continued). 

Field Name Description Unit 

49 STCCO2RT State annual CO2 coal output emission rate lb/MWh 

50 STOCO2RT State annual CO2 oil output emission rate lb/MWh 

51 STGCO2RT State annual CO2 gas output emission rate lb/MWh 

52 STFSC2RT State annual CO2 fossil fuel output emission rate lb/MWh 

53 STCHGRT State annual Hg coal output emission rate lb/GWh 

54 STFSHGRT State annual Hg fossil fuel output emission rate lb/GWh 

55 STCNOXR State annual NOx coal input emission rate lb/MMBtu 

56 STONOXR State annual NOx oil input emission rate lb/MMBtu 

57 STGNOXR State annual NOx gas input emission rate lb/MMBtu 

58 STFSNXR State annual NOx fossil fuel input emission rate lb/MMBtu 

59 STCNXOR State ozone season NOx coal input emission rate lb/MMBtu 

60 STONXOR State ozone season NOx oil input emission rate lb/MMBtu 

61 STGNXOR State ozone season NOx gas input emission rate lb/MMBtu 

62 STFSNOR State ozone season NOx fossil fuel input emission rate lb/MMBtu 

63 STCSO2R State annual SO2 coal input emission rate lb/MMBtu 

64 STOSO2R State annual SO2 oil input emission rate lb/MMBtu 

65 STGSO2R State annual SO2 gas input emission rate lb/MMBtu 

66 STFSS2R State annual SO2 fossil fuel input emission rate lb/MMBtu 

67 STCCO2R State annual CO2 coal input emission rate lb/MMBtu 

68 STOCO2R State annual CO2 oil input emission rate lb/MMBtu 

69 STGCO2R State annual CO2 gas input emission rate lb/MMBtu 

70 STFSC2R State annual CO2 fossil fuel input emission rate lb/MMBtu 

71 STCHGR State annual Hg coal input emission rate lb/BBtu 

72 STFSHGR State annual Hg fossil fuel input emission rate lb/BBtu 

73 STNBNOX State annual NOx non-baseload output emission rate lb/MWh 

74 STNBNXO State ozone season NOx non-baseload output emission rate lb/MWh 

75 STNBSO2 State annual SO2 non-baseload output emission rate lb/MWh 

76 STNBCO2 State annual CO2 non-baseload output emission rate lb/MWh 

77 STNBCH4 State annual CH4 non-baseload output emission rate lb/GWh 

78 STNBN2O State annual N2O non-baseload output emission rate lb/GWh 

79 STNBHG State annual Hg non-baseload output emission rate lb/GWh 

80 STGENACL State annual coal net generation MWh 

81 STGENAOL State annual oil net generation MWh 

82 STGENAGS State annual gas net generation MWh 

83 STGENANC State annual nuclear net generation MWh 

84 STGENAHY State annual hydro net generation MWh 

85 STGENABM State annual biomass net generation MWh 

86 STGENAWI State annual wind net generation MWh 

87 STGENASO State annual solar net generation MWh 

88 STGENAGT State annual geothermal net generation MWh 

89 STGENAOF State annual other fossil net generation MWh 

90 STGENAOP State annual other unknown/purchased fuel net generation MWh 

91 STGENATN State annual total nonrenewables net generation MWh 

92 STGENATR State annual total renewables net generation MWh 

93 STGENATH State annual total nonhydro renewables net generation MWh 

94 STGENACY State annual total combustion net generation MWh 

95 STGENACN State annual total noncombustion net generation MWh 

96 STCLPR State coal generation percent (resource mix) 
A-9 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 ST State File (continued). 

Field Name Description Unit 

97 STOLPR State oil generation percent (resource mix) 

98 STGSPR State gas generation percent (resource mix) 

99 STNCPR State nuclear generation percent (resource mix) 

100 STHYPR State hydro generation percent (resource mix) 

101 STBMPR State biomass generation percent (resource mix) 

102 STWIPR State wind generation percent (resource mix) 

103 STSOPR State solar generation percent (resource mix) 

104 STGTPR State geothermal generation percent (resource mix) 

105 STOFPR State other fossil generation percent (resource mix) 

106 STOPPR State other unknown/purchased fuel generation percent (resource mix) 

107 STTNPR State total nonrenewables generation percent (resource mix) 

108 STTRPR State total renewables generation percent (resource mix) 

109 STTHPR State total nonhydro renewables generation percent (resource mix) 

110 STCYPR State total combustion generation percent (resource mix) 

111 STCNPR State total noncombustion generation percent (resource mix) 
A-10 

Table A-1 

eGRID2012 Version 1.0 File Structure 

Year 2009 PCAL File 

Power Control Area (PCA) File 

Field Name Description Unit 

1 SEQPCL09 eGRID2012 year 2009 file PCA sequence number 

2 PCAID PCA ID 

3 PCANAME PCA name 

4 NAMEPCAP PCA nameplate capacity MW 

5 PCHTIAN PCA annual heat input MMBtu 

6 PCHTIOZ PCA ozone season heat input MMBtu 

7 PCNGENAN PCA annual net generation MWh 

8 PCNGENOZ PCA ozone season net generation MWh 

9 PCNOXAN PCA annual NOx emissions tons 

10 PCNOXOZ PCA ozone season NOx emissions tons 

11 PCSO2AN PCA annual SO2 emissions tons 

12 PCCO2AN PCA annual CO2 emissions tons 

13 PCCH4AN PCA annual CH4 emissions lbs 

14 PCN2OAN PCA annual N2O emissions lbs 

15 PCCO2EQA PCA annual CO2 equivalent emissions tons 

16 PCHGAN PCA annual Hg emissions lbs 

17 PCNOXRTA PCA annual NOx total output emission rate lb/MWh 

18 PCNOXRTO PCA ozone season NOx total output emission rate lb/MWh 

19 PCSO2RTA PCA annual SO2 total output emission rate lb/MWh 

20 PCCO2RTA PCA annual CO2 total output emission rate lb/MWh 

21 PCCH4RTA PCA annual CH4 total output emission rate lb/GWh 

22 PCN2ORTA PCA annual N2O total output emission rate lb/GWh 

23 PCC2ERTA PCA annual CO2 equivalent total output emission rate lb/MWh 

24 PCHGRTA PCA annual Hg total output emission rate lb/GWh 

25 PCNOXRA PCA annual NOx input emission rate lb/MMBtu 

26 PCNOXRO PCA ozone season NOx input emission rate lb/MMBtu 

27 PCSO2RA PCA annual SO2 input emission rate lb/MMBtu 

28 PCCO2RA PCA annual CO2 input emission rate lb/MMBtu 

29 PCHGRA PCA annual Hg input emission rate lb/BBtu 

30 PCNOXCRT PCA annual NOx combustion output emission rate lb/MWh 

31 PCNOXCRO PCA ozone season NOx combustion output emission rate lb/MWh 

32 PCSO2CRT PCA annual SO2 combustion output emission rate lb/MWh 

33 PCCO2CRT PCA annual CO2 combustion output emission rate lb/MWh 

34 PCCH4CRT PCA annual CH4 combustion output emission rate lb/GWh 

35 PCN2OCRT PCA annual N2O combustion output emission rate lb/GWh 

36 PCHGCRT PCA annual Hg combustion output emission rate lb/GWh 

37 PCCNOXRT PCA annual NOx coal output emission rate lb/MWh 

38 PCONOXRT PCA annual NOx oil output emission rate lb/MWh 

39 PCGNOXRT PCA annual NOx gas output emission rate lb/MWh 

40 PCFSNXRT PCA annual NOx fossil fuel output emission rate lb/MWh 

41 PCCNXORT PCA ozone season NOx coal output emission rate lb/MWh 

42 PCONXORT PCA ozone season NOx oil output emission rate lb/MWh 

43 PCGNXORT PCA ozone season NOx gas output emission rate lb/MWh 

44 PCFSNORT PCA ozone season NOx fossil fuel output emission rate lb/MWh 

45 PCCSO2RT PCA annual SO2 coal output emission rate lb/MWh 

46 PCOSO2RT PCA annual SO2 oil output emission rate lb/MWh 

47 PCGSO2RT PCA annual SO2 gas output emission rate lb/MWh 
A-11 

Table A-1 

eGRID2012 Version 1.0 File Structure 

Year 2009 PCAL File 

Power Control Area (PCA) File (continued). 

Field Name Description Unit 

48 PCFSS2RT PCA annual SO2 fossil fuel output emission rate lb/MWh 

49 PCCCO2RT PCA annual CO2 coal output emission rate lb/MWh 

50 PCOCO2RT PCA annual CO2 oil output emission rate lb/MWh 

51 PCGCO2RT PCA annual CO2 gas output emission rate lb/MWh 

52 PCFSC2RT PCA annual CO2 fossil fuel output emission rate lb/MWh 

53 PCCHGRT PCA annual Hg coal output emission rate lb/GWh 

54 PCFSHGRT PCA annual Hg fossil fuel output emission rate lb/GWh 

55 PCCNOXR PCA annual NOx coal input emission rate lb/MMBtu 

56 PCONOXR PCA annual NOx oil input emission rate lb/MMBtu 

57 PCGNOXR PCA annual NOx gas input emission rate lb/MMBtu 

58 PCFSNXR PCA annual NOx fossil fuel input emission rate lb/MMBtu 

59 PCCNXOR PCA ozone season NOx coal input emission rate lb/MMBtu 

60 PCONXOR PCA ozone season NOx oil input emission rate lb/MMBtu 

61 PCGNXOR PCA ozone season NOx gas input emission rate lb/MMBtu 

62 PCFSNOR PCA ozone season NOx fossil fuel input emission rate lb/MMBtu 

63 PCCSO2R PCA annual SO2 coal input emission rate lb/MMBtu 

64 PCOSO2R PCA annual SO2 oil input emission rate lb/MMBtu 

65 PCGSO2R PCA annual SO2 gas input emission rate lb/MMBtu 

66 PCFSS2R PCA annual SO2 fossil fuel input emission rate lb/MMBtu 

67 PCCCO2R PCA annual CO2 coal input emission rate lb/MMBtu 

68 PCOCO2R PCA annual CO2 oil input emission rate lb/MMBtu 

69 PCGCO2R PCA annual CO2 gas input emission rate lb/MMBtu 

70 PCFSC2R PCA annual CO2 fossil fuel input emission rate lb/MMBtu 

71 PCCHGR PCA annual Hg coal input emission rate lb/BBtu 

72 PCFSHGR PCA annual Hg fossil fuel input emission rate lb/BBtu 

73 PCNBNOX PCA annual NOx non-baseload output emission rate lb/MWh 

74 PCNBNXO PCA ozone season NOx non-baseload output emission rate lb/MWh 

75 PCNBSO2 PCA annual SO2 non-baseload output emission rate lb/MWh 

76 PCNBCO2 PCA annual CO2 non-baseload output emission rate lb/MWh 

77 PCNBCH4 PCA annual CH4 non-baseload output emission rate lb/GWh 

78 PCNBN2O PCA annual N2O non-baseload output emission rate lb/GWh 

79 PCNBHG PCA annual Hg non-baseload output emission rate lb/GWh 

80 PCGENACL PCA annual coal net generation MWh 

81 PCGENAOL PCA annual oil net generation MWh 

82 PCGENAGS PCA annual gas net generation MWh 

83 PCGENANC PCA annual nuclear net generation MWh 

84 PCGENAHY PCA annual hydro net generation MWh 

85 PCGENABM PCA annual biomass net generation MWh 

86 PCGENAWI PCA annual wind net generation MWh 

87 PCGENASO PCA annual solar net generation MWh 

88 PCGENAGT PCA annual geothermal net generation MWh 

89 PCGENAOF PCA annual other fossil net generation MWh 

90 PCGENAOP PCA annual other unknown/purchased fuel net generation MWh 

91 PCGENATN PCA annual total nonrenewables net generation MWh 

92 PCGENATR PCA annual total renewables net generation MWh 

93 PCGENATH PCA annual total nonhydro renewables net generation MWh 

94 PCGENACY PCA annual total combustion net generation MWh 
A-12 

Table A-1 

eGRID2012 Version 1.0 File Structure 

Year 2009 PCAL File 

Power Control Area (PCA) File (continued). 

Field Name Description Unit 

95 PCGENACN PCA annual total noncombustion net generation MWh 

96 PCCLPR PCA coal generation percent (resource mix) 

97 PCOLPR PCA oil generation percent (resource mix) 

98 PCGSPR PCA gas generation percent (resource mix) 

99 PCNCPR PCA nuclear generation percent (resource mix) 

100 PCHYPR PCA hydro generation percent (resource mix) 

101 PCBMPR PCA biomass generation percent (resource mix) 

102 PCWIPR PCA wind generation percent (resource mix) 

103 PCSOPR PCA solar generation percent (resource mix) 

104 PCGTPR PCA geothermal generation percent (resource mix) 

105 PCOFPR PCA other fossil generation percent (resource mix) 

106 PCOPPR PCA other unknown/purchased fuel generation percent (resource mix) 

107 PCTNPR PCA total nonrenewables generation percent (resource mix) 

108 PCTRPR PCA total renewables generation percent (resource mix) 

109 PCTHPR PCA total nonhydro renewables generation percent (resource mix) 

110 PCCYPR PCA total combustion generation percent (resource mix) 

111 PCCNPR PCA total noncombustion generation percent (resource mix) 
A-13 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 SRL File 

eGRID Subregion File 

Field Name Description Unit 

1 SEQSRL09 eGRID2012 year 2009 file eGRID subregion sequence number 

2 SUBRGN eGRID subregion acronym 

3 SRNAME eGRID subregion name 

4 NERC NERC region acronym associated with the eGRID subregion acronym 

5 NAMEPCAP eGRID subregion nameplate capacity MW 

6 SRHTIAN eGRID subregion annual heat input MMBtu 

7 SRHTIOZ eGRID subregion ozone season heat input MMBtu 

8 SRNGENAN eGRID subregion annual net generation MWh 

9 SRNGENOZ eGRID subregion ozone season net generation MWh 

10 SRNOXAN eGRID subregion annual NOx emissions tons 

11 SRNOXOZ eGRID subregion ozone season NOx emissions tons 

12 SRSO2AN eGRID subregion annual SO2 emissions tons 

13 SRCO2AN eGRID subregion annual CO2 emissions tons 

14 SRCH4AN eGRID subregion annual CH4 emissions lbs 

15 SRN2OAN eGRID subregion annual N2O emissions lbs 

16 SRCO2EQA eGRID subregion annual CO2 equivalent emissions tons 

17 SRHGAN eGRID subregion annual Hg emissions lbs 

18 SRNOXRTA eGRID subregion annual NOx total output emission rate lb/MWh 

19 SRNOXRTO eGRID subregion ozone season NOx total output emission rate lb/MWh 

20 SRSO2RTA eGRID subregion annual SO2 total output emission rate lb/MWh 

21 SRCO2RTA eGRID subregion annual CO2 total output emission rate lb/MWh 

22 SRCH4RTA eGRID subregion annual CH4 total output emission rate lb/GWh 

23 SRN2ORTA eGRID subregion annual N2O total output emission rate lb/GWh 

24 SRC2ERTA eGRID subregion annual CO2 equivalent total output emission rate lb/MWh 

25 SRHGRTA eGRID subregion annual Hg total output emission rate lb/GWh 

26 SRNOXRA eGRID subregion annual NOx input emission rate lb/MMBtu 

27 SRNOXRO eGRID subregion ozone season NOx input emission rate lb/MMBtu 

28 SRSO2RA eGRID subregion annual SO2 input emission rate lb/MMBtu 

29 SRCO2RA eGRID subregion annual CO2 input emission rate lb/MMBtu 

30 SRHGRA eGRID subregion annual Hg input emission rate lb/BBtu 

31 SRNOXCRT eGRID subregion annual NOx combustion output emission rate lb/MWh 

32 SRNOXCRO eGRID subregion ozone season NOx combustion output emission rate lb/MWh 

33 SRSO2CRT eGRID subregion annual SO2 combustion output emission rate lb/MWh 

34 SRCO2CRT eGRID subregion annual CO2 combustion output emission rate lb/MWh 

35 SRCH4CRT eGRID subregion annual CH4 combustion output emission rate lb/GWh 

36 SRN2OCRT eGRID subregion annual N2O combustion output emission rate lb/GWh 

37 SRHGCRT eGRID subregion annual Hg combustion output emission rate lb/GWh 

38 SRCNOXRT eGRID subregion annual NOx coal output emission rate lb/MWh 

39 SRONOXRT eGRID subregion annual NOx oil output emission rate lb/MWh 

40 SRGNOXRT eGRID subregion annual NOx gas output emission rate lb/MWh 

41 SRFSNXRT eGRID subregion annual NOx fossil fuel output emission rate lb/MWh 

42 SRCNXORT eGRID subregion ozone season NOx coal output emission rate lb/MWh 

43 SRONXORT eGRID subregion ozone season NOx oil output emission rate lb/MWh 

44 SRGNXORT eGRID subregion ozone season NOx gas output emission rate lb/MWh 

45 SRFSNORT eGRID subregion ozone season NOx fossil fuel output emission rate lb/MWh 

46 SRCSO2RT eGRID subregion annual SO2 coal output emission rate lb/MWh 

47 SROSO2RT eGRID subregion annual SO2 oil output emission rate lb/MWh 
A-14 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 SRL File 

eGRID Subregion File (continued). 

Field Name Description Unit 

48 SRGSO2RT eGRID subregion annual SO2 gas output emission rate lb/MWh 

49 SRFSS2RT eGRID subregion annual SO2 fossil fuel output emission rate lb/MWh 

50 SRCCO2RT eGRID subregion annual CO2 coal output emission rate lb/MWh 

51 SROCO2RT eGRID subregion annual CO2 oil output emission rate lb/MWh 

52 SRGCO2RT eGRID subregion annual CO2 gas output emission rate lb/MWh 

53 SRFSC2RT eGRID subregion annual CO2 fossil fuel output emission rate lb/MWh 

54 SRCHGRT eGRID subregion annual Hg coal output emission rate lb/GWh 

55 SRFSHGRT eGRID subregion annual Hg fossil fuel output emission rate lb/GWh 

56 SRCNOXR eGRID subregion annual NOx coal input emission rate lb/MMBtu 

57 SRONOXR eGRID subregion annual NOx oil input emission rate lb/MMBtu 

58 SRGNOXR eGRID subregion annual NOx gas input emission rate lb/MMBtu 

59 SRFSNXR eGRID subregion annual NOx fossil fuel input emission rate lb/MMBtu 

60 SRCNXOR eGRID subregion ozone season NOx coal input emission rate lb/MMBtu 

61 SRONXOR eGRID subregion ozone season NOx oil input emission rate lb/MMBtu 

62 SRGNXOR eGRID subregion ozone season NOx gas input emission rate lb/MMBtu 

63 SRFSNOR eGRID subregion ozone season NOx fossil fuel input emission rate lb/MMBtu 

64 SRCSO2R eGRID subregion annual SO2 coal input emission rate lb/MMBtu 

65 SROSO2R eGRID subregion annual SO2 oil input emission rate lb/MMBtu 

66 SRGSO2R eGRID subregion annual SO2 gas input emission rate lb/MMBtu 

67 SRFSS2R eGRID subregion annual SO2 fossil fuel input emission rate lb/MMBtu 

68 SRCCO2R eGRID subregion annual CO2 coal input emission rate lb/MMBtu 

69 SROCO2R eGRID subregion annual CO2 oil input emission rate lb/MMBtu 

70 SRGCO2R eGRID subregion annual CO2 gas input emission rate lb/MMBtu 

71 SRFSC2R eGRID subregion annual CO2 fossil fuel input emission rate lb/MMBtu 

72 SRCHGR eGRID subregion annual Hg coal input emission rate lb/BBtu 

73 SRFSHGR eGRID subregion annual Hg fossil fuel input emission rate lb/BBtu 

74 SRNBNOX eGRID subregion annual NOx non-baseload output emission rate lb/MWh 

75 SRNBNXO eGRID subregion ozone season NOx non-baseload output emission rate lb/MWh 

76 SRNBSO2 eGRID subregion annual SO2 non-baseload output emission rate lb/MWh 

77 SRNBCO2 eGRID subregion annual CO2 non-baseload output emission rate lb/MWh 

78 SRNBCH4 eGRID subregion annual CH4 non-baseload output emission rate lb/GWh 

79 SRNBN2O eGRID subregion annual N2O non-baseload output emission rate lb/GWh 

80 SRNBC2ER eGRID subregion annual CO2 equivalent non-baseload output emission rate lb/MWh 

81 SRNBHG eGRID subregion annual Hg non-baseload output emission rate lb/GWh 

82 SRGENACL eGRID subregion annual coal net generation MWh 

83 SRGENAOL eGRID subregion annual oil net generation MWh 

84 SRGENAGS eGRID subregion annual gas net generation MWh 

85 SRGENANC eGRID subregion annual nuclear net generation MWh 

86 SRGENAHY eGRID subregion annual hydro net generation MWh 

87 SRGENABM eGRID subregion annual biomass net generation MWh 

88 SRGENAWI eGRID subregion annual wind net generation MWh 

89 SRGENASO eGRID subregion annual solar net generation MWh 

90 SRGENAGT eGRID subregion annual geothermal net generation MWh 

91 SRGENAOF eGRID subregion annual other fossil net generation MWh 

92 SRGENAOP eGRID subregion annual other unknown/purchased fuel net generation MWh 

93 SRGENATN eGRID subregion annual total nonrenewables net generation MWh 

94 SRGENATR eGRID subregion annual total renewables net generation MWh 
A-15 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 SRL File 

eGRID Subregion File (continued). 

Field Name Description Unit 

95 SRGENATH eGRID subregion annual total nonhydro renewables net generation MWh 

96 SRGENACY eGRID subregion annual total combustion net generation MWh 

97 SRGENACN eGRID subregion annual total noncombustion net generation MWh 

98 SRCLPR eGRID subregion coal generation percent (resource mix) 

99 SROLPR eGRID subregion oil generation percent (resource mix) 

100 SRGSPR eGRID subregion gas generation percent (resource mix) 

101 SRNCPR eGRID subregion nuclear generation percent (resource mix) 

102 SRHYPR eGRID subregion hydro generation percent (resource mix) 

103 SRBMPR eGRID subregion biomass generation percent (resource mix) 

104 SRWIPR eGRID subregion wind generation percent (resource mix) 

105 SRSOPR eGRID subregion solar generation percent (resource mix) 

106 SRGTPR eGRID subregion geothermal generation percent (resource mix) 

107 SROFPR eGRID subregion other fossil generation percent (resource mix) 

108 SROPPR eGRID subregion other unknown/purchased fuel generation percent (resource mix) 

109 SRTNPR eGRID subregion total nonrenewables generation percent (resource mix) 

110 SRTRPR eGRID subregion total renewables generation percent (resource mix) 

111 SRTHPR eGRID subregion total nonhydro renewables generation percent (resource mix) 

112 SRCYPR eGRID subregion total combustion generation percent (resource mix) 

113 SRCNPR eGRID subregion total noncombustion generation percent (resource mix) 
A-16 

Table A-1 

eGRID2012 Version 1.0 File Structure 

Year 2009 NRL File 

NERC Region File 

Field Name Description Unit 

1 SEQNRL09 eGRID2012 year 2009 file NERC region sequence number 

2 NERC NERC region acronym 

3 NERCNAME NERC region name 

4 NAMEPCAP NERC region nameplate capacity MW 

5 NRHTIAN NERC region annual heat input MMBtu 

6 NRHTIOZ NERC region ozone season heat input MMBtu 

7 NRNGENAN NERC region annual net generation MWh 

8 NRNGENOZ NERC region ozone season net generation MWh 

9 NRNOXAN NERC region annual NOx emissions tons 

10 NRNOXOZ NERC region ozone season NOx emissions tons 

11 NRSO2AN NERC region annual SO2 emissions tons 

12 NRCO2AN NERC region annual CO2 emissions tons 

13 NRCH4AN NERC region annual CH4 emissions lbs 

14 NRN2OAN NERC region annual N2O emissions lbs 

15 NRCO2EQA NERC region annual CO2 equivalent emissions tons 

16 NRHGAN NERC region annual Hg emissions lbs 

17 NRNOXRTA NERC region annual NOx total output emission rate lb/MWh 

18 NRNOXRTO NERC region ozone season NOx total output emission rate lb/MWh 

19 NRSO2RTA NERC region annual SO2 total output emission rate lb/MWh 

20 NRCO2RTA NERC region annual CO2 total output emission rate lb/MWh 

21 NRCH4RTA NERC region annual CH4 total output emission rate lb/GWh 

22 NRN2ORTA NERC region annual N2O total output emission rate lb/GWh 

23 NRC2ERTA NERC region annual CO2 equivalent total output emission rate lb/MWh 

24 NRHGRTA NERC region annual Hg total output emission rate lb/GWh 

25 NRNOXRA NERC region annual NOx input emission rate lb/MMBtu 

26 NRNOXRO NERC region ozone season NOx input emission rate lb/MMBtu 

27 NRSO2RA NERC region annual SO2 input emission rate lb/MMBtu 

28 NRCO2RA NERC region annual CO2 input emission rate lb/MMBtu 

29 NRHGRA NERC region annual Hg input emission rate lb/BBtu 

30 NRNOXCRT NERC region annual NOx combustion output emission rate lb/MWh 

31 NRNOXCRO NERC region ozone season NOx combustion output emission rate lb/MWh 

32 NRSO2CRT NERC region annual SO2 combustion output emission rate lb/MWh 

33 NRCO2CRT NERC region annual CO2 combustion output emission rate lb/MWh 

34 NRCH4CRT NERC region annual CH4 combustion output emission rate lb/GWh 

35 NRN2OCRT NERC region annual N2O combustion output emission rate lb/GWh 

36 NRHGCRT NERC region annual Hg combustion output emission rate lb/GWh 

37 NRCNOXRT NERC region annual NOx coal output emission rate lb/MWh 

38 NRONOXRT NERC region annual NOx oil output emission rate lb/MWh 

39 NRGNOXRT NERC region annual NOx gas output emission rate lb/MWh 

40 NRFSNXRT NERC region annual NOx fossil fuel output emission rate lb/MWh 

41 NRCNXORT NERC region ozone season NOx coal output emission rate lb/MWh 

42 NRONXORT NERC region ozone season NOx oil output emission rate lb/MWh 

43 NRGNXORT NERC region ozone season NOx gas output emission rate lb/MWh 

44 NRFSNORT NERC region ozone season NOx fossil fuel output emission rate lb/MWh 

45 NRCSO2RT NERC region annual SO2 coal output emission rate lb/MWh 

46 NROSO2RT NERC region annual SO2 oil output emission rate lb/MWh 

47 NRGSO2RT NERC region annual SO2 gas output emission rate lb/MWh 
A-17 

Table A-1 

eGRID2012 Version 1.0 File Structure 

Year 2009 NRL File 

NERC Region File (continued). 

Field Name Description Unit 

48 NRFSS2RT NERC region annual SO2 fossil fuel output emission rate lb/MWh 

49 NRCCO2RT NERC region annual CO2 coal output emission rate lb/MWh 

50 NROCO2RT NERC region annual CO2 oil output emission rate lb/MWh 

51 NRGCO2RT NERC region annual CO2 gas output emission rate lb/MWh 

52 NRFSC2RT NERC region annual CO2 fossil fuel output emission rate lb/MWh 

53 NRCHGRT NERC region annual Hg coal output emission rate lb/GWh 

54 NRFSHGRT NERC region annual Hg fossil fuel output emission rate lb/GWh 

55 NRCNOXR NERC region annual NOx coal input emission rate lb/MMBtu 

56 NRONOXR NERC region annual NOx oil input emission rate lb/MMBtu 

57 NRGNOXR NERC region annual NOx gas input emission rate lb/MMBtu 

58 NRFSNXR NERC region annual NOx fossil fuel input emission rate lb/MMBtu 

59 NRCNXOR NERC region ozone season NOx coal input emission rate lb/MMBtu 

60 NRONXOR NERC region ozone season NOx oil input emission rate lb/MMBtu 

61 NRGNXOR NERC region ozone season NOx gas input emission rate lb/MMBtu 

62 NRFSNOR NERC region ozone season NOx fossil fuel input emission rate lb/MMBtu 

63 NRCSO2R NERC region annual SO2 coal input emission rate lb/MMBtu 

64 NROSO2R NERC region annual SO2 oil input emission rate lb/MMBtu 

65 NRGSO2R NERC region annual SO2 gas input emission rate lb/MMBtu 

66 NRFSS2R NERC region annual SO2 fossil fuel input emission rate lb/MMBtu 

67 NRCCO2R NERC region annual CO2 coal input emission rate lb/MMBtu 

68 NROCO2R NERC region annual CO2 oil input emission rate lb/MMBtu 

69 NRGCO2R NERC region annual CO2 gas input emission rate lb/MMBtu 

70 NRFSC2R NERC region annual CO2 fossil fuel input emission rate lb/MMBtu 

71 NRCHGR NERC region annual Hg coal input emission rate lb/BBtu 

72 NRFSHGR NERC region annual Hg fossil fuel input emission rate lb/BBtu 

73 NRNBNOX NERC region annual NOx non-baseload output emission rate lb/MWh 

74 NRNBNXO NERC region ozone season NOx non-baseload output emission rate lb/MWh 

75 NRNBSO2 NERC region annual SO2 non-baseload output emission rate lb/MWh 

76 NRNBCO2 NERC region annual CO2 non-baseload output emission rate lb/MWh 

77 NRNBCH4 NERC region annual CH4 non-baseload output emission rate lb/GWh 

78 NRNBN2O NERC region annual N2O non-baseload output emission rate lb/GWh 

79 NRNBHG NERC region annual Hg non-baseload output emission rate lb/GWh 

80 NRGENACL NERC region annual coal net generation MWh 

81 NRGENAOL NERC region annual oil net generation MWh 

82 NRGENAGS NERC region annual gas net generation MWh 

83 NRGENANC NERC region annual nuclear net generation MWh 

84 NRGENAHY NERC region annual hydro net generation MWh 

85 NRGENABM NERC region annual biomass net generation MWh 

86 NRGENAWI NERC region annual wind net generation MWh 

87 NRGENASO NERC region annual solar net generation MWh 

88 NRGENAGT NERC region annual geothermal net generation MWh 

89 NRGENAOF NERC region annual other fossil net generation MWh 

90 NRGENAOP NERC region annual other unknown/purchased fuel net generation MWh 

91 NRGENATN NERC region annual total nonrenewables net generation MWh 

92 NRGENATR NERC region annual total renewables net generation MWh 

93 NRGENATH NERC region annual total nonhydro renewables net generation MWh 

94 NRGENACY NERC region annual total combustion net generation MWh 
A-18 

Table A-1 

eGRID2012 Version 1.0 File Structure 

Year 2009 NRL File 

NERC Region File (continued). 

Field Name Description Unit 

95 NRGENACN NERC region annual total noncombustion net generation MWh 

96 NRCLPR NERC region coal generation percent (resource mix) 

97 NROLPR NERC region oil generation percent (resource mix) 

98 NRGSPR NERC region gas generation percent (resource mix) 

99 NRNCPR NERC region nuclear generation percent (resource mix) 

100 NRHYPR NERC region hydro generation percent (resource mix) 

101 NRBMPR NERC region biomass generation percent (resource mix) 

102 NRWIPR NERC region wind generation percent (resource mix) 

103 NRSOPR NERC region solar generation percent (resource mix) 

104 NRGTPR NERC region geothermal generation percent (resource mix) 

105 NROFPR NERC region other fossil generation percent (resource mix) 

106 NROPPR NERC region other unknown/purchased fuel generation percent (resource mix) 

107 NRTNPR NERC region total nonrenewables generation percent (resource mix) 

108 NRTRPR NERC region total renewables generation percent (resource mix) 

109 NRTHPR NERC region total nonhydro renewables generation percent (resource mix) 

110 NRCYPR NERC region total combustion generation percent (resource mix) 

111 NRCNPR NERC region total noncombustion generation percent (resource mix) 
A-19 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 U.S. File 

United States File 

Field Name Description Unit Source(s) 

1 SEQUS09 eGRID2012 year 2009 file U.S. sequence number 

2 NAMEPCAP U.S. nameplate capacity MW 

3 USHTIAN U.S. annual heat input MMBtu 

4 USHTIOZ U.S. ozone season heat input MMBtu 

5 USNGENAN U.S. annual net generation MWh 

6 USNGENOZ U.S. ozone season net generation MWh 

7 USNOXAN U.S. annual NOx emissions tons 

8 USNOXOZ U.S. ozone season NOx emissions tons 

9 USSO2AN U.S. annual SO2 emissions tons 

10 USCO2AN U.S. annual CO2 emissions tons 

11 USCH4AN U.S. annual CH4 emissions lbs 

12 USN2OAN U.S. annual N2O emissions lbs 

13 USCO2EQA U.S. annual CO2 equivalent emissions tons 

14 USHGAN U.S. annual Hg emissions lbs 

15 USNOXRTA U.S. annual NOx total output emission rate lb/MWh 

16 USNOXRTO U.S. ozone season NOx total output emission rate lb/MWh 

17 USSO2RTA U.S. annual SO2 total output emission rate lb/MWh 

18 USCO2RTA U.S. annual CO2 total output emission rate lb/MWh 

19 USCH4RTA U.S. annual CH4 total output emission rate lb/GWh 

20 USN2ORTA U.S. annual N2O total output emission rate lb/GWh 

21 USC2ERTA U.S. annual CO2 equivalent total output emission rate lb/MWh 

22 USHGRTA U.S. annual Hg total output emission rate lb/GWh 

23 USNOXRA U.S. annual NOx input emission rate lb/MMBtu 

24 USNOXRO U.S. ozone season NOx input emission rate lb/MMBtu 

25 USSO2RA U.S. annual SO2 input emission rate lb/MMBtu 

26 USCO2RA U.S. annual CO2 input emission rate lb/MMBtu 

27 USHGRA U.S. annual Hg input emission rate lb/BBtu 

28 USNOXCRT U.S. annual NOx combustion output emission rate lb/MWh 

29 USNOXCRO U.S. ozone season NOx combustion output emission rate lb/MWh 

30 USSO2CRT U.S. annual SO2 combustion output emission rate lb/MWh 

31 USCO2CRT U.S. annual CO2 combustion output emission rate lb/MWh 

32 USCH4CRT U.S. annual CH4 combustion output emission rate lb/GWh 

33 USN2OCRT U.S. annual N2O combustion output emission rate lb/GWh 

34 USHGCRT U.S. annual Hg combustion output emission rate lb/GWh 

35 USCNOXRT U.S. annual NOx coal output emission rate lb/MWh 

36 USONOXRT U.S. annual NOx oil output emission rate lb/MWh 

37 USGNOXRT U.S. annual NOx gas output emission rate lb/MWh 

38 USFSNXRT U.S. annual NOx fossil fuel output emission rate lb/MWh 

39 USCNXORT U.S. ozone season NOx coal output emission rate lb/MWh 

40 USONXORT U.S. ozone season NOx oil output emission rate lb/MWh 

41 USGNXORT U.S. ozone season NOx gas output emission rate lb/MWh 

42 USFSNORT U.S. ozone season NOx fossil fuel output emission rate lb/MWh 
A-20 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 U.S. File 

United States File (continued). 

Field Name Description Unit Source(s) 

43 USCSO2RT U.S. annual SO2 coal output emission rate lb/MWh 

44 USOSO2RT U.S. annual SO2 oil output emission rate lb/MWh 

45 USGSO2RT U.S. annual SO2 gas output emission rate lb/MWh 

46 USFSS2RT U.S. annual SO2 fossil fuel output emission rate lb/MWh 

47 USCCO2RT U.S. annual CO2 coal output emission rate lb/MWh 

48 USOCO2RT U.S. annual CO2 oil output emission rate lb/MWh 

49 USGCO2RT U.S. annual CO2 gas output emission rate lb/MWh 

50 USFSC2RT U.S. annual CO2 fossil fuel output emission rate lb/MWh 

51 USCHGRT U.S. annual Hg coal output emission rate lb/GWh 

52 USFSHGRT U.S. annual Hg fossil fuel output emission rate lb/GWh 

53 USCNOXR U.S. annual NOx coal input emission rate lb/MMBtu 

54 USONOXR U.S. annual NOx oil input emission rate lb/MMBtu 

55 USGNOXR U.S. annual NOx gas input emission rate lb/MMBtu 

56 USFSNXR U.S. annual NOx fossil fuel input emission rate lb/MMBtu 

57 USCNXOR U.S. ozone season NOx coal input emission rate lb/MMBtu 

58 USONXOR U.S. ozone season NOx oil input emission rate lb/MMBtu 

59 USGNXOR U.S. ozone season NOx gas input emission rate lb/MMBtu 

60 USFSNOR U.S. ozone season NOx fossil fuel input emission rate lb/MMBtu 

61 USCSO2R U.S. annual SO2 coal input emission rate lb/MMBtu 

62 USOSO2R U.S. annual SO2 oil input emission rate lb/MMBtu 

63 USGSO2R U.S. annual SO2 gas input emission rate lb/MMBtu 

64 USFSS2R U.S. annual SO2 fossil fuel input emission rate lb/MMBtu 

65 USCCO2R U.S. annual CO2 coal input emission rate lb/MMBtu 

66 USOCO2R U.S. annual CO2 oil input emission rate lb/MMBtu 

67 USGCO2R U.S. annual CO2 gas input emission rate lb/MMBtu 

68 USFSC2R U.S. annual CO2 fossil fuel input emission rate lb/MMBtu 

69 USCHGR U.S. annual Hg coal input emission rate lb/BBtu 

70 USFSHGR U.S. annual Hg fossil fuel input emission rate lb/BBtu 

71 USNBNOX U.S. annual NOx non-baseload output emission rate lb/MWh 

72 USNBNXO U.S. ozone season NOx non-baseload output emission rate lb/MWh 

73 USNBSO2 U.S. annual SO2 non-baseload output emission rate lb/MWh 

74 USNBCO2 U.S. annual CO2 non-baseload output emission rate lb/MWh 

75 USNBCH4 U.S. annual CH4 non-baseload output emission rate lb/GWh 

76 USNBN2O U.S. annual N2O non-baseload output emission rate lb/GWh 

77 USNBHG U.S. annual Hg non-baseload output emission rate lb/GWh 

78 USGENACL U.S. annual coal net generation MWh 

79 USGENAOL U.S. annual oil net generation MWh 

80 USGENAGS U.S. annual gas net generation MWh 

81 USGENANC U.S. annual nuclear net generation MWh 

82 USGENAHY U.S. annual hydro net generation MWh 

83 USGENABM U.S. annual biomass net generation MWh 

84 USGENAWI U.S. annual wind net generation MWh 

85 USGENASO U.S. annual solar net generation MWh 

86 USGENAGT U.S. annual geothermal net generation MWh 

87 USGENAOF U.S. annual other fossil net generation MWh 

88 USGENAOP U.S. annual other unknown/purchased fuel net generation MWh 
A-21 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 U.S. File 

United States File (continued). 

Field Name Description Unit Source(s) 

89 USGENATN U.S. annual total nonrenewables net generation MWh 

90 USGENATR U.S. annual total renewables net generation MWh 

91 USGENATH U.S. annual total nonhydro renewables net generation MWh 

92 USGENACY U.S. annual total combustion net generation MWh 

93 USGENACN U.S. annual total noncombustion net generation MWh 

94 USCLPR U.S. coal generation percent (resource mix) 

95 USOLPR U.S. oil generation percent (resource mix) 

96 USGSPR U.S. gas generation percent (resource mix) 

97 USNCPR U.S. nuclear generation percent (resource mix) 

98 USHYPR U.S. hydro generation percent (resource mix) 

99 USBMPR U.S. biomass generation percent (resource mix) 

100 USWIPR U.S. wind generation percent (resource mix) 

101 USSOPR U.S. solar generation percent (resource mix) 

102 USGTPR U.S. geothermal generation percent (resource mix) 

103 USOFPR U.S. other fossil generation percent (resource mix) 

104 USOPPR U.S. other unknown/purchased fuel generation percent 

(resource mix) 

 

105 USTNPR U.S. total nonrenewables generation percent (resource mix) 

106 USTRPR U.S. total renewables generation percent (resource mix) 

107 USTHPR U.S. total nonhydro renewables generation percent (resource 

mix) 

 

108 USCYPR U.S. total combustion generation percent (resource mix) 

109 USCNPR U.S. total noncombustion generation percent (resource mix) 
A-22 

Table A-1

eGRID2012 Version 1.0 File Structure 

Year 2009 GGL File 

Grid Gross Loss (%) File 

Field Name Description Unit Source(s) 

1 REGION One of the three interconnect power grids in the U.S. (plus 

Alaska, Hawaii, and the entire U.S.) 

 

2 GENERAT The regional total net generation MWh 2009 FERC-714 updated 

by EIA, but eGRID yr 

2009 net generation for 

ASCC and HICC 

3 FRGNINTC The regional net foreign interchange with Canada and 

Mexico (imports are positive) 

MWh 2009 FERC-714 updated 

by EIA 

4 INTRCHNG The regional total net interchange with a different U.S. 

region (imports are positive) 

MWh 2009 FERC-714 + 

updates 

5 CONSUMP The regional total consumption MWh 2009 EIA-861 Files 1 & 2 

+ updates 

6 GGRSLOSS The estimated regional grid gross loss as a percent [= 

100 * (GENERAT + FRGNINTC+ INTRCHNG - 

CONSUMP) / GENERAT) ] 

% 

7 YEAR Data year 
B-1 

APPENDIX B. eGRID2012 eGRID SUBREGION AND NERC 

REGION REPRESENTATIONAL MAPS 

Figure B-1. eGRID2012 eGRID Subregion Representational Map 

This is a representational map; many of the boundaries shown on this map are approximate because they are based 

on companies, not on strictly geographical boundaries. 
B-2 

Figure B-2. eGRID2012 NERC Region Representational Map 

This is a representational map; many of the boundaries shown on this map are approximate because they are based 

on companies, not on strictly geographical boundaries.