## T HE 

## E MISSIONS 

## & G ENERATION 

## R ESOURCE 

## I NTEGRATED 

## D ATABASE

FOR 

## 2012 (eGRID2012) T ECHNICAL 

## S UPPORT 

## D OCUMENT

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. 2-04i 

## 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 pub lic through the EPA eGRID website at http://www.epa.gov/egrid

.



## ACKNOWLEDGMENTS

This edition of eGRID was developed under the lead ership of EPA’s Mr. Art Diem, Clean Air Markets Division (CAMD), and TranSystems|E.H. Pechan’ eGRI D 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 valuab le analysis and support. The eGRID system was conceived of by Mr. Rick Morgan, former EPA Seni or 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 Estim ates for Y ear 200 9 ................................................................... 9 2. Annual Emission Estimates for CO 2 , SO 2 , and NO

x ......................................................... 10 3. Annual Emission Estimates for CH 4 and N 2 O .................................................................. 11 4. Annual Emission Estimates for Mercury (Hg) ................................................................. 11 5. Ozone Season Emission Estimates for NO

x ...................................................................... 12 6. Adjusted Emission Estimates ............................................................................................ 12 7. Adjustments fo r 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 ............................................................................................................. 2 4 3. Power Control Area .......................................................................................................... 2 5 F. TREATMENT OF AGGREGATION LEVELS .............................................................. 32

SECTION IV. SPECIFIC eGRID IDENTIFIER CO DES, NAME CHANGES A ND 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 ................................................................ 66iii 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 W aste 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 Fu el Generation Category .......................................................................... 2 2 Table III-7 NERC Region Acronym and Names for eGRID .............................................................. 24 Table III-8 eGRID Subregion Acro nym and Names for eGRID ........................................................ 25 Table III-9 PCA – NERC Region Relationship .................................................................................. 2 6 Table III-10 PCA – MISO – eGRID Subreg ion – 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 Subreg ion Representational Map ................................................... B-1 Figure B-2 eGRID2012 NERC Region Representational Map ......................................................... B-2iv [This page intentionally left blank.]v 

## ABBREVIATIONS AND ACRONYMS

40 CFR Part 75 Code of Federa l Regulations Title 40 Part 75, which specifies the air emissions monitoring and reporting requirement s delineated in EPA regulations AB 32 Assembly Bill 32 - California Global Warming Solutions Act AR4 Fourth Intergovernmental Pane l 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) CH 4 Methane CO 2 Carbon dioxide CO 2 e Carbon dioxide equivalent DOE U.S. Department of Energy EEA Energy and Environmental Analysis, an ICF International Company EF Emission factor eGRID Emissions & Generation R esource Integrated Database eGRID96 Emissions & Generation Resource In tegrated Database for the year 1996 (1995 data) eGRID97 Emissions & Generation Resource In tegrated Database for the year 1997 (1995-1996 data) eGRID2000 Emissions & Generation Resource In tegrated Database for the year 2000 (1996-1998 data) eGRID2002 Emissions & Generation Resource In tegrated Database for the year 2002 (1996-2000 data) eGRID2006 Emissions & Generation Resource In tegrated Database for the year 2006 (2004 data) eGRID2007 Emissions & Generation Resource In tegrated Database for the year 2007 (2004 and 2005 data) eGRID2010 Emissions & Generation Resource In tegrated Database for the year 2010 (2007 and 2005 and 2004 data) eGRID2012 Emissions & Generation Resource In tegrated 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 Internationalvi 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 Sequest ration 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 NO x Nitrogen oxides NREL National Renewable Energy Laboratory N 2 O 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 Pane l on Climate Change Assessment SAS Statistical Analysis System SO 2 Sulfur dioxide TAR Third Intergovernmental Pane l on Climate Change Assessment TS|Pechan TranSystems|E.H. Pechan, form erly E.H. Pechan & Associates, Inc. USBIA U.S. Bureau of Indian Affairs USBR U.S. Bureau of Reclamation USCE U.S. Army Corps of Engineers1 

## SECTION I. INTRODUCTION

The Emissions & Generation Resource Integrated Database (eGRID) is a comprehensive source of data on the environmental characteristics of almost all el ectric power generated in the United States. The preeminent source of emissions data for the elect ric 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 incl ude generation in megawatt-hour (MWh); resource mix (for renewable and nonrenewable generation); emissions in tons for carbon dioxide (CO 2 ), nitrogen oxides (NO
x ), and sulfur dioxide (SO 2 ); emissions in pounds for methane (CH 4 ), nitrous oxide (N 2 O) and mercury (Hg); emission rates for CO 2 , NO x , and SO 2 (in both pounds per megawatt-hour [lb/MWh]) and pounds per million British thermal unit [lb/MMBtu]) and for CH 4 , N 2 O, and Hg (in pounds per gigawatthour [lb/GWh]) and Hg (in pounds per billion Btu [l b/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 NO
x emissions and emission rates, net generation a nd resource mix, and heat input) at different levels of aggregation (plant, companie s, and grid regions of the country).

The newest and eighth edition of eGRID, eGRID2012 Ve rsion 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 represen ts 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 firs t 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 pl ant 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, parentcompany 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 Oct ober 2008 and Version 1.1 was released in January 2009, both with two Excel work books 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 for2 years 2004 and 2005 (the same as those incl uded 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 downloade d 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 a nd 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/conf erence/ei18/session5/rothschild.pdf , or downloaded from the eGRIDweb Reports tab. The second one, “The Va lue of eGRID and eGRIDweb to GHG Inventories” (Rothschild. Diem, Quiroz, and Salhotra, 2010), pr esented at the EUEC 2010 Environmental Conference, is available for download from the eGRID website at http://www.epa.gov/cleanenergy/documents/e gridzips/The_Value_of_eGRID_Dec_2009.pdf

. The third one, “eGRID: An Efficient Way to Va lue 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 Ca rbon 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 Wh ich eGRID Data Year of GHG Emission Factors: Several Scenarios Presented” (Diem, Rothschild, a nd 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 c ontrol. Accurate matching of entit ies from different databases required great care, even where identification codes were availa ble. 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 eGRID2 012 year 2009 data elements in the 8 Excel spreadsheet files for each level of aggregation, as we ll as the grid gross loss file. Section II provides a summary of the database; Section III is the Me thodology Section and presents the methodology for emissions estimations, including adjustments for bi omass and combined heat and power (CHP), among other issues; Section IV includes discussion of eGRI D 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 in cludes the file structure, and Appendix B, which includes the eGRID subregion and NERC region re presentational 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 leve ls of aggregation. As the database name implies, the focus of the data files is on two areas: gene ration and emissions. Gene ration is expressed in both MWh and as a percentage (called “resource mix” – gene ration of a certain fuel or resource type divided by total generation). CO 2 , NO x , and SO 2 emissions are expressed in tons and CH 4, N 2 O, and Hg emissions are expressed in pounds. Emission rates ar e expressed in lb/MWh, lb/MMBtu for CO 2 , NO x , and SO 2 ; in lb/GWh for CH 4, N 2 O, and Hg; and in lb/BBtu for Hg. The m easurement 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 ar ea 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 al so 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 th e 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 f ile; are linked to the year 2005 plant data with the inclusion of the year 2005 plant file’s SEQPLT05 vari able 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, stat e, power control area, eGRID subregion, NERC region, and U.S files; and the new year 2009 grid gross lo ss 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 IB M 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 generati on 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 f ile 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 pos tal 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 incl udes a description of the variables and the original data sources. The file structure indicates which vari ables 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 y ear 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) displa yed 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 aggreg ation files for EGC operator-based, EGC ownerbased, parent company operator-based, or pare nt 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-b ased 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 ha ve 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/bala ncing 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 repl acement for the NBP flag in the boiler file;

 eGRID subregion annual CO 2 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 CO 2 emissions. But, beginning with year 2009 data, the biomass fuel components’ CO 2 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 CH 4 , N 2 O, SO 2 , and NO
x emissions are also adjusted by the same biogas fuel component percentage as that in the matching EIA-923 un it-level data (or if necessary, the matching EIA-923 prime mover level data) for the adjusted CH 4 , N 2 O, SO 2 , and NO
x CAMD emissions. RMBMFLAG, the biomass flag, is assigned a value of 7100 if there is a biomass adjustment to CAMD CO 2 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 out put emissions rates, rather than divide the total adjusted emissions by the total plan t net generation (as done for year 2007 data and earlier), if a plant is partially a com bustion 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, th e 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 corr ected for those plants whose longitude is -99.xx (they had inadvertently been replaced by ‘N/A’ in the prev ious edition). For more information about the year 2007 data, see the eGRID2010 Technical Support Do cument (TS|Pechan, 2010). For methodology from previous years, see their Technical Suppor t Documents (TS|Pechan , 2008, 2007, 2003a).



## C. USES AND USERS OF eGRID

eGRID data support a wide variety of users globally thr ough a wide variety of uses. eGRID is valuable to those in the Federal Government, state and lo cal governments, non-governmental organizations,6 academia, and provides constructive direction to co mpanies who are generally seeking environmental information from the electric power sector in the Unit ed States. eGRID is most often used for the estimation of indirect emissions from electricity pu rchases, 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 em ission inventory and registry protocols, by various emission calculation tools and applications, by many acad emic papers, by many consultants, and is used for many research applications and efforts.

Within EPA, eGRID data are used in the followi ng applications and programs: Power Profiler web application, Climate Leaders protocols, ENERGYSTA R’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 Environmen t” challenge using EPA data, developers across the U.S. responded. EPA announced the winners on N ovember 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 i ndirect activities.” The Federal GHG Accounting and Reporting Guidance accompanied this order and r ecommended 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 pr ogram (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 he lp 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 eG RID 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 w hose 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 Governme nt agencies such as Oak Ridge National Laboratory (ORNL) for their Combined Heat and Power Calc ulator, the National Energy Technology Laboratory (NETL) for their sponsored Distributed Nationa l Carbon Sequestration Da tabase 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 we ll 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. Th e Maryland Department of the Environment (MDE) determined eligibility for participation in the Vo luntary 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 an d New Jersey -- completed a 2005 GHG Inventory in support of regional efforts to quantify and reduce emi ssions 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 Attr ibute Tracking System (GATS) utilize eGRID data. ISO New England uses eGRID rates in developi ng the 2008 New England Electric Generator Air Emissions Report ( http://www.iso-ne.com/genrtion_resrcs/re ports/emission/2008_e missions_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 (G HG) Protocol Initiative, the Rocky Mountain Institute’s Community Energy Finder, Leonardo Academy’s “Cleaner and Greener Environmental Program,” the National Resource Defense Council’s Benc hmarking Air Emissions, The Berkeley Institute of the Environment, Cool Climate Carbon Footprin t Calculator, the Climate and Air Pollution Planning Assistant (CAPPA), Emission Solution’s Carbon Fo otprint Calculator, and the Clean Air software developed by the International Council for Local Environmental Initiatives (ICLEI), The United States Department of Transportation Federal Transit Ad ministration (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 (I CC), 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 CM 1 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 Moni toring for Action Database (CARMA) at carma.org, which contains information about carbon emissions fo r 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 collect ed by the U.S. Environmental Protection Agency (EPA), and the Energy Information Administra tion (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 Emi ssions 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 Nort h American Electric Reliability Corporation (NERC) [formerly the North American El ectric 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. Inconsistenc ies 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 th at are not transparent. Some methods used for eGRID2012 are modified or refined from previous ed itions of eGRID and are so noted in this section.



## A. ESTIMATION OF EMISSIONS

Emissions (CO 2 , NO x , SO 2 , Hg, CH 4 , and N 2 O) 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 (CO 2 ) is a product of fossil fuel combustion and is the prim ary greenhouse gas (GHG) emitted by human activities that is contributing to global climate change; nitrogen oxides (NO
x ) 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 (SO 2 ) is an air pollutant emitted primarily by power plants burning fossil fuels, esp ecially 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 (CH 4 ) and nitrous oxide (N 2 O), two other GHG emitted by electric power generators, are in cluded 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 Re gistry, 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 nonu tilities 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 200 9 data are generally utility and nonutility steam units with at least 25 MW capacity, nonsteam units – gas turbines, combined cy cles, 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 boile rs and prime movers repre senting an aggregation of like generating units. In general, eGRID plant leve l 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 gene rating plants (net generation). However, they do not take into account any power purchases, imports or e xports of electricity into a specific state or any other grouping of plants; and they do not account fo r any transmission and distribution losses between thepoints of generation and the points of consumption. Also, eGRID does not account for any precombustion emissions associated with the extracti on, 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 em ission rates and for all aggregation emission values.



### 1. Unadjusted Emission Estimates for Year 2009

Emissions that are reported and estimated for eGRI D are initially unadjusted, including biomass GHG values, and are displayed at the plant (and boiler) leve l. Adjusted emissions (and heat input) are included in the plant file and all subsequent aggregation f iles. All emission rates in the plant file and all aggregation files are based on adjusted emissions, net generation, and adjusted heat input. Depending on10 the source of data and the emissions type, compone nt emissions are adjusted for biomass and then summed to the plant level before making the CHP adjust ment specific to eGRID. Both the source(s) of emissions data and adjustment flags are provided in the plant file.



### 2. Annual Emission Estimates for CO 2 

### , SO 2 

### , and NO x

Mass emissions in eGRID are estimated using data from a variety of sources. eGRID’s primary source for CO 2 , SO 2 , and NO
x , data is EPA/CAMD’s unit level emissions data. CO 2 is a greenhouse gas, while SO 2 and NO
x are not. SO 2 and NO
x 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 le vel if the data are in the EIA-923 boiler level, and/or on a prime mover-fuel level if the data ar e only in the EIA-923 prime mover level file.

For estimating CO 2 , the Intergovernmental Panel on Clim ate 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 Si nks: 1990-2010 (EPA, 2012b, Annex 2 tables). CO 2 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 CO 2 emissions are estimated, whether for EPA/CAMD, EIA-923 boiler, or EIA-923 prime mover data, the emission factor is applie d to fuel consumption (usually in MMBtu).

For SO 2 , 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 NO
x 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 NO x 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 unc ontrolled 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 NO
x emissions for combined cycles, turbines, and internal combustion engines. NO
x EF were developed based on the prime mover technology, size, a nd 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/Low est 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 ge nerators (including small combustion turbines, microturbines and reciprocating engines), the me thodology 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 CO 2 , SO 2 , and NO
x . While CO 2 is a gas in the geothermal reservoir, SO 2 and NO
x 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 ty pe of geothermal plant (GEA, 2010, plus updates based on internet research). For a binary or flash/binary geothermal plant, there are no CO 2 , SO 2 , or NO x EF; for a flash geothermal plant, there are no NO
x EF and small CO 2 and SO 2 EF; and for a dry steam11 geothermal plant, there are small CO 2 , SO 2 , and NO
x EF. If a plant has operating (i.e., reported non-zero net generation) generators with diffe rent 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 CH 4 

### and N 2 

### O

In addition to CO 2 , electric power plants also emit some CH 4 , and N 2 O GHG emissions. CH 4 and N 2 O 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 Ma ndatory Reporting of Greenhouse Gases Rule (EPA, 2009).

Nitrous oxide (N 2 O) is an oxide of nitrogen that is not part of the NO
x subset of oxides of nitrogen. N 2 O is a greenhouse gas, the emissions of which are contributing toward global climate change; NO
x is not a GHG. N 2 O should not be confused with NO X .

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, CO 2 , which has a GWP of 1. Traditionally, the 100-year GWPs are used when calculating overall CO 2 equivalent emissions, which is the sum of the products of each GHG emission value a nd its GWP. Note: be sure when calculating the CO 2 equivalent that each of the GHG emission values has the same measurement units (either all in tons or all in pounds) since in eGRID, CO 2 are expressed in tons while both CH 4 and N 2 O 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 ther e 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 CO 2 111 CH 4 21 23 25 N 2 O 310 296 298

Beginning with year 2007 data, the CO 2 equivalent emissions (tons) and total output emission rate (in lb/MWh) is calculated (using the SAR GWP) at the plan t and aggregation levels; and beginning with year 2009 data, the CO 2 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 NO x

The ozone season is the five-month period from May th rough 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 NO
x 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 covere d by EPA/CAMD, monthly fuel quantity is provided so that five-month (May th rough September) ozone season NO
x 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 wh ich 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 biom ass 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 move rs is reported as zero even though positive fuel use is reported to the EIA-923. For 74 th 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 assign ed zero adjusted emissions and heat input

.


### 7. Adjustments for Biomass

eGRID makes adjustments for biogas emissions, for bi omass emissions other than biogas, and for solid waste emissions for specified pollutants. Solid waste t ypically 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 th e 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 compone nt (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, CO 2 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 me thodology has not changed. However, beginning with the year 2007 data, the biomass portion of solid waste combustion is shown in the unadjusted CO 2 emissions.

A flag in the plant file indicates whether there is any biomass adjustment and the type of adjustment. The possible adjustments for CO 2 , NO x , SO 2 , CH 4 , and N 2 O emissions (and heat input) are explained below.

a. CO 2

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 CO 2 emissions to generation from the combustion of all biomass (including biogas) because these organic materials would otherwise release CO 2 (or other greenhouse gases) to the at mosphere through decomposition.

For those adjusted-for-biomass CO 2 emissions that are estimated, the biomass components are zeroed out in this edition, just as they have b een for previous years of eGRID data. However, in this edition of eGRID, the CO 2 emissions from biomass are more comprehens ively disclosed in the plant unadjusted emissions. The CO 2 emissions from biomass can be determined at a plant level by comparing the emissions and the unadjusted emissions at plants th at 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 bi omass fuel components’ CO 2 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/C AMD primary fuel was a biomass fuel. Beginning with year 2009 data, the biomass fuel components’ CO 2 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 CO 2 emissions. Similarly, the biogas fuel components’ CO 2 , CH 4 , N 2 O, SO 2 , and NO
x 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. NO x , SO 2 , CH 4 , and N 2 O

NO x , SO 2 , CH 4 , and N 2 O emissions from generation powered by biogas (landfill gas and digester gas) are also adjusted in eGRID. Landfill gas and digester gas em issions 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 adjust ed 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 em issions) by the emission factor represented by a typical flare. This methodology has not changed.

For NO x , 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-a pproved uncontrolled EF before being applied. For SO 2 , CH 4 , and N 2 O, the EF are assumed to be the same as the flares’, so there are no incremental SO 2 , CH 4 , and N 2 O emissions attributable to utilizing biogas to generate electricity, and values of zero are assigned.

In eGRID, there are no fuel adjustments for NO
x , SO 2 , CH 4 , and N 2 O emissions for biomass other than biogas. Beginning with year 2009 data, the biogas components’ CAMD CH 4 , N 2 O, SO 2 , and NO
x 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 EI A-923 prime mover level data) for the adjusted CH 4 , N 2 O, SO 2 , and NO
x 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 elect ricity and another form of useful thermal energy (such as heat or steam) used for industrial, commerc ial, 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 fi le indicates if a plant is considered a CHP for purposes of eGRID. Since emissions reported in eGRI D 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 effici ency gains between electricity and useful thermal output. For CHP facilities in the year 2009 data, eG RID 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 elect ric allocation factor, it is applied to the emissions (and heat input) for the entire plant after any bi omass adjustment has been made. Specifically, the adjusted value is the product of the electri c 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 su m of the electricity and steam heat outputs, where15 electricity heat output in MMBtu is the net gene ration 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 fo r 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 d esignated 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 be low 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 opera ting characteristics of existing CHP systems. The power-to-heat ratio is largely a function of the CH P 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 character istics 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 emi ssion values, annual and ozone season ne t 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 electric ity 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 pr ime 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, gene ration is reported monthly and annually so that ozone season generation is calculated by summing up th e 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 de rived 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 EI A-923 plant-prime mover annual and ozone season MWh net generation, if available. Oz one season net generation for those plan ts/generators that report monthly to the EIA-923 is calculated by summing the May thr ough September net generation; for plants/units that report only annually to the EIA-923, the ozone season net generation is calcula ted as 5/12 of annual net generation.

If plant-prime mover net generation is also n eeded because there is EPA/CAMD non-zero reported emissions without associated EIA-923 net generati on, 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 genera tion 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 c onversion 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 ge neration), based on the fuel type generation of each plant. For plants that are onl y 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 gene rating units, the combustion net generation will be less than the total net generation for that plant.

Generator level net generation

To determine generator level ne t 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, u se EIA-923 nuclear unit-level reported annual and ozone season net generation. Most non-stea m 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 in itially obtained from EPA/CAMD 12 month reported17 emissions data. Ozone season heat i nput is also provided with these data. EPA heat input is based either on stack flow and CO 2 /O 2 monitoring, or fuel flow and heat content of fuel.

If these EPA data are unavailable, heat input is ob tained from the EIA-923 prime mover level data; its value was calculated internally by EIA by multiplyin g 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 h eat input for the same prime mover to EIA-923 and/or EPA/CAMD, the EPA/CAMD data are used first. If th e 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 SO 2 , NO x , and CO 2 , and lb/GWh for Hg, CH 4, and N 2 O. These rates are calculated as the emissions divi ded by the net generation and multiplied by a unit conversion factor. Beginning with year 2009 data, fo r 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 inst ead divided by the combustion net generation for that plant.

For input emission rates, the units are lb/MMBtu for SO 2 , NO x , and CO 2 , and lb/BBtu for Hg; these rates are calculated as the emissions divi ded by the heat input and multiplied by a unit conversion factor.

eGRID output emission rates do not account for any li ne losses between the points of consumption and the points of generation. For example, because ther e 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 c onsumption 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 fro m 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 consumpti on, U.S. regional interchange, and FERC foreign [Canadian and Mexican] net imports) th at 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 foss il 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 in cluded 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 a pplied 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 annua l non-baseload emission rates which are the annual output emission rates for plants that combust fuel a nd have capacity factors less than 0.8, weighted by generation and a percent of generati on determined by capacity factor. These data values are derived from plant level data and supplement, rather than repl ace, 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 foss il 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 surroga te for determining how much non-baseload generation and emissions occur at each facility. Although there ar e 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 procedur e used to generate these non-baseloa d 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 relations hip is used to determine the percent of the plant’s generation and emissions to be considered non-baseloa d generation. All generation at plants with low capacity factors (greater than 0.0 and less than 0.2) would be considered non-basel oad. No generation at plants with high capacity factors (0.8 and greater) would be considered non-b aseload generation. No19 generation at plants with negative generation from combustion sources would be considered non-baseload generation. A linear relationship would determine th e 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 multipliedby 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 a ttempting 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 ener gy 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 insu lation improvements), then one could use the eGRID subregion non-baseload CO 2 output emission rate and the expected or actual energy savings resulting from the installation to estimate the CO 2 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 calculati ng 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 ope rator of a plant are taken directly from those provided in the 2009 EIA-860. Since ownership is repor ted in eGRID only on the plant level, but in the EIA-860 on the generator level, the generators’ owner companies and per centages must be aggregated to the plant level, which is accomplished for each plan t by MW-weighting each generator’s ownership and then summing to the plant level. Although eGRI D’s methodology for assigning ownership on a plant level has not changed, eGRID has not tracked ownershi p or nonutility front company data as was done in the past, and is taking ownership data di rectly from the EIA-860 for year 2009 data.

Unfortunately, there are some plants for which th is plant level ownership methodology will result in misleading percentages. For example, if one compan y owns only one of several generators and that one generator is connected to a “clean” boiler that has emis sions whose ratio to the entire plant’s emissions is much less than its MW’s ratio to the entire plan t’s MW, that one company will, because of its MW-toplant MW ratio, have a higher plant ownership percenta ge attributed to it than its actual emissions plant20 percentage; thus, that company will be associated wi th greater emissions and generation than it actually has.

This situation is not typical since most plants do not have “jointly owned” genera tors or different owners for all the plant’s generators. It affects only so me plants and companies and some percentage of emissions and generation associations in this situatio n. 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 h as about the same nameplate capacity. One generator is owned by Ohio Power, and two by Buckeye Power In c. 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 SO 2 emissions for the two boilers associated with Buckeye’s two generators combined are over 90% of the Cardinal plant’s reported SO 2 emissions total (the largest boiler has no SO 2 control), and the reported NO
x emissions for the two boilers associated with Buckeye’s two generators combined are over 70% of the Cardinal plant’s reported NO
x emissions total (the largest boiler has an additional NO
x 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 fo r 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 dow n 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 main ly 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, beginni ng with year 2007 data. This new variable is based on the maximum22 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 bi omass, 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 an d generation percent.

For cases in which there is only one fuel and its genera tion is negative, that fuel’s generation percent is assigned 100%. For cases in which there are fuels wi th both negative and positive net generation, the generation percents only include the positive genera tion in both the denominator and numerator. For cases in which there are only two fuels and both ne t generations are negative, both fuels’ generation percents are assigned 0%.

For the three grouped aggregate categories – total ne t generation from nonrenewab le, total net generation from all renewables, and total net generation from re newables 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 nega tive fuel generation in the nonrenew ables category (it is unlikely to happen in the renewables category), the category pe rcentages 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 aggr egated 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) ne t 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 move r-fuel level. However, there are some cases for which only the EPA/CAMD-based net generation is av ailable for use in eGRID. In these cases, the primary fuel (based on the maximum heat input va lue) is assigned 100% of the generation for the resource mix.23 

## E. DETERMINATION OF PL ANT 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 relationshi ps 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 Nort h American Electric Reliability Corporation. Each NERC region listed in eGRID represents one of ten regi onal 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 Reli ability Council of Texas (ERCOT) NERC region did change its name to the Texas Reliability Entity (T RE) 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 eG RID2012 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/distri bution/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 NE RC 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 configur ation, 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 eGRI D 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, e quivalent 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 determin es the plant’s associated eGRID subregion, which is defined as a subset of the NERC region, and is composed of en tire 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 eG RID subregion do change from year to year. The 26 eGRID subregion names and their acronyms are displa yed 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 Mi dwest 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 gr ouped 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 determ ined 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 distri bution 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 w ith 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 determin ed 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 register ed 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 PC As 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 Fl orida Reliability C oordinating Council Florida Power & Light Company FRCC Florida Reliability Coordinating Council Gainesville Regional Utilities FRCC Fl orida Reliability C oordinating Council Homestead City of FRCC Florida Reliability Coordinating Council JEA FRCC Florida Reliabilit y Coordinating Council New Smyrna Beach Utilities Commission of FR CC Florida Reliability Coordinating Council Progress Energy Florida FRCC Florid a Reliability Coordinating Council Seminole Electric Cooperative FRCC Fl orida Reliability C oordinating 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 Organization27 Table III-9 (continued).

PCA Name NERC Region NERC Name WAPA - Upper Great Plains East MR O 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 Re liability First Corporation Indianapolis Power & Light Company RFC Reliability First Corporation Michigan Electric Coordinated System s 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 RF C 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 SER C 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 Co mpany SPP Southwest Power Pool28 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 Co mpany SPP Southwest Power Pool Lafayette Utilities System SPP Southwest Power Pool Louisiana Energy & Power Author ity SPP Southwest Power Pool Oklahoma Gas and Electric Com pany SPP Southwest Power Pool Southwestern Power Administra tion SPP Southwest Power Pool Southwestern Public Service Co mpany SPP Southwest Power Pool Springfield MO City Utilities of SPP Southwest Power Pool Sunflower Electric Power Corpor ation SPP Southwest Power Pool Westar Energy SPP Southwest Power Pool Western Farmers Electric Cooper ative SPP Southwest Power Pool ERCOT ISO TRE Texas Regional Entity Arizona Public Service Company WECC We stern Electricity Coordinating Council Arlington Valley WECC Western Electricity Coordinating Council Avista Corporation WECC Western Electricity Coordinating Council Balancing Authority of Northern California WE CC Western Electricity Coordinating Council Bonneville Power Administration WECC Western Electricity Coordinating Council California ISO WECC Western Elec tricity 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 West ern 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 West ern Electricity Coordinating Council PUD No. 2 of Grant County WECC Wester n 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 WE CC Western Electricity Coordinating Council Puget Sound Energy WECC Western El ectricity 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 West ern Electricity Coordinating Council WAPA - Desert Southwest Region WECC West ern Electricity Coordinating Council WAPA - Rocky Mountain Region WECC West ern Electricity Coordinating Council WAPA - Upper Great Plains West WECC We stern Electricity Coordinating Council29 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 Ge neration 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 we re also reviewed and updated as needed, as were the PCAs, eGRID subregions, and NERC regions.

Since PCAs are not strictly geographically based, th ere 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 Coope rative 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 As sn 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 SERC30 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 P ublic 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 MRO31 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 Servic e 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 Powe r 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 SPP32 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. Th e 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 pl ant data values needed to calculate non-baseload emission rates), based on the state in which the plan t 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 subreg ion, NERC region, and U.S. files’ adjusted heat input, adjusted emissions, adjusted fuel-based emissi ons, net generation, fuel-based net generation, and nameplate capacity data should be the same, after accounting for rounding.33 

## SECTION IV. SPECIFIC eGRI D IDENTIFIER CODES, NAME CHANGES AND ASSOCIATIONS

eGRID2012 generally uses identifier (ID) codes (for plan ts, 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. Consequen tly, 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 beco me 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, ow ners, 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 territori es, 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. DESCRIPTIO N OF DATA ELEMENTS

For year 2009 data, eGRID2012 has 8 aggregation fi les named BLR (boiler), GEN (generator), PLNT (plant), ST (state), PCAL (PCA), SRL (eGRID s ubregion), 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 va riable descriptions and original data sources. Definitions for like variables are not repeated after th e 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 cont ains 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 w as 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-923THE 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 co mmas. The individual values possible are:

ARP =Acid Rain Program CAIRNOX =Clean Air Interstate Rule for NO
x (annual) CAIROS =Clean Air Interstate Rule for NO
x (ozone season) CAIRSO2 =Clean Air Interstate Rule for SO 2 NHNOX =New Hampshire’s special NO
x program RGGI =Regional Greenhouse Gas Initiative (CO 2 ) SIPNOX =NO x SIP Call See http://epa.gov/airmarkets/pr ogsregs/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 follo wed 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-860THE BLR FILE

37 9. Number of Associated Generators (NUMGEN) – This field provides the number of generato rs 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/CAMDTHE BLR FILE

38 12. Boiler Unadjusted Annual EPA/CAMD Heat Input (HTIEAN) – This field, in MMBtu, is the unit’s una djusted 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 una djusted 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-Ba sed Calculated Heat Input (HTIFAN) – This field, in MMBtu, provides the boiler’s unadjusted annual total heat input, calculated using EIA-923 boiler data, when availabl e. 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 bo iler’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 NO x Emissions (NOXEAN) – This field, in tons, is the unit’s unadjusted NO
x 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 NO x Emissions (NOXEOZ) – This field, in tons, is the unit’s unadju sted ozone season (May through September) NO
x emissions based on values reported to EPA/CA MD. When not available, it is zero. Source: EPA/CAMD

18. Boiler Unadjusted Annual EIA-Based Calculated NO x Emissions (NOXFAN) – This field, in tons, is th e boiler’s unadjusted annual NO
x 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 NO x Emissions (NOXFOZ) – This field, in tons, is the boiler’s unadj usted ozone season (May through September) NO
x emissions calculated from EIA-923 boiler re ported 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 SO 2 Emissions (SO2EAN) – This field, in tons, is the unit’s unadjusted annual SO 2 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 SO 2 emissions, so theTHE 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 SO 2 Emissions (SO2FAN) – This field, in tons, is th e boiler’s unadjusted annual SO 2 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 CO 2 Emissions (CO2EAN) – This field, in tons, is the unit’s unadjusted annual CO 2 emissions assigned by EPA/CAMD based on the values reported to EPA/CAMD. Units that are NBP and not ARP do not report annual CO 2 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 CO 2 emissions are assigned a zero value (see the Methodology Section for the rationale for biomass adjustments for CO 2 ). Source: EPA/CAMD

23. Boiler Unadjusted Annual EIA-Based Calculated CO 2 Emissions (CO2FAN) – This field, in tons, is th e boiler’s unadjusted annual CO 2 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 CO 2 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 NO x Emissions (NOXBAN) – This field, in tons, contains the “best” unadjusted annual NO
x value by taking NOXEAN as its value, if it exists; otherwise NOXFAN’s value is used.

28. Boiler Unadjusted Ozone Season Best NO x Emissions (NOXBOZ) – This field, in tons, contains the “best” unadjusted ozone season (May through September) NO x 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 SO 2 Emissions (SO2BAN) – This field, in tons, contains the “best” unadjusted annual SO 2 value by taking SO2EAN as its value, if it exists; otherwise SO2FAN’s value is used.

30. Boiler Unadjusted Annual Best CO 2 Emissions (CO2BAN) – This field, in tons, contains the “best” unadjusted annual CO 2 value by taking CO2EAN as its value, if it exists; otherwise CO2FAN’s value is used.

31. Boiler SO 2 (Scrubber) First Control Device (SO2CTLDV) – This field contains the first reported SO 2 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 NO x First Control Device (NOXCTLDV) – This field contains the first reported NO
x 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 NO

x premixed technology FR = Flue gas recirculation FU = Fuel reburning H2O = Water injection LA = Low excess air LNB or LN = Low NO
x burner LNBO = Low NO
x burner with overfire air LNC1 = Low NO
x burner technology with close-coupled overfire air LNC2 = Low NO
x burner technology with separated OFATHE BLR FILE

41 LNC3 = Low NO
x burner technology with close-coupled and separated overfire air LNCB NA = Low NO
x 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-860THE 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 resu lt in the same values as the plant generation. This file includes generation from steam boilers and nucl ear 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 Genera tor Sequence Number (SEQGEN09) – The generator records in this year 2009 da ta 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 se quence 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 w as 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 bo ilers 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 genera tor status values are considered potentially operating generators (including ge nerators 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 ge nerator’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, nucl ear, 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 steamTHE 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 excl usive. 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 prov ide 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 mont h ozone season (May through September) net generation in MWh. For plants that re ported 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 ge nerator 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-860THE 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 Plan t 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 sa me 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 w as 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 Syst em (FRS) code associated with the ORISPL. This field is blank for year 2009 da ta because of data inconsistencies. Source: EPA FRS

6. Plant Operator Name (OPRNAME) – The name associated with each operating comp any (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 Territo ry 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 plan t is located. See Section IV for further details. Source: EIA-860 + updatesTHE PLNT FILE

46 9. Utility Service Territory ID (UTLSRVID) – This field contains the unique ID code asso ciated 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 operat or’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 pa rent 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 informati on 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 s ubregion 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) + updatesTHE 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 plan t 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 Nati onal 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 boile rs 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 = NO
x , SO 2 , and CO 2 emissions reported to EPA's Emissions tracking System/Continuous Emissions M onitoring System (EPA/CAMD) if in the ARP program; otherwise estimated by applying EPA- approved EF to EPA/CAMD data for year 2009. CH 4 and N 2 O emission estimated by applying EPA-approved EF to EPA/CAMD data for year 2009. EIA-923

EIA-906 = NO
x , SO 2 , CO 2 , CH 4 , and N 2 O emissions estimated by applying EPA-approved EF to EIA-923 boiler-level data for year 2009. = NO
x , SO 2 , CO 2 , CH 4 , and N 2 O 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 plan t 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 wasteTHE 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 Coa l/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 organi c 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 nameplat e 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 eGRI D 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 CO 2 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 fo r a CHP facility, which is the ratio of the heat value of electricity generated (3413 * kWh out put) 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 frac tion 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 allo cate 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 (M ay through September) heat input, in MWh, for the plant. For CHP plants, the value is ad justed by the electric allocation factor. See the Methodology Section for details.

42. Plant Annual Net Generation (PLNGENAN) – This field is the total reported annual ne t 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 calculatedTHE PLNT FILE

51 44. Plant Annual NO x Emissions (PLNOXAN) – This field, in tons, is the total annual NO
x emissions for the plant. Biogas components are adjusted. For CHP plants, the value is ad justed 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 allocati on factor (if the plant is a CHP). See the Methodology Section for details.

45. Plant Ozone Season NO x Emissions (PLNOXOZ) – This field, in tons, is the five m onth ozone season (May through September) NO
x emissions for the plant. Biogas components ar e 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 allocati on factor (if the plant is a CHP). See the Methodology Section for details.

46. Plant Annual SO 2 Emissions (PLSO2AN) – This field, in tons, is the total annual SO 2 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 allocati on factor (if the plant is a CHP). See the Methodology Section for details.

47. Plant Annual CO 2 Emissions (PLCO2AN) – This field, in tons, is the total annual CO 2 emissions for the plant. All estimated CO 2 emissions from biomass fuels are adjusted to zero. The biomass fuel components’ CO 2 CAMD emissions are excluded (adjusted to zero) by the same biomass fuel component percentage as that in the EIA-923 for the adjusted CO 2 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 allocati on factor (if the plant is a CHP). See the Methodology Section for details.

48. Plant Annual CH 4 Emissions (PLCH4AN) – This field, in lbs, is the total annual CH 4 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 allocati on factor (if the plant is a CHP). See the Methodology Section for details.THE PLNT FILE

52 49. Plant Annual N 2 O Emissions (PLN2OAN ) – This field, in lbs, is the total annual N 2 O 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 allocati on factor (if the plant is a CHP). See the Methodology Section for details.

50. Plant Annual CO 2 Equivalent Emissions (PLCO2EQA ) – This field, in U.S. tons, is the annual CO 2 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 NO x Total Output Emission Rate (PLNOXRTA) – This field, in lb/MWh, is calculated as follows: PLNOXRTA = 2000 * (PLNOXAN / PLNGENAN).

53. Plant Ozone Season NO x Total Output Emission Rate (PLNOXRTO) – This field, in lb/MWh, is calculated as follows: PLNOXRTO = 2000 * (PLNOXOZ / PLNGENOZ).

54. Plant Annual SO 2 Total Output Emission Rate (PLSO2RTA) – This field, in lb/MWh, is calculated as follows: PLSO2RTA = 2000 * (PLSO2AN / PLNGENAN).

55. Plant Annual CO 2 Total Output Emission Rate (PLCO2RTA) – This field, in lb/MWh, is calculated as follows: PLCO2RTA = 2000 * (PLCO2AN / PLNGENAN).

56. Plant Annual CH 4 Total Output Emission Rate (PLCH4RTA) – This field, in lb/GWh, is calculated as follows: PLCH4RTA = PLCH4AN / (PLNGENAN / 1000).

57. Plant Annual N 2 O Total Output Emission Rate (PLN2ORTA) – This field, in lb/GWh, is calculated as follows: PLN2ORTA = PLN2OAN / (PLNGENAN / 1000).

58. Plant Annual CO 2 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 NO x Input Emission Rate (PLNOXRA) – This field, in lb/MMBtu, is calculated as follows: PLNOXRA = 2000 * (PLNOXAN / PLHTIAN).

61. Plant Ozone Season NO x Input Emission Rate (PLNOXRO) – This field, in lb/MMBtu, is calculated as follows: PLNOXRO = 2000 * (PLNOXOZ / PLHTIOZ).

62. Plant Annual SO 2 Input Emission Rate (PLSO2RA) – This field, in lb/MMBtu, is calculated as follows: PLSO2RA = 2000 * (PLSO2AN / PLHTIAN).

63. Plant Annual CO 2 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 NO x Combustion Output Emission Rate (PLNOXCRT) – This field, in lb/MWh, is calculated as follows: PLNOXCRT = 2000 * (PLNOXAN / PLGENACY).

66. Plant Ozone Season NO x Combustion Output Emission Rate (PLNOXCRO) – This field, in lb/MWh, is calculated as follows: PLNOXCRO = 2000 * (PLNOXOZ / ((PLG ENACY * PLNGENOZ) / PLNGENAN)).

67. Plant Annual SO 2 Combustion Output Emission Rate (PLSO2CRT) – This field, in lb/MWh, is calculated as follows: PLSO2CRT = 2000 * (PLSO2AN / PLGENACY).

68. Plant Annual CO 2 Combustion Output Emission Rate (PLCO2CRT) – This field, in lb/MWh, is calculated as follows: PLCO2CRT = 2000 * (PLCO2AN / PLGENACY).

69. Plant Annual CH 4 Combustion Output Emission Rate (PLCH4CRT) – This field, in lb/GWh, is calculated as follows: PLCH4CRT = PLCH4AN / (PLGENACY / 1000).

70. Plant Annual N 2 O 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 NO x Emissions (UNNOX) – This field, in tons, is the to tal plant level unadjusted annual NO
x emissions. See the Methodology Section for details.

73. Plant Unadjusted Ozone Season NO x Emissions (UNNOXOZ) – This field, in tons, is the unadjusted fi ve month ozone season (May through September) NO x emissions for the plant. See the Methodology Section for details.

74. Plant Unadjusted Annual SO 2 Emissions (UNSO2) – This field, in tons, is the to tal plant level unadjusted annual SO 2 emissions. See the Methodology Section for details.

75. Plant Unadjusted Annual CO 2 Emissions (UNCO2) – This field, in tons, is the to tal plant level unadjusted annual CO 2 emissions. Beginning in year 2007, the biomass fuel components’ CO 2 emissions will be included in the unadjusted CO 2 plant emissions. See the Methodology Section for details.

76. Plant Unadjusted Annual CH 4 Emissions (UNCH4) – This field, in lbs, is the tota l plant level unadjusted annual CH 4 emissions. See the Methodology Section for details.

77. Plant Unadjusted Annual N 2 O Emissions (UNN2O) – This field, in lbs, is the tota l plant level unadjusted annual N 2 O emissions. See the Methodology Section for details.

78. Plant Unadjusted Annual Hg Emissions (UNHG) – This field, in lbs, is the total plant leve l 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 mont h 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, adjust ed 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 ne t generation for nuclear if the fuel code is NUC. Note that one plant, North Anna, h as 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 w ood 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 annua l 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 annua l 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/ Purcha sed 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 tota l nonrenewables net generation for the plant. Nonrenewables are exhaustible energy resour ces 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 tota l 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 Rene wables Net Generation (PLGENATH) – This field, in MWh, contains the annual to tal 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 tota l 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 to tal 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 genera tion, 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 mi x 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 info rmation on ownership is provided, then it is assumed that the operator has 100% owne rship. 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 gene rator 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 Pl ant Sequence Number (SEQPLT04) – This field contains the sequence number of th e plant in the year 2004 data, if one exists. This sequence number is unlikely to be the sa me as the sequence number in the year 2005 eGRID2007 file for the same plant.

163. eGRID2007 year 2005 File Pl ant Sequence Number (SEQPLT05) – This field contains the sequence number of th e plant in the year 2005 data, if one exists. This sequence number is unlikely to be the sa me as the sequence number in the year 2007 eGRID2010 file for the same plant.

164. eGRID2010 year 2005 File Pl ant Sequence Number (SEQPLT05) – This field contains the sequence number of th e plant in the year 2007 data, if one exists. This sequence number is unlikely to be the sa me 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 aggr egating 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 begi n with “ST.” The one new variable for this data year is the first one.

1. eGRID2012 year 2009 File Stat e 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 be ginning 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 NO x Emissions (STNOXAN) –

10. State Ozone Season NO x Emissions (STNOXOZ) –

11. State Annual SO 2 Emissions (STSO2AN) –

12. State Annual CO 2 Emissions (STCO2AN) –

13. State Annual CH 4 Emissions (STCH4AN) –

14. State Annual N 2 O Emissions (STN2OAN) –

15. State Annual CO 2 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 NO x 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 NO x Total Output Emission Rate (STNOXRTO) – This field, in lb/MWh, is calculated as follows: STNOXRTO = 2000 * (STNOXOZ / STNGENOZ).

19. State Annual SO 2 Total Output Emission Rate (STSO2RTA) – This field, in lb/MWh, is calculated as follows: STSO2RTA = 2000 * (STSO2AN / STNGENAN).

20. State Annual CO 2 Total Output Emission Rate (STCO2RTA) – This field, in lb/MWh, is calculated as follows: STCO2RTA = 2000 * (STCO2AN / STNGENAN).

21. State Annual CH 4 Total Output Emission Rate (STCH4RTA) – This field, in lb/GWh, is calculated as follows: STHCH4RTA = STCH4AN / (STNGENAN / 1000).

22. State Annual N 2 O Total Output Emission Rate (STN2ORTA) – This field, in lb/GWh, is calculated as follows: STN2ORTA = STN2OAN / (STNGENAN / 1000).

23. State Annual CO 2 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 NO x Input Emission Rate (STNOXRA) – This field, in lb/MMBtu, is calculated as follows: STNOXRA = 2000 * (STNOXAN / STHTIAN).

26. State Ozone Season NO x Input Emission Rate (STNOXRO) – This field, in lb/MMBtu, is calculated as follows: STNOXRO = 2000 * (STNOXOZ / STHTIOZ).

27. State Annual SO 2 Input Emission Rate (STSO2RA) – This field, in lb/MMBtu, is calculated as follows: STSO2RA = 2000 * (STSO2AN / STHTIAN).

28. State Annual CO 2 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 NO x Combustion Output Emission Rate (STNOXCRT) – This field, in lb/MMBtu, is calculated as follows: STNOXCRT =2000 * (STNOXAN / STGENACY).

31. State Ozone Season NO x Combustion Output Emission Rate (STNOXCRO) – This field, in lb/MMBtu, is calculated as follows: STNOXCRO = 2000 * (STNOXOZ / (( STGENACY*STNGENOZ)/STNGENAN)).

32. State Annual SO 2 Combustion Output Emission Rate (STSO2CRT) – This field, in lb/MMBtu, is calculated as follows: STSO2CRT = 2000 * (STSO2AN / STGENACY).

33. State Annual CO 2 Combustion Output Emission Rate (STCO2CRT) – This field, in lb/MMBtu, is calculated as follows: STCO2CRT = 2000 * (STCO2AN / STGENACY).

34. State Annual CH 4 Combustion Output Emission Rate (STCH4CRT) – This field, in lb/BBtu, is calculated as follows: STCH4CRT = STCH4AN / (STGENACY / 1000).

35. State Annual N 2 O 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 NO x Coal Output Emission Rate (STCNOXRT) – This field, in lb/MWh, is calculated as the sum of the annual NO
x 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 ne w, beginning with year 2009 data, for all the fuel-based output emission rates.

38. State Annual NO x Oil Output Emission Rate (STONOXRT) – This field, in lb/MWh, is calculated as the sum of the annual NO
x emissions from all plants in the state that have oil as its prim ary fuel (PLPRMFL) divided by the sum of the annual combustion net generation from the sa me 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 NO x Gas Output Emission Rate (STGNOXRT) – This field, in lb/MWh, is calculated as the sum of the annual NO
x 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 NO x Fossil Fuel Output Emission Rate (STFSNXRT) – This field, in lb/MWh, is calculated as the sum of the annual NO
x 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 NO x 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 NO x as fields #37 through #40, respectively, do for annual NO
x . The state ozone season combustion net generation, used in th e 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, beginni ng with year 2009 data, for all the fuelbased output emission rates.

45. - State Annual SO 2 Coal, Oil, Gas, and Fossil Fuel Output Emission Rates – 48. The descriptions of these fields, in lb/MWh, contain the same information for annual SO 2 as fields #37 through #40, respectively, do for annual NO
x .

49. - State Annual CO 2 Coal, Oil, Gas, and Fossil Fuel Output Emission Rates – 52. The descriptions of these fields, in lb/MWh, contain the same information for annual CO 2 as fields #37 through #40, respectively, do for annual NO
x .

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 NO
x .

55. - State Annual NO x , Ozone Season NO x , Annual SO 2 , Annual CO 2 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 un its are lb/BBtu, not lb/MMBtu. These values are calculated in the same manner as are any input emission rates.

73. State Annual NO x Non-baseload Output Emission Rate (STNBNOX) – This field, in lb/MWh, is the sum of the annual non-baseload NO
x 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 weight ed by a factor which is a function of capacity factor. For more information, see the Methodology Section.

74. State Ozone Season NO x 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 SO 2 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 CO 2 Non-baseload Output Emission Rate (STNBCO2) –

77. State Annual CH 4 Non-baseload Output Emission Rate (STNBCH4) –

78. State Annual N 2 O 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 Rene wables 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, wh ich contains location (operator)-based power control area (PCA) data. All generation and emission valu es 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 variab le 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 de rived 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 CO 2 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 ha ve not been described in previous file variable descriptions. Aggregated variable names generally begin with “SR.”



## G. THE NRL (NER C 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 derive d by aggregating from the plant level based on the associated NERC region.

The only variable in this file that has not been d escribed 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 aggregati ng 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. Ag gregated variable names ge nerally begin with “US.”



## I. THE REGIONAL GR ID 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 f actors (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 electri city 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 asso ciated 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 regiona l 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 di stribution 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 em issions are calculated in the following equation:

GHG emis ll = GHG emis ra te * Consumption * (ggl%/ 100) / (1-ggl%/100)/2000;

where GHG emis ll = a specified GHG emission asso ciated 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 regiona l 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 pow er 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 subsequent ly 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 intercha nge 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 im ports will have a positive value. Source: 2009 FERC-714 updated by EIA

4

. INTRCHNG – This field is the regional total net inte rchange (= 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 summ ed 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 fu rnished without charge, and energy consumed68 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 lo ss 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/e lectricity_use/impact_model.html

CARB, 2007: California Air Resources Board “Regul ation 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 Anal ysis, an ICF International Company, “Combined Heat and Power Installation Database, mainta ined 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 Oct ober 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.html70 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, “2 009 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, “P lant 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/emissi ons/downloads09/GHG-MRR-Full%20Version.pdf

EPA, 2011a: U.S. Environmental Protection Ag ency, 2009 Annual and Ozone Season EPA/CAMD database, Washington, DC, dow nloaded 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 Prot ection 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 Protec tion 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 Ga well. Table 3, Air Emissions Summary, in “A Guide to Geothermal Energy and the Envir onment”, Geothermal Energy Association, Washington, D.C., April 2007. http://geo-energy.org/report s/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 C limate 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_Vol ume2/V2_2_Ch2_Stationary_Combustion.pdf

Maryland, 2010: Maryland Department of th e Environment, Technical Support Document for Amendments to COMAR 26.09 MD CO 2 Budget Training Program, Baltimore, MD, October 25, 2010. http://www.mde.state.md.us/aboutmde/About MDEHome/Documents/RGGI-VERSA_TSD.PDF

NERC, 2012a: “Currently Registered BAs in NERC Compliance Registry as of March 28, 2012” Excel spreadsheet. Downloaded NERC_Complian ce_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/A boutNERC/maps/NERC_Regions_color.jpg

.

NIST, undated: National Institute of Standard s and Technology, Federal Information Processing Standards Publications. http://www.itl.nist.gov/fipspubs/index.htm

.

Rothschild and Diem, 2009: Rothschild, S. and A. Di em, 2009. “Total, Non-baseload, eGRID Subregion, State? Guidance on the Use of eGRID Out put Emission Rates,” presented at the U.S. Environmental Protection Agency Emission Inve ntory Conference, Baltimore, MD, May 2009. http://www.epa.gov/ttn/chief/conf erence/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/e gridzips/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 Tec hnical 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 S upport 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 S upport 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 S upport 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 S upport 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_fuel cell_and_electric_vehicles/emissions-and-charging-costs-electriccars.html?utm_source=SP&utm_medium= head&utm_campaign=EV%2BReport

Ventyx, 2007: Ventyx’ Global Energy Decisions’ Velo city 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/StandingComm ittees/PCC/LRS/Shared%20Documents/LRS%2 0Reports/Year%202007/SIGADD07Final.pdf

.

Wheeler, 2007: David Wheeler, Senior Fellow, Ce nter 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 da tabase format and are then transformed into Excel spreadsheets. The structure of the nine datab ase 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-bas ed 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 NO x emissions tons EPA/CAMD 17 NOXEOZ Boiler unadjust ed ozone season EPA/CAMD NO x emissions tons EPA/CAMD 18 NOXFAN Boiler unadjusted annual EIA-based calculated NO x emissions tons EIA-923 19 NOXFOZ Boiler unadjusted ozone season EIA-based calculated NO x emissions tons EIA-923 20 SO2EAN Boiler unadjusted annual EPA/CAMD SO 2 emissions tons EPA/CAMD 21 SO2FAN Boiler unadjusted annual EIA-based calculated SO 2 emissions tons EIA-923 22 CO2EAN Boiler unadjusted annual EPA/CAMD CO 2 emissions tons EPA/CAMD 23 CO2FAN Boiler unadjusted annual EIA-based calculated CO 2 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 s eason best heat input MMBtu 27 NOXBAN Boiler unadjusted annual best NO x emissions tons 28 NOXBOZ Boiler unadjusted ozone season best NO x emissions tons 29 SO2BAN Boiler unadjusted annual best SO 2 emissions tons 30 CO2BAN Boiler unadjusted annual best CO 2 emissions tons

31 SO2CTLDV Boiler SO 2 (scrubber) first control device EPA/CAMD, EIA-860

32 NOXCTLDV Boiler NO x 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 le vel may not result in the same values as the plant unadjusted emissions since additional emissions from prime movers not covered by the EPA/CA MD 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 seas on 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. Thi s file includes generation from nuclear units in t he 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 CO 2 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 calculatedA-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 NO x emissions tons

45 PLNOXOZ Plant ozone season NO x emissions tons

46 PLSO2AN Plant annual SO 2 emissions tons

47 PLCO2AN Plant annual CO 2 emissions tons

48 PLCH4AN Plant annual CH 4 emissions lbs

49 PLN2OAN Plant annual N 2 O emissions lbs

50 PLCO2EQA Plant annual CO 2 equivalent emissions ((1 * PLCO2AN ) + (21 * PLCH4AN/2000) + (310 * PLN2OAN/2000)) tons

51 PLHGAN Plant annual Hg emissions lbs

52 PLNOXRTA Plant annual NO x total output emission rate lb/MWh

53 PLNOXRTO Plant ozone season NO x total output emission rate lb/MWh

54 PLSO2RTA Plant annual SO 2 total output emission rate lb/MWh

55 PLCO2RTA Plant annual CO 2 total output emission rate lb/MWh

56 PLCH4RTA Plant annual CH 4 total output emission rate lb/GWh

57 PLN2ORTA Plant annual N 2 O total output emission rate lb/GWh

58 PLC2ERTA Plant annual CO 2 equivalent total output emission rate lb/MWh 59 PLHGRTA Plant annual Hg total output emission rate lb/GWh

60 PLNOXRA Plant annual NO x input emission rate lb/MMBtu

61 PLNOXRO Plant ozone season NO x input emission rate lb/MMBtu

62 PLSO2RA Plant annual SO 2 input emission rate lb/MMBtu

63 PLCO2RA Plant annual CO 2 input emission rate lb/MMBtu 64 PLHGRA Plant annual Hg input emission rate lb/BBtu

65 PLNOXCRT Plant annual NO x combustion output emission rate lb/MWh

66 PLNOXCRO Plant ozone season NO x combustion output emission rate lb/MWh

67 PLSO2CRT Plant annual SO 2 combustion output emission rate lb/MWh

68 PLCO2CRT Plant annual CO 2 combustion output emission rate lb/MWh

69 PLCH4CRT Plant annual CH 4 combustion output emission rate lb/GWh

70 PLN2OCRT Plant annual N 2 O combustion output emission rate lb/GWh 71 PLHGCRT Plant annual Hg combustion output emission rate lb/GWh 72 UNNOX Plant unadjusted annual NO x emissions tons 73 UNNOXOZ Plant unadjusted ozone season NO x emissions tons 74 UNSO2 Plant unadjusted annual SO 2 emissions tons 75 UNCO2 Plant unadjusted annual CO 2 emissions tons 76 UNCH4 Plant unadjusted annual CH 4 emissions lbs 77 UNN2O Plant unadjusted annual N 2 O 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 MWhA-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/pur chased 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 nonc ombustion 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 generat ion percent (resource mix) 110 PLTRPR Plant total renewables generat ion 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 generati on 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-860A-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 numberA-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 NO x emissions tons

10 STNOXOZ State ozone season NO x emissions tons

11 STSO2AN State annual SO 2 emissions tons

12 STCO2AN State annual CO 2 emissions tons

13 STCH4AN State annual CH 4 emissions lbs

14 STN2OAN State annual N 2 O emissions lbs

15 STCO2EQA State annual CO 2 equivalent emissions tons 16 STHGAN State annual Hg emissions lbs

17 STNOXRTA State annual NO x total output emission rate lb/MWh

18 STNOXRTO State ozone season NO x total output emission rate lb/MWh

19 STSO2RTA State annual SO 2 total output emission rate lb/MWh

20 STCO2RTA State annual CO 2 total output emission rate lb/MWh

21 STCH4RTA State annual CH 4 total output emission rate lb/GWh

22 STN2ORTA State annual N 2 O total output emission rate lb/GWh

23 STC2ERTA State annual CO 2 equivalent total output emission rate lb/MWh 24 STHGRTA State annual Hg total output emission rate lb/GWh

25 STNOXRA State annual NO x input emission rate lb/MMBtu

26 STNOXRO State ozone season NO x input emission rate lb/MMBtu

27 STSO2RA State annual SO 2 input emission rate lb/MMBtu

28 STCO2RA State annual CO 2 input emission rate lb/MMBtu 29 STHGRA State annual Hg input emission rate lb/BBtu

30 STNOXCRT State annual NO x combustion output emission rate lb/MWh

31 STNOXCRO State ozone season NO x combustion output emission rate lb/MWh

32 STSO2CRT State annual SO 2 combustion output emission rate lb/MWh

33 STCO2CRT State annual CO 2 combustion output emission rate lb/MWh

34 STCH4CRT State annual CH 4 combustion output emission rate lb/GWh

35 STN2OCRT State annual N 2 O combustion output emission rate lb/GWh 36 STHGCRT State annual Hg combustion output emission rate lb/GWh

37 STCNOXRT State annual NO x coal output emission rate lb/MWh

38 STONOXRT State annual NO x oil output emission rate lb/MWh

39 STGNOXRT State annual NO x gas output emission rate lb/MWh

40 STFSNXRT State annual NO x fossil fuel output emission rate lb/MWh

41 STCNXORT State ozone season NO x coal output emission rate lb/MWh

42 STONXORT State ozone season NO x oil output emission rate lb/MWh

43 STGNXORT State ozone season NO x gas output emission rate lb/MWh

44 STFSNORT State ozone season NO x fossil fuel output emission rate lb/MWh

45 STCSO2RT State annual SO 2 coal output emission rate lb/MWh

46 STOSO2RT State annual SO 2 oil output emission rate lb/MWh

47 STGSO2RT State annual SO 2 gas output emission rate lb/MWh

48 STFSS2RT State annual SO 2 fossil fuel output emission rate lb/MWhA-8 

### Table A-1 eGRID2012 Version 1.0 File Structure Year 2009 ST State File (continued).

Field Name Description Unit

49 STCCO2RT State annual CO 2 coal output emission rate lb/MWh

50 STOCO2RT State annual CO 2 oil output emission rate lb/MWh

51 STGCO2RT State annual CO 2 gas output emission rate lb/MWh

52 STFSC2RT State annual CO 2 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 NO x coal input emission rate lb/MMBtu

56 STONOXR State annual NO x oil input emission rate lb/MMBtu

57 STGNOXR State annual NO x gas input emission rate lb/MMBtu

58 STFSNXR State annual NO x fossil fuel input emission rate lb/MMBtu

59 STCNXOR State ozone season NO x coal input emission rate lb/MMBtu

60 STONXOR State ozone season NO x oil input emission rate lb/MMBtu

61 STGNXOR State ozone season NO x gas input emission rate lb/MMBtu

62 STFSNOR State ozone season NO x fossil fuel input emission rate lb/MMBtu

63 STCSO2R State annual SO 2 coal input emission rate lb/MMBtu

64 STOSO2R State annual SO 2 oil input emission rate lb/MMBtu

65 STGSO2R State annual SO 2 gas input emission rate lb/MMBtu

66 STFSS2R State annual SO 2 fossil fuel input emission rate lb/MMBtu

67 STCCO2R State annual CO 2 coal input emission rate lb/MMBtu

68 STOCO2R State annual CO 2 oil input emission rate lb/MMBtu

69 STGCO2R State annual CO 2 gas input emission rate lb/MMBtu

70 STFSC2R State annual CO 2 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 NO x non-baseload output emission rate lb/MWh

74 STNBNXO State ozone season NO x non-baseload output emission rate lb/MWh

75 STNBSO2 State annual SO 2 non-baseload output emission rate lb/MWh

76 STNBCO2 State annual CO 2 non-baseload output emission rate lb/MWh

77 STNBCH4 State annual CH 4 non-baseload output emission rate lb/GWh

78 STNBN2O State annual N 2 O 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/p urchased 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 f uel generation percent (resource mix) 107 STTNPR State total nonrenewables generation percent (resource mix) 108 STTRPR State total renewables gener ation 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 generat ion 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 NO x emissions tons

10 PCNOXOZ PCA ozone season NO x emissions tons

11 PCSO2AN PCA annual SO 2 emissions tons

12 PCCO2AN PCA annual CO 2 emissions tons

13 PCCH4AN PCA annual CH 4 emissions lbs

14 PCN2OAN PCA annual N 2 O emissions lbs

15 PCCO2EQA PCA annual CO 2 equivalent emissions tons 16 PCHGAN PCA annual Hg emissions lbs

17 PCNOXRTA PCA annual NO x total output emission rate lb/MWh

18 PCNOXRTO PCA ozone season NO x total output emission rate lb/MWh

19 PCSO2RTA PCA annual SO 2 total output emission rate lb/MWh

20 PCCO2RTA PCA annual CO 2 total output emission rate lb/MWh

21 PCCH4RTA PCA annual CH 4 total output emission rate lb/GWh

22 PCN2ORTA PCA annual N 2 O total output emission rate lb/GWh

23 PCC2ERTA PCA annual CO 2 equivalent total output emission rate lb/MWh 24 PCHGRTA PCA annual Hg total output emission rate lb/GWh

25 PCNOXRA PCA annual NO x input emission rate lb/MMBtu

26 PCNOXRO PCA ozone season NO x input emission rate lb/MMBtu

27 PCSO2RA PCA annual SO 2 input emission rate lb/MMBtu

28 PCCO2RA PCA annual CO 2 input emission rate lb/MMBtu 29 PCHGRA PCA annual Hg input emission rate lb/BBtu

30 PCNOXCRT PCA annual NO x combustion output emission rate lb/MWh

31 PCNOXCRO PCA ozone season NO x combustion output emission rate lb/MWh

32 PCSO2CRT PCA annual SO 2 combustion output emission rate lb/MWh

33 PCCO2CRT PCA annual CO 2 combustion output emission rate lb/MWh

34 PCCH4CRT PCA annual CH 4 combustion output emission rate lb/GWh

35 PCN2OCRT PCA annual N 2 O combustion output emission rate lb/GWh 36 PCHGCRT PCA annual Hg combustion output emission rate lb/GWh

37 PCCNOXRT PCA annual NO x coal output emission rate lb/MWh

38 PCONOXRT PCA annual NO x oil output emission rate lb/MWh

39 PCGNOXRT PCA annual NO x gas output emission rate lb/MWh

40 PCFSNXRT PCA annual NO x fossil fuel output emission rate lb/MWh

41 PCCNXORT PCA ozone season NO x coal output emission rate lb/MWh

42 PCONXORT PCA ozone season NO x oil output emission rate lb/MWh

43 PCGNXORT PCA ozone season NO x gas output emission rate lb/MWh

44 PCFSNORT PCA ozone season NO x fossil fuel output emission rate lb/MWh

45 PCCSO2RT PCA annual SO 2 coal output emission rate lb/MWh

46 PCOSO2RT PCA annual SO 2 oil output emission rate lb/MWh

47 PCGSO2RT PCA annual SO 2 gas output emission rate lb/MWhA-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 SO 2 fossil fuel output emission rate lb/MWh

49 PCCCO2RT PCA annual CO 2 coal output emission rate lb/MWh

50 PCOCO2RT PCA annual CO 2 oil output emission rate lb/MWh

51 PCGCO2RT PCA annual CO 2 gas output emission rate lb/MWh

52 PCFSC2RT PCA annual CO 2 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 NO x coal input emission rate lb/MMBtu

56 PCONOXR PCA annual NO x oil input emission rate lb/MMBtu

57 PCGNOXR PCA annual NO x gas input emission rate lb/MMBtu

58 PCFSNXR PCA annual NO x fossil fuel input emission rate lb/MMBtu

59 PCCNXOR PCA ozone season NO x coal input emission rate lb/MMBtu

60 PCONXOR PCA ozone season NO x oil input emission rate lb/MMBtu

61 PCGNXOR PCA ozone season NO x gas input emission rate lb/MMBtu

62 PCFSNOR PCA ozone season NO x fossil fuel input emission rate lb/MMBtu

63 PCCSO2R PCA annual SO 2 coal input emission rate lb/MMBtu

64 PCOSO2R PCA annual SO 2 oil input emission rate lb/MMBtu

65 PCGSO2R PCA annual SO 2 gas input emission rate lb/MMBtu

66 PCFSS2R PCA annual SO 2 fossil fuel input emission rate lb/MMBtu

67 PCCCO2R PCA annual CO 2 coal input emission rate lb/MMBtu

68 PCOCO2R PCA annual CO 2 oil input emission rate lb/MMBtu

69 PCGCO2R PCA annual CO 2 gas input emission rate lb/MMBtu

70 PCFSC2R PCA annual CO 2 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 NO x non-baseload output emission rate lb/MWh

74 PCNBNXO PCA ozone season NO x non-baseload output emission rate lb/MWh

75 PCNBSO2 PCA annual SO 2 non-baseload output emission rate lb/MWh

76 PCNBCO2 PCA annual CO 2 non-baseload output emission rate lb/MWh

77 PCNBCH4 PCA annual CH 4 non-baseload output emission rate lb/GWh

78 PCNBN2O PCA annual N 2 O non-baseload output emission rate lb/GWh 79 PCNBHG PCA annual Hg non-baseload ou tput 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 MWhA-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 generat ion 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 oz one 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 NO x emissions tons 11 SRNOXOZ eGRID subregion ozone season NO x emissions tons 12 SRSO2AN eGRID subregion annual SO 2 emissions tons 13 SRCO2AN eGRID subregion annual CO 2 emissions tons 14 SRCH4AN eGRID subregion annual CH 4 emissions lbs 15 SRN2OAN eGRID subregion annual N 2 O emissions lbs 16 SRCO2EQA eGRID subregion annual CO 2 equivalent emissions tons 17 SRHGAN eGRID subregion annual Hg emissions lbs 18 SRNOXRTA eGRID subregion annual NO x total output emission rate lb/MWh 19 SRNOXRTO eGRID subregion ozone season NO x total output emission rate lb/MWh 20 SRSO2RTA eGRID subregion annual SO 2 total output emission rate lb/MWh 21 SRCO2RTA eGRID subregion annual CO 2 total output emission rate lb/MWh 22 SRCH4RTA eGRID subregion annual CH 4 total output emission rate lb/GWh 23 SRN2ORTA eGRID subregion annual N 2 O total output emission rate lb/GWh 24 SRC2ERTA eGRID subregion annual CO 2 equivalent total output emission rate lb/MWh 25 SRHGRTA eGRID subregion annual Hg total output emission rate lb/GWh 26 SRNOXRA eGRID subregion annual NO x input emission rate lb/MMBtu 27 SRNOXRO eGRID subregion ozone season NO x input emission rate lb/MMBtu 28 SRSO2RA eGRID subregion annual SO 2 input emission rate lb/MMBtu 29 SRCO2RA eGRID subregion annual CO 2 input emission rate lb/MMBtu 30 SRHGRA eGRID subregion annual Hg input emission rate lb/BBtu 31 SRNOXCRT eGRID subregion annual NO x combustion output emission rate lb/MWh

32 SRNOXCRO eGRID s ubregion ozone season NO x combustion output emission rate lb/MWh 33 SRSO2CRT eGRID subregion annual SO 2 combustion output emission rate lb/MWh 34 SRCO2CRT eGRID subregion annual CO 2 combustion output emission rate lb/MWh 35 SRCH4CRT eGRID subregion annual CH 4 combustion output emission rate lb/GWh 36 SRN2OCRT eGRID subregion annual N 2 O combustion output emission rate lb/GWh 37 SRHGCRT eGRID subregion annual Hg com bustion output emission rate lb/GWh 38 SRCNOXRT eGRID subregion annual NO x coal output emission rate lb/MWh 39 SRONOXRT eGRID subregion annual NO x oil output emission rate lb/MWh 40 SRGNOXRT eGRID subregion annual NO x gas output emission rate lb/MWh 41 SRFSNXRT eGRID subregion annual NO x fossil fuel output emission rate lb/MWh 42 SRCNXORT eGRID subregion ozone season NO x coal output emission rate lb/MWh 43 SRONXORT eGRID subregion ozone season NO x oil output emission rate lb/MWh 44 SRGNXORT eGRID subregion ozone season NO x gas output emission rate lb/MWh 45 SRFSNORT eGRID subregion ozone season NO x fossil fuel output emission rate lb/MWh 46 SRCSO2RT eGRID subregion annual SO 2 coal output emission rate lb/MWh 47 SROSO2RT eGRID subregion annual SO 2 oil output emission rate lb/MWhA-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 SO 2 gas output emission rate lb/MWh 49 SRFSS2RT eGRID subregion annual SO 2 fossil fuel output emission rate lb/MWh 50 SRCCO2RT eGRID subregion annual CO 2 coal output emission rate lb/MWh 51 SROCO2RT eGRID subregion annual CO 2 oil output emission rate lb/MWh 52 SRGCO2RT eGRID subregion annual CO 2 gas output emission rate lb/MWh 53 SRFSC2RT eGRID subregion annual CO 2 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 NO x coal input emission rate lb/MMBtu 57 SRONOXR eGRID subregion annual NO x oil input emission rate lb/MMBtu 58 SRGNOXR eGRID subregion annual NO x gas input emission rate lb/MMBtu 59 SRFSNXR eGRID subregion annual NO x fossil fuel input emission rate lb/MMBtu 60 SRCNXOR eGRID subregion ozone season NO x coal input emission rate lb/MMBtu 61 SRONXOR eGRID subregion ozone season NO x oil input emission rate lb/MMBtu 62 SRGNXOR eGRID subregion ozone season NO x gas input emission rate lb/MMBtu 63 SRFSNOR eGRID subregion ozone season NO x fossil fuel input emission rate lb/MMBtu 64 SRCSO2R eGRID subregion annual SO 2 coal input emission rate lb/MMBtu 65 SROSO2R eGRID subregion annual SO 2 oil input emission rate lb/MMBtu 66 SRGSO2R eGRID subregion annual SO 2 gas input emission rate lb/MMBtu 67 SRFSS2R eGRID subregion annual SO 2 fossil fuel input emission rate lb/MMBtu 68 SRCCO2R eGRID subregion annual CO 2 coal input emission rate lb/MMBtu 69 SROCO2R eGRID subregion annual CO 2 oil input emission rate lb/MMBtu 70 SRGCO2R eGRID subregion annual CO 2 gas input emission rate lb/MMBtu 71 SRFSC2R eGRID subregion annual CO 2 fossil fuel input emission rate lb/MMBtu 72 SRCHGR eGRID subregion annual Hg c oal input emission rate lb/BBtu 73 SRFSHGR eGRID subregion annual Hg foss il fuel input emission rate lb/BBtu 74 SRNBNOX eGRID subregion annual NO x non-baseload output emission rate lb/MWh 75 SRNBNXO eGRID subregion ozone season NO x non-baseload output emission rate lb/MWh 76 SRNBSO2 eGRID subregion annual SO 2 non-baseload output emission rate lb/MWh 77 SRNBCO2 eGRID subregion annual CO 2 non-baseload output emission rate lb/MWh 78 SRNBCH4 eGRID subregion annual CH 4 non-baseload output emission rate lb/GWh 79 SRNBN2O eGRID subregion annual N 2 O non-baseload output emission rate lb/GWh

80 SRNBC2ER eGRID subregion annual CO 2 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 tota l nonrenewables net generation MWh 94 SRGENATR eGRID subregion annual tota l renewables net generation MWhA-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 to tal combustion net generation MWh 97 SRGENACN eGRID subregion annual to tal noncombustion net generation MWh 98 SRCLPR eGRID subregion coal gener ation 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 gene ration percent (resource mix) 102 SRHYPR eGRID subregion hydro gene ration 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/purchas ed fuel generation percent (resource mix) 109 SRTNPR eGRID subregion total nonrenewabl es generation percent (resource mix) 110 SRTRPR eGRID subregion total renewabl es generation percent (resource mix) 111 SRTHPR eGRID subregion total nonhydro renew ables generation percent (resource mix) 112 SRCYPR eGRID subregion total combusti on generation percent (resource mix) 113 SRCNPR eGRID subregion total noncombusti on 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 s eason net generation MWh 9 NRNOXAN NERC region annual NO x emissions tons 10 NRNOXOZ NERC region ozone season NO x emissions tons 11 NRSO2AN NERC region annual SO 2 emissions tons 12 NRCO2AN NERC region annual CO 2 emissions tons 13 NRCH4AN NERC region annual CH 4 emissions lbs 14 NRN2OAN NERC region annual N 2 O emissions lbs 15 NRCO2EQA NERC region annual CO 2 equivalent emissions tons 16 NRHGAN NERC region annual Hg emissions lbs 17 NRNOXRTA NERC region annual NO x total output emission rate lb/MWh 18 NRNOXRTO NERC region ozone season NO x total output emission rate lb/MWh 19 NRSO2RTA NERC region annual SO 2 total output emission rate lb/MWh 20 NRCO2RTA NERC region annual CO 2 total output emission rate lb/MWh 21 NRCH4RTA NERC region annual CH 4 total output emission rate lb/GWh 22 NRN2ORTA NERC region annual N 2 O total output emission rate lb/GWh 23 NRC2ERTA NERC region annual CO 2 equivalent total output emission rate lb/MWh 24 NRHGRTA NERC region annual Hg total output emission rate lb/GWh 25 NRNOXRA NERC region annual NO x input emission rate lb/MMBtu

26 NRNOXRO NERC re gion ozone season NO x input emission rate lb/MMBtu 27 NRSO2RA NERC region annual SO 2 input emission rate lb/MMBtu 28 NRCO2RA NERC region annual CO 2 input emission rate lb/MMBtu 29 NRHGRA NERC region annual Hg input emission rate lb/BBtu 30 NRNOXCRT NERC region annual NO x combustion output emission rate lb/MWh 31 NRNOXCRO NERC region ozone season NO x combustion output emission rate lb/MWh 32 NRSO2CRT NERC region annual SO 2 combustion output emission rate lb/MWh 33 NRCO2CRT NERC region annual CO 2 combustion output emission rate lb/MWh 34 NRCH4CRT NERC region annual CH 4 combustion output emission rate lb/GWh 35 NRN2OCRT NERC region annual N 2 O combustion output emission rate lb/GWh 36 NRHGCRT NERC region annual Hg combustion output emission rate lb/GWh 37 NRCNOXRT NERC region annual NO x coal output emission rate lb/MWh 38 NRONOXRT NERC region annual NO x oil output emission rate lb/MWh 39 NRGNOXRT NERC region annual NO x gas output emission rate lb/MWh 40 NRFSNXRT NERC region annual NO x fossil fuel output emission rate lb/MWh 41 NRCNXORT NERC region ozone season NO x coal output emission rate lb/MWh

42 NRONXORT NERC re gion ozone season NO x oil output emission rate lb/MWh

43 NRGNXORT NERC re gion ozone season NO x gas output emission rate lb/MWh 44 NRFSNORT NERC region ozone season NO x fossil fuel output emission rate lb/MWh 45 NRCSO2RT NERC region annual SO 2 coal output emission rate lb/MWh 46 NROSO2RT NERC region annual SO 2 oil output emission rate lb/MWh 47 NRGSO2RT NERC region annual SO 2 gas output emission rate lb/MWhA-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 SO 2 fossil fuel output emission rate lb/MWh 49 NRCCO2RT NERC region annual CO 2 coal output emission rate lb/MWh 50 NROCO2RT NERC region annual CO 2 oil output emission rate lb/MWh 51 NRGCO2RT NERC region annual CO 2 gas output emission rate lb/MWh 52 NRFSC2RT NERC region annual CO 2 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 NO x coal input emission rate lb/MMBtu 56 NRONOXR NERC region annual NO x oil input emission rate lb/MMBtu 57 NRGNOXR NERC region annual NO x gas input emission rate lb/MMBtu 58 NRFSNXR NERC region annual NO x fossil fuel input emission rate lb/MMBtu 59 NRCNXOR NERC region ozone season NO x coal input emission rate lb/MMBtu

60 NRONXOR NERC re gion ozone season NO x oil input emission rate lb/MMBtu

61 NRGNXOR NERC re gion ozone season NO x gas input emission rate lb/MMBtu 62 NRFSNOR NERC region ozone season NO x fossil fuel input emission rate lb/MMBtu 63 NRCSO2R NERC region annual SO 2 coal input emission rate lb/MMBtu 64 NROSO2R NERC region annual SO 2 oil input emission rate lb/MMBtu 65 NRGSO2R NERC region annual SO 2 gas input emission rate lb/MMBtu 66 NRFSS2R NERC region annual SO 2 fossil fuel input emission rate lb/MMBtu 67 NRCCO2R NERC region annual CO 2 coal input emission rate lb/MMBtu 68 NROCO2R NERC region annual CO 2 oil input emission rate lb/MMBtu 69 NRGCO2R NERC region annual CO 2 gas input emission rate lb/MMBtu 70 NRFSC2R NERC region annual CO 2 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 NO x non-baseload output emission rate lb/MWh 74 NRNBNXO NERC region ozone season NO x non-baseload output emission rate lb/MWh 75 NRNBSO2 NERC region annual SO 2 non-baseload output emission rate lb/MWh 76 NRNBCO2 NERC region annual CO 2 non-baseload output emission rate lb/MWh 77 NRNBCH4 NERC region annual CH 4 non-baseload output emission rate lb/GWh 78 NRNBN2O NERC region annual N 2 O 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 unkno wn/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 nonhyd ro renewables net generation MWh 94 NRGENACY NERC region annual total combustion net generation MWhA-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 generati on percent (resource mix) 100 NRHYPR NERC region hydro generation percent (resource mix) 101 NRBMPR NERC region biomass generati on percent (resource mix) 102 NRWIPR NERC region wind generati on percent (resource mix) 103 NRSOPR NERC region solar generati on percent (resource mix) 104 NRGTPR NERC region geothermal genera tion percent (resource mix) 105 NROFPR NERC region other fossil generat ion percent (resource mix) 106 NROPPR NERC region other unknown/purchased f uel generation percent (resource mix) 107 NRTNPR NERC region total nonrenewables generation percent (resource mix) 108 NRTRPR NERC region total renewables ge neration percent (resource mix) 109 NRTHPR NERC region total nonhydro renewabl es generation percent (resource mix) 110 NRCYPR NERC region total combustion gener ation percent (resource mix) 111 NRCNPR NERC region total noncombustion gener ation 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 NO x emissions tons

8 USNOXOZ U.S. ozone season NO x emissions tons

9 USSO2AN U.S. annual SO 2 emissions tons

10 USCO2AN U.S. annual CO 2 emissions tons

11 USCH4AN U.S. annual CH 4 emissions lbs

12 USN2OAN U.S. annual N 2 O emissions lbs

13 USCO2EQA U.S. annual CO 2 equivalent emissions tons 14 USHGAN U.S. annual Hg emissions lbs

15 USNOXRTA U.S. annual NO x total output emission rate lb/MWh

16 USNOXRTO U.S. ozone season NO x total output emission rate lb/MWh

17 USSO2RTA U.S. annual SO 2 total output emission rate lb/MWh

18 USCO2RTA U.S. annual CO 2 total output emission rate lb/MWh

19 USCH4RTA U.S. annual CH 4 total output emission rate lb/GWh

20 USN2ORTA U.S. annual N 2 O total output emission rate lb/GWh

21 USC2ERTA U.S. annual CO 2 equivalent total output emission rate lb/MWh 22 USHGRTA U.S. annual Hg total output emission rate lb/GWh

23 USNOXRA U.S. annual NO x input emission rate lb/MMBtu

24 USNOXRO U.S. ozone season NO x input emission rate lb/MMBtu

25 USSO2RA U.S. annual SO 2 input emission rate lb/MMBtu

26 USCO2RA U.S. annual CO 2 input emission rate lb/MMBtu 27 USHGRA U.S. annual Hg input emission rate lb/BBtu

28 USNOXCRT U.S. annual NO x combustion output emission rate lb/MWh

29 USNOXCRO U.S. ozone season NO x combustion output emission rate lb/MWh

30 USSO2CRT U.S. annual SO 2 combustion output emission rate lb/MWh

31 USCO2CRT U.S. annual CO 2 combustion output emission rate lb/MWh

32 USCH4CRT U.S. annual CH 4 combustion output emission rate lb/GWh

33 USN2OCRT U.S. annual N 2 O combustion output emission rate lb/GWh 34 USHGCRT U.S. annual Hg combustion output emission rate lb/GWh

35 USCNOXRT U.S. annual NO x coal output emission rate lb/MWh

36 USONOXRT U.S. annual NO x oil output emission rate lb/MWh

37 USGNOXRT U.S. annual NO x gas output emission rate lb/MWh

38 USFSNXRT U.S. annual NO x fossil fuel output emission rate lb/MWh

39 USCNXORT U.S. ozone season NO x coal output emission rate lb/MWh

40 USONXORT U.S. ozone season NO x oil output emission rate lb/MWh

41 USGNXORT U.S. ozone season NO x gas output emission rate lb/MWh

42 USFSNORT U.S. ozone season NO x fossil fuel output emission rate lb/MWhA-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 SO 2 coal output emission rate lb/MWh

44 USOSO2RT U.S. annual SO 2 oil output emission rate lb/MWh

45 USGSO2RT U.S. annual SO 2 gas output emission rate lb/MWh

46 USFSS2RT U.S. annual SO 2 fossil fuel output emission rate lb/MWh

47 USCCO2RT U.S. annual CO 2 coal output emission rate lb/MWh

48 USOCO2RT U.S. annual CO 2 oil output emission rate lb/MWh

49 USGCO2RT U.S. annual CO 2 gas output emission rate lb/MWh

50 USFSC2RT U.S. annual CO 2 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 NO x coal input emission rate lb/MMBtu

54 USONOXR U.S. annual NO x oil input emission rate lb/MMBtu

55 USGNOXR U.S. annual NO x gas input emission rate lb/MMBtu

56 USFSNXR U.S. annual NO x fossil fuel input emission rate lb/MMBtu

57 USCNXOR U.S. ozone season NO x coal input emission rate lb/MMBtu

58 USONXOR U.S. ozone season NO x oil input emission rate lb/MMBtu

59 USGNXOR U.S. ozone season NO x gas input emission rate lb/MMBtu

60 USFSNOR U.S. ozone season NO x fossil fuel input emission rate lb/MMBtu

61 USCSO2R U.S. annual SO 2 coal input emission rate lb/MMBtu

62 USOSO2R U.S. annual SO 2 oil input emission rate lb/MMBtu

63 USGSO2R U.S. annual SO 2 gas input emission rate lb/MMBtu

64 USFSS2R U.S. annual SO 2 fossil fuel input emission rate lb/MMBtu

65 USCCO2R U.S. annual CO 2 coal input emission rate lb/MMBtu

66 USOCO2R U.S. annual CO 2 oil input emission rate lb/MMBtu

67 USGCO2R U.S. annual CO 2 gas input emission rate lb/MMBtu

68 USFSC2R U.S. annual CO 2 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 NO x non-baseload output emission rate lb/MWh

72 USNBNXO U.S. ozone season NO x non-baseload output emission rate lb/MWh

73 USNBSO2 U.S. annual SO 2 non-baseload output emission rate lb/MWh

74 USNBCO2 U.S. annual CO 2 non-baseload output emission rate lb/MWh

75 USNBCH4 U.S. annual CH 4 non-baseload output emission rate lb/GWh

76 USNBN2O U.S. annual N 2 O 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/pur chased fuel net generation MWhA-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 noncom bustion 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 generat ion percent (resource mix) 106 USTRPR U.S. total renewables generat ion 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 generati on 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 gr id gross loss as a percent [= 100 * (GENERAT + FRGNINTC+ INTRCHNG - CONSUMP) / GENERAT) ] %

7 YEAR Data yearB-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

.