1Comments Received to-Date on the Draft 2018 Base Case ProjectionsVersion: December 21, 2005Commenter Comment Affects2002?ResponseAlice Edwards,AK DEC, viaemail 10/6/051. We totaled each pollutant forall units/processes at the facility and compared it to the overall PTEin the permit. When a projection exceeded the PTE, we highlighted it in bright yellow in columnAJ. In column AL we took the PTE for the pollutant and spread it across the various units based onthe 2018 projections.So for those projections that exceededthe PTE you should be able to replacethe value in column AJ with the value in columnAL. A comment field indicates what the PTE isfor that pollutant for that facility (if needed it indicates which units it applies to; some units hadspecific NOx limits.) For thosepollutants/units that did not exceedthe permit PTE, we did make anote that it was not exceeded and what the PTE was...N ERG will revise the projectionsfor the sources/records asshown in AK DEC’sspreadsheet for 2018.2. Alaska recently reached an enforceableagreement with British Petroleum and Conoco Phillipsthat means they will reduce the sulfur content in theirdiesel fuel for all their stationary sources to 15ppm or less before 2018. We would like to have this reflected in the 2018 projections for thosefacilities. I have highlighted in column AJ in bright green the SO2 projections for those facilities,but I am not sure the best way to make an adjustment to the projection.10/31: Sent spreadsheet containing facilities and existing S content to be affected by agreement.N One way to accomplish thiswould be to determine currentS content of diesel fromaffected facilities, and reduceSOxemissions accordingly.ERG will make theseadjustments using datareceived from AK DEC.3. There were two facilities that I had a hard time mapping to one of our permits (there were morethan one possibility) for the PTE comparisons and these facilities may be duplicated in thespreadsheet. I have highlighted those records with a light yellow background. They are CHENAand ALASKA ELECTRIC LIGHT & POWER. I was notsure whether CHENA is the same as theAurora Energy Chena Power Plant (which is alsoin the spreadsheet) orthe GVEA Chena 6 PowerPlant (which is not in the spreadsheet).I think the ALASKA ELECTRIC LIGHT & POWERfacility may be the same as the AEL&P Lemon Creekfacility (which is also in the spreadsheet) butthere is also a generating station AEL&P Auke Bay.I don’t know if there are any other identifiersthat are in the data set that might help us sort this out. Because of the additional pollutants that arein the CHENA and ALASKA ELECTRIC LIGHT & Power records, I don’t think this data camefrom DEC’s submittal to the NEI.Y ERG determined that CHENAand ALASKA ELECTRICLIGHT & POWER records arenot needed in the 2002 EI. Wewill remove these from 2002and 2018 EIs.4. I was unable at this time to check theElmendorf AFB records against the permit PTE.Elmendorf now has multiple permits and I wasn’t able to figure out how to match up the units andemissions to those permits. For this reason, you will not see edits in Column AL for this facility. Iwas also not able to verify the PTEsfor the Unocal Granite Point tank farm.N ERG will not make anychanges to the 2018projections for ElmendorfARB and Unocal Granite Pointtank farm.Latha Toopal, AZDEQ, via email9/22/05Attached is a spreadsheet listing the post-2002data for 3 sources, Douglas Lime Plant, BensonCompressor Station and North Star Steel. While Douglas Lime plant restarted operations in October2004, Benson did not operate in 2004. North Star Steel(now Nucor Steel Kingman LLC)hasN ERG will make these changes.2Commenter Comment Affects2002?Responseterminated their air quality permit. Also listedis the stack data for Benson Compressor Station.One unit for Douglas Lime Plant is listed for NOx emissions. The Emission Unit ID is 1 and theProcess ID is 1. This unit is a Primary Screenand only PM and PM10 emissions are emitted. I amnot sure if this was an error or incorrect ID's have been used.Y ERG will correct this problemand review the NOx emissionsfrom 2002 and 2018 EIs.There is another major source of HAP that is pending. I am not sure if this facility needs to beadded. The facility name is North American Sleek Craft Inc. Let me know if you need the PTE infofor this facility. The facility is currently operating.N ERG will not add this facilityin the absence of actualemissions data.Latha Toopal, AZDEQ, via email9/28/051. There are 29 minor sources that have been carried forward from past inventories. These 29sources account for 1% of the total baseline emissions. Some of these sources have beenpermanently closed. Either theyshould be excluded or listed separately. I have attached an excelspreadsheet listing all the minor facilities.Y ERG will exclude these minorsources from the 2002 and2018 EIs.2. A number of facilities have been listed withboth old and new ID's. The old ID's need to bedeleted. Following are the list of facilities:a. Mojave Topock Compressor Station/Topock Compressor Station - Current Facility ID401515581 and Old ID is 401500815.b.. Sierrita Mine - ID's - 40191567 and 400714620. The correct one is 40191567. I wonder howthey got listed under 2 different counties.c. Phoenix Cement Company - Old facility ID - 402500421, Current ID is 40252393d. Yuma Cogeneration Associates - Old ID-402700141, New ID is 4027492e. Copper Mountain Landfill - Current ID -40277178Y ERG will make thesecorrections in the 2002 and2018 EIs.3. Lake Havasu City Landfill - ID 401500000 - This facility is not permitted. Y ERG will remove this.4. South Point Energy, LLC, - ADEQ has notpermitted this facility. Y ERG will remove this.5. Two sources, EPNG -Window Rock and Navajo Generating Station have the Tribal Code set to"0". These are located on Tribal land.Y We will change the tribal codeto 780 for Navajo Nation. TheEPNG-Window Rock site wastaken from the 1999 NEI andwill be removed, rather thantransferred to tribal land.6. Facility ID 54 -Magma Copper is now called BHP Copper. N ERG will make this change(post-2002)Latha Toopal, AZDEQ, viatelephone 10/3/05There are some duplicate records in the projections that are under old facility IDs. These need to beremoved. Will send an email listing the records to remove. One example is the EGUs for Salt RiverProject and Coronado Generating Station are apparently duplicated for CO and VOC.Y ERG will make these changesin coordination with commentsfrom SRP (below).Latha Toopal, AZDEQ, via email10/6/05I have completed a thorough review of the Point source data. Quite a few errors were noted. Wehave a few sources that need to be deleted. Whenwe revised our facility IDs after we moved to anOracle-based system, we indicatedthis to EPA and they stated that the IDs would be changed.Looks like not all the IDs have been changed. Some of the facilities are hence listed twice. Thereare some pollutants that are duplicated. Looks like they were manually entered and not from NEI.I have the following files attached:Y ERG will make all changesrequested by ADEQ. Alldeletions/revisions affect both2002 and 2018 emissions.3Commenter Comment Affects2002?ResponseErrors.xls – All facilities that either need to be deleted or revised. I have them color coded. Yellowfor deletion and green for revisions. I also have comments stating so in the last column. I have alsoattempted to note the line # in the first column from your original spreadsheet.AZ_Projections_Errors.xls – This is the original file for AZ where I have highlighted the rows thatneed attention.Let me know if you have questions and I will be glad to explain them. Thank you.Randy Sedlacek,AZ DEQ, viaemail 10/7/05[Main text of memo received from AZ DEQ:] Air Quality Division staffreviewed the projectedchanges for Year 2018 Arizona Area Source Emissions for reasonableness. However, they were notable to do a rigorous review of the projected emission changes for the majority of the Arizona AreaSources since the underlying inputs and assumptions that were used in the EGAS and EIAprojection models were not provided by ERG.N General information iscontained in the Reviewer’sMemo that accompanied thedraft 2018 projections:http://www.wrapair.org/forums/ssjf/documents/eictts/projections.htmlERG will provide details onthe EGAS and EIA modelinputs in the draft and finalreports.A case in point is the projected emissions from agriculture. Since ERG provided data on the numberof Arizona harvested acres in Year 2002 and Year 2018, Air Quality Division Unit staff were able tocompare these data with recenttrends in Arizona harvested acres. It was found that ERG’sprojected increase in Arizona harvested acres did not correspond torecent trends cited by USDAstaff that harvested acres in Arizona are decreasing. The following text lists the Air QualityDivision’s specific recommendations for the Arizona Area Source portion ofthe draft WRAP Year2018 Emissions Inventory (EI):CReduce Agricultural Acreage In Year 2018– The WRAP Year 2018 EI spreadsheet forArizona Area Sources shows a growth factor of1.0361 for harvested acres in Arizona betweenthe Years 2002 to 2018 and lists 226,900,000 acres for Year 2002 and 235,100,000 acres forYear 2018. These harvested acre data appear tobe total harvested acres for the United Statesand not total harvested acres in Arizona. The Year 2002 Census of Agriculture:http://www.nass.usda.gov/census/census02/volume1/az/st04_1_008_008.pdflists Arizona’sharvested acres as decreasing over time between Year 1997 and Year 2002 (1,026,359harvested acres decreasing to 887,966 harvestedacres, respectively). This corresponds to a“growth” factor of 0.87 for this 5-year period, and extrapolating to Year 2018, a factor of 0.65.This reduction in agricultural land, due mainly to conversion from agricultural uses toresidential / commercial uses, has also been observed in ADEQ air quality studies in MaricopaCounty and Yuma County. However, projected increases in agricultural land on tribal nationsin Arizona may offset the projected decreases in agricultural land due to conversion tocommercial and residential uses. Thus, the Air Quality Division recommends that Arizona’stotal harvested acres be held constant between the Years 2002 and 2018.N Since state-level USDAacreage projections are notavailable, the only feasibleapproach was to use thenational average as providedby USDA (1.036), and thenreceive comments fromindividual states regardingtheir reasonableness.ERG will change the growthfactor for AZ harvested acresbetween 2002 and 2018 to 1.0(no growth).10/2705: Maricopa County AZhas been consulted on thisissue, and concurs with thisapproach.•Additional Area Source Categories–It appears that some area source categories were notN These emission categories4Commenter Comment Affects2002?Responseincluded in the WRAP Year 2018 EI, at leastfor some Arizona counties. For example, itappears that the source categories of lawn andgarden equipment, recreational boating (Arizonahas one of the highest per capita boat ownership in the United States), prescribed fires andwildfires, and open burning were not included. The Air Quality Division recommends thatemissions from lawn and garden equipment, recreational boating, prescribed fires and wildfires,and open burning be included in the WRAP Year 2018 EI.were not part of the scope ofthis point and area sourceinventory, but are addressedelsewhere in the WRAP effort.The scope of this particularpoint/area 2018 projection isdescribed in the Reviewer’sMemo that accompanied thedraft 2018 projections.•Review Manufacturing Growth Assumptions- The growth factor, 3.5658, in the WRAP Year2018 spreadsheet for Industrial and Commercial Machinery and Computer Equipment (SCCcodes in the SIC 35 category) in Arizona appears to be too high. Arizona has not had majorgrowth in the manufacturing sector during the recent past. Established corporations have beensending manufacturing operations out of the country. With free trade agreements such asNAFTA and lower wages in Mexico, the trend seems to be loss rather than growth in thissector. The Air Quality Division recommends that ERG review the assumptions used todevelop the manufacturing growth factor for Arizona to ensure that it is not overly optimistic.N ERG used the EGAS-generatedgrowth factorfor these SCCs,which is consistent with theWRAP-wide method selectedfor this project. Note that AZ’stotal projected emissions forthe SCCs in the SIC 35category (an area source) is400 tons of VOC. While thegrowth factor may beoverestimated, changing itwould have little effect on theoverall inventory for AZ or theWRAP. However, if AZ DEQprovides an alternative growthfactor, then ERG can replacethe 3.5658 factor in the 2018base case calculation.•Review Growth Factors Based on Population– Many of the growth factors in the WRAP Year2018 spreadsheet have the exact same value for each county in Arizona. The Air QualityDivision recommends that ERG use the county population growth factors compiled by theArizona Department of Economic Security for those Arizona growth factors based onpopulation.N The most recent version ofEGAS (5.0) does not currentlyallow input of externalpopulation data (i.e., thisfunctionality is not working).Therefore, ERG was not ableto use population growth datafrom external files with theEGAS model (e.g., fromMaricopa County). Due to thismodel limitation, theProjections Work Group hasagreed not topursue use of5Commenter Comment Affects2002?Responseother population growthprojections.Arizona’s General RecommendationsIt is difficult for staff to easily review thelarge spreadsheets of emissions, projections, andreductions in the current format provided by ERG, especially under the limited time constraintsrequested by ERG. For example, some of the spreadsheets contained 10,000 lines and close to 2,000growth factors. The calculations and assumptions used by ERG should be transparent to thereviewers.N The format of the spreadsheets,including the level of detailthey provide, was thoroughlyvetted through the WRAPSSJF/Projection Work Group(which includes a MaricopaCounty representative).Additional detail on modelinputs and assumptions will beprovided in the draft and finalreports.For future ERG requests for review of emissions inventories, Air Quality Division staff recommendthe following items:CDocumentation– Provide more documentation on the inputs and underlying assumptions usedto calculate the future year emissions inventories. This should include an explanation of thehow the EGAS and EIA models work, and specific notation with the growth factors in thespreadsheets (e.g., there are 1,806 growth factors in the Arizona Area Source spreadsheet. Itwould be useful to have short explanations of the basis for the growth factors in thespreadsheet). Also, it was unclear from ERG’s documentation of the source for the EIA model,source for USDA agricultural data (e.g., from Census of Agriculture), and which version of theEGAS model was used.N ERG will include details on theEGAS inputs/outputs, and EIAoutputs that were used in theprojections. These details willbe included in the draft andfinal reports. As appropriate,we will add details to thespreadsheets (e.g., USDAreference).•Trends– Percent change data and graphs showing the change in emissions between Year 2002and Year 2018 would assist reviewers in assessing the reasonablenessof projected emissionchanges.N ERG has developed these; theyare posted on the WRAP/SSJF/Projections Work Group webpage under Draft Documents:http://www.wrapair.org/forums/ssjf/documents/eictts/projections.htmlERG will update these tablesafter incorporating changesbased on comments received,and post them for review.Additional summary tableswith more detail will beprovided.6Commenter Comment Affects2002?Response•Text Labels– Converting FIPS to county names and converting SCC codes to descriptivenames of the emission source categories would assist reviewers since they would not have toconvert these codes themselves.N ERG will do this in the finalversion of the spreadsheets.•Other State’s Comments– Compile a table of all reviewers’ comments and how ERGresponded to the comments. Providing this table back to the reviewers would help ensure thatall major areas of the emissions inventory review have been addressed.N ERG has developed this tableand will post it after allcomments are received.In summary, it is essential that all technicaland administrative limitationsfor each growth factor,and any assumed emissions reductions due to control measures, be discussed and evaluated beforethe final methodology and calculations for the WRAPYear 2018 Emissions Inventory are accepted.This will ensure that the highest quality emissions inventory is used for WRAP modeling.N The draft and final reports willdiscuss the general technicaland administrative limitationsof the growth factors (e.g.,state-level versus countylevel); however, individuallimitations for “each growthfactor” will not be discussedunless particular factors standout as highly uncertain due tolimited data or other issues.The draft and final reports willinclude a discussion of thecontrols applied.All WRAP members will beprovided opportunities forreview and comment on allwork products, reports, etc.from this project.Bob Downing,Maricopa Co.,AZ, via email11/10/05I concur with your proposal to add the following EGUs to the 2018 inventory: APS West PhoenixPower Plant (CC5a and CC5B). These units came online during 2003. “...we’ve discovered someerrors in the present versions of the NEI and WERAP EDMS data bases for EGUs in MaricopaCounty. A number of facilities here have a mix of units, some of which report data to EPA/CAMDand others, which do not. We recently noted that EPA’s data augmentation procedures, in whichstate-supplied NOx and SOx emissions data is replaced by data reported from the utilities to CAMD,only looked at the entire facility level, and thus inadvertently deleted valid emissions data....theOcotillo Power Plant...APS West Phoenix...Kyrene.”(Mr. Downing provided a spreadsheet withthe missing units/emissions.”Y All changes were made to the2018 base case(EGUs/emissions were addedthat had been dropped viaaugmentation). However, thechanges for Ocotillo, APSWest Phoenix, and Kyrene thatimpact the 2002 emissionswere notmade to the 2002inventory; these could be madeif/when that inventory isrevised.Curtis Taipale, Regarding new “future” power plants, for purposes of the projections, place them as follows: N Theprocedure for sitingof7Commenter Comment Affects2002?ResponseRoy Doyle, DaveThayer, RayMohr, CDPHE,via telephone10/4/051 coal-fired EGU @ existing Lamar Power Authority NG plant.1 coal-fired EGU @ existing Pawnee plant (FIPS 08-087)1 coal-fired EGU @ existing Comanche plant (FIPS 08-101)3 NG EGUs in Garfield Co. (FIPS 08-007)3 NG EGUs in Weld Co. (FIPS 08-123)3 NG EGUs in Archuleta Co. (FIPS 08-007)future EGUs was changed afterthe draft spreadsheets werereleased. Future siting is nowbased upon new EGUannouncements and location ofexisting EGUs/infrastructure.Curtis Taipale,Roy Doyle, DaveThayer, RayMohr, CDPHE,via telephone10/4/05We submitted corrections to the 2002 NEI to EPA on 9/30/04, which are not reflected in the datacontained in the 2002 inventory for WRAP. These changes affected the county codes for severalsources, mostly smaller VOC point sources. These may not be worth trying to change in the WRAPprojections since visibility impacts would be small relative to other sources.N No action by ERG. A reviewof the files submitted to EPAon 9/30/04 indicates that pointsource data for 2003 (not 2002)were submitted. Nonpointsource county code changes for2002 were submitted, but forsome reason were notprocessed (note that ERG isnot the EPA nonpoint sourcecontractor, so we have noinsight into this problem).Area source VOC reductions due to Denver EAC: reduce the condensate tank VOC emissions by47.5% in the affected counties; this is for 1 SCC (40400311), only.N ERG will make this adjustmentunder “Controls” in thespreadsheet. Note that this is apoint source SCC affiliatedwith o&g point sources.Note that SunCor refining recently bought Valero. These will be combined into 1 facility (locatedacross the street from eachother) for future inventories.N ERG will add this comment tothe records for each refinery.Roy Doyle,CDPHE viatelephone 11/8/05Add two EGUs that came on-line after 2002: BlueSpruce (2003), Rocky Mountain Energy Center(2004)N ERG will add these to the 2018base case.Chris Ramsdell,ID DEQ, viaemail 9/30/05Thanks for all of the information you (ERG) are providing on this data. It is so much easier tounderstand when it is explained so well. Idaho believes the 2018 point and area source dataprojections are good as presented by ERG. We feel any exceedances of permit limits, if any, willbetter allow for the facilities' actual growth thana permit limit would show. Note: At this time,resources do not allow for a detailed review of thepermits and comparison to the ERG projections.N No response by ERG.We would like to add three (3) new EGUs tothe 2018 EGU projections. They are as follows:700 megawatt, coal-fired plant in Jerome520 megawatt, coal gasification plant in Pocatello600 megawatt, coal gasification plant in Soda SpringsN The one future allocated coalfired EGU was sited in JeromeCounty.Also, we have one question on the data. With the new EGUs, why not apply BACT controls ratherthan BART? BACT is possibly more controlling.N Based on many commentsreceived on this issue, newEGU emissions will be8Commenter Comment Affects2002?Responsechanged to BACT.Julie Merkel, MTDEQ, via email9/29/05The Montana Department of Environmental Quality(Department) has reviewed ERG's Draft Reportregarding 2018 projected emissions inventory. The Department has the following concerns andcomments:1. The projected coal-fired EGUs for Montana in ERG's report show a prediction of no growth forthe state. At this time, Montana has one new coal-fired EGU that will be on line within a year(Rocky Mountain Power), another that is permitted (Roundup/Bull Mountain), and an applicationfor a third (Great Falls - Southern MT Electric Generation and Transmission Cooperative -Highwood Generating Station). There are also afew others that the Department anticipates willsubmit applications. This appears to be the area ofgrowth occurring in Montana at this time. TheDepartment recommends that Montana should predict at least 3 new coal-fired EGUs in theprojected future.N The Rocky Mountain Powerand Roundup/Bull MountainEGUs were included in the2018 inventory. The oneadditional future allocatedcoal-fired EGU was sited inCascade County (i.e., nearGreat Falls).2. The projected natural gas EGU's for Montana predicts 7 new facilities. Currently, the Departmenthas four permitted natural gas EGU's that are not on line. Of those four, one is scheduled tobegin operation within the next year. The other 3 (permitted but not built) have no start-up date.The Department does not believe this will be anarea of growth in the projected future. TheDepartment recommends dropping the predicted growth from 7 natural gas EGU's to 3 or 4.N Based on revised allocations,no future natural-gas firedEGUs are needed in Montana.3. There are several Montana coal-fired EGUs(in operation) that arenot on ERGs emissioninventory list. These include:Montana-Dakota Utilities Glendive Generating Station (AFS #30-021-0005)Montana-Dakota Utilities - Miles City (AFS #30-017-0002)Colstrip Energy Limited Partnership (CELP) (AFS #30-087-0007)Thompson River Co-Gen (TRC) (AFS #30-089-0009)Y ERG confirmed the EGUs andtheir IDs in the 2002 file withMontana staff. They are all inthe file.4. PPL Montana, LLC - Colstrip Steam Electric Station's 4 EGU units are listed under ColstripEnergy Limited Partnership -- this is wrong, CELPis a separate facility, not associated with PPLMontana. However, it is located near the PPL Montana Colstrip facility. (Note in comment #3 thatCELP is not on the list).CELP - AFS #30-087-0007Colstrip Units 1, 2, 3, and 4 - AFS #30-111-0015Y ERG confirmed the ColstripSite ID with Montana staff. Inthe 2002 file the Site ID is 087-0008. The Site ID 111-0015 inthe 2002 file is currently forPPL Montana, JE CorettePlant.5. In July 2005, Bob Jeffrey had some correspondence with you (Paula) regarding the Refineryconsent decree reductions. Was this enough information regarding this issue, or do you need more?N See response to J. Hughes,below.6. These questions may have already been answered, but, (a) what is the reason that there are PMcondensable for area sources and not for point sources? and (b) Why do some of the area sourceswith the same SCC code have different emissions numeric values?N (a) Some of the PM estimatesfor area sources were gap-filledby EPA during the NEIdevelopment; the point sourcePM emissions were not gapfilled for missing species. (b)County-level emissions forboth 2002 and 2018 for certain9Commenter Comment Affects2002?ResponseSCCs were developed usingpopulation surrogates, thus themagnitude of these emissionswill vary by county population.Jim Hughes, MTDEQ, viatelephone 9/29/05There are going to be additional NOxand SO2reductions from refineries in Montana, although thesehave not been made official and are not yet reflected in their permits. I will try to note these on thespreadsheet.N Fine. We will note theseanecdotally in thespreadsheets, because thereductions or not yet official.Lori Campbell,NVDEP, viaemail 10/7/05Attached please find 2 spreadsheets:1. An update to the EGU projections worksheet. I have made changes/updates in red.N ERG will make all of thesechanges (to 2018) as requestedby the agency.2. An excerpt from your 2018 point and area source EI spreadsheet for Nevada. I’ve highlightedthe Mohave emissions. NOxin blue and SO2in green. My changes in red reflect the projectedemissions that I received from thefacility for their future projections emissions (also attached).Regarding NOx: these calculations did not projectany NOx reductions. The consent decree requiresthe plant to install low NOx burners with overfire air on each emission unit. Regarding SO2: I havealso changed these 2018 projection numbers to red to reflect the estimates outlined in their futureprojected emissions. These are the only items I found in my review of the 2018 projections. Thankfor all your help in this project.N ERG will change the Mohaveemissions for 2018 asrequested by the agency. Also,we will consult with PatCummins as his revisedprojections affect the Mohavepower plant.Lori Campbell,NVDEP, viaemail 10/12/05I've been reviewing Pat C's '11 state 2018 coalEGU spreadsheet and I noticed that the BART flagfor Reid Gardner's Unit #4 is wrong, so I went back and looked at your big spreadsheet and it seemsit is wrong there too. Sorry I didn't catch this before. But unit #4 at Nevada Power, Reid Gardner isnot BART eligible, units 1-3 are yes, but # 4 is a no.N ERG will change the BARTflag for #4 @ Reid Gardner.Mike Doyle, NVClark Co, viatelephone 10/7/05Asked for clarification on information requested related to SCCs, stack parameters, controls on newpost-2002 sources. 10/7: Provided detailed stack information for new post-2002 sources.N ERG will add details to recordsfor new, post-2002 sources inClark Co.Rita Trujillo, NMEnv. Dept. viaemail 10/3/05Here are New Mexico's comments on the EI data you sent to us. We have no comments on the areasource inventory. NM does not prepare its own area source inventoryN No changes to NM areasourcesHeather Lancour,NM Env. Dept....closed facilities were added to the 2018 projectedEI....ERG requested that I review the 2018projected EI and identify those facilities that are notsupposed to be included in the 2002 EI. Thereare over 22,000 rows of data in the 2018 projected EI. I propose that instead of reviewing andcorrecting ERG's 2018 projection EI, I supply ERG with all of the necessary data so that ERG mayreview and correct its own 2018 projected EI....ERG may contact me with specific data requests.However, I will leave the majorityof review and correction to ERG.Y See following responses.Attached are several flies to aid ERG intheir review and corrections, such as:2002 EI Sources.xls is an excel spreadsheet that contains all sourcesincluded in the 2002 EI. Pleasenote that: The NMED 2002 point source EI includes major and minor sources, which have an NSRor Title V permit. It includes operational, planned, temporarily closed, and permanently closedsources. Theplanned, temporarilyclosed, andpermanentlyclosed sources werereported with zeroY 2002: ERG will remove allsources of status C, P, T, andX.2018: ERG will remove all10Commenter Comment Affects2002?Responseactual emissions.[Spreadsheet indicates facilities based on status(O=operating; C=under construction; I=seasonal;L=landfill; P=planned; T=temporarily closed; X=permanently closed).Another spreadsheet was received on 10/14/05: (NM) NonOperatingFAcilities With Actuals.xlsComment received on 10/26/05: “Since there are not emissions for the temporarily closed (T)facilities, I vote to take them out.”sources of status C, P, X, andT.2. 2003/2004 TV permit info.xls is an excel workbook that contains four spreadsheets:* issued_TV_03&04 which lists all Title V permits that were issued in 2003 and 2004* closed_TV_03&04 which lists all Title V permits that were closed in 2003 and 2004* TV_new_eqpt_03&04 which lists new Title V equipment that was permitted in 2003 and 2004* TV_rmvd_eqpt_03&04 which lists Title V equipment that was removed in 2003 and 2004N In order to include emissionsfrom new facilities and/orequipment, ERG requestsemissions at the SCC levelfrom the agency. (Note: NMcannot provide these emissionsper Heather’s 10/20 email,below.)We will review “closed TV”facilities from the projections,and “TV_rmvd_eqpt” from theprojected inventory. (Any2003/2004 closed or removedfacilities/equipment wouldremain in the 2002 inventory.)I am drafting the 2004 SO2 Milestone source changes reports and have included some notes forERG: [email contains table.]N ERG will make include thisinformation as a SO2 flag andnote in the NM spreadsheet.Heather Lancour,NM Env. Dept,via email10/20/05I apologize. I am unable to provide the emissions, stack parameters, and SCCs for all equipmentadded in 2003 and 2004. I can only generate complete NEI submittals from our data managementsystem; I can't perform specializedqueries....If you would like a complete 2003 NEI submittal, Ican provide it to you in XML. The 2004 data is not yet complete. I hope to have the 2004 completeby mid-December.N ERG will not add the new2003/2004 point sourceemissions.11Commenter Comment Affects2002?ResponseTom Bachman,ND Dept. ofHealth, via email9/29/05(attachment),teleconference10/6/05I have reviewed the 2018 emissions projections for North Dakota and my preliminary comments arecontained in the attachment 2018 EI Comments3.doc. Two other attachments are included whichare referenced in the comments. We will continueto review the inventory and provide correctionswe believe are appropriate. If you have any questions, please contact me.Point Sources: The point source estimateslook reasonable except as noted below.The following sources should be deleted since they are no longer operating or now haveinsignificant emissions:Heating Plant - FargoAmerada Hess: Dolphin UnitAmerada Hess: Antelope #1 and Plant No. 2Bear Paw Energy Inc.: PLAZARoyal Oak Enterprises, Inc.N ERG will remove the sourcesno longer operating from the2018 projections.Several new sources have been permitted – see attached file with data for the sources. N ERG will add these post-2002sources to the 2018projections.3. The Lignite Gas Plant and Grasslands Plant are now injecting all of their acid gas into deep wells.SO2and other emissions from the tail gas incinerator at these facilities should be zero in 2018.N ERG will set these SO2emissions to 0 for 2018.Area Sources:1. The area source emissions estimates do not lookreasonable. North Dakota is predicted to onlyslightly gain population (1- 2%) between now and 2018 (see attached document titled “NorthDakota Population Projection”). We believe areasource emissions will not significantly increaseoverall and there will be a decrease in the ruralareas. The growth factors for many sourceclassifications appear to be much too high based on this low population increase. We ask that youconsider these population projections when developing the final area source emissions estimates.N ERG is not using localpopulation projections due tocurrently limitations of EGAS.However, ERG is investigatingthe area source emissionimpacts due to populationgrowth, as these are notexpected to be significant.2. In reviewing the area source inventory, several counties had emissions estimated for SCC2102002000, industrial boilers burning bituminous/subbituminous coal. This source categoryproduced approximately 100,000 tons of SO2plus other pollutants. This is clearly in error. Anyindustrial boiler with significant emissions (i.e. > 100 tpy) that is burning any type of fossil fuelisincluded in the point source inventory already. We believe this source category should be deleted. Ifit was included in the 2002 baseline, it should also be deleted from that inventory also. (Inteleconference, Tom said that ND does not burn any bit/sub-bit coal, so the commercial category(SCC 2103002000) should be removed, also. Tom will provide county-level emissions for SCC2199003000 (area/stationary/all boiler types, lignite).Y ERG will remove the SCCs asrequested, and add SCCemissions as to be provided byND.3. We believe the PM10 emissions estimate is also inaccurate. North Dakota has a populationsimilar to South Dakota, similar agriculture and other PM10 sources. Yet, South Dakota is projectedto have 120,000 tpy less PM10 emissions from area sources. We believe the PM10 emissionsestimate from area sources should be reevaluated.N ERG investigated this andfound that the ND ratio of lbsPM10/acre harvested ~12.8,which the SD ratio is ~11.0.There is no basis to change this12Commenter Comment Affects2002?Responseestimate at this time.Since there is a tremendous amount of data, we will continue to review the estimates and providedcorrections we believe are appropriate.N No response.Tom Bachman,ND Dept. ofHealth, via email10/11/05(attachment)Attached is a spreadsheet with our area source emissions estimate for industrial, commercial andinstitutional boilers that burn coal (any type). I suggest SCCs 2102002000 and 210300200 bezeroed out and our estimates for SCC 2199003000 added. In developing our inventory I noticed thatBillings (38007) and Slope (38087) counties were not included in the original inventory (probablytoo small to include). I have added then to our inventory.Y ERG will make the requestedchanges to the 2002 and 2018EIs.One significant SO2 source which I am not sure has been included in the area source inventory is theoil and gas production facilities (flaring and lease use). Based on a table passed out by PatCummins at the recent WESTAR meeting titled "2002 WRAP Area Sources Emissions Inventory(Revised) (Includes Oil and Gas)" and the inventory we just reviewed, the oil and gas productionfacilities (wells) appear to be missing. We estimatethat these facilities produced 4600 tons of SO2in calendar year 2002. Do you have any information on how that source category is handled? If youhave any questions, please contact me.Y ENVIRON has resolved thisissue directly with Mr.Bachman; no change inemissions has been made.Jeff Stocum ORDEQ, via email9/28 and 9/29/05The Oregon Area source 2002 and 2018 inventories look good. All the coordination with RegiOommen paid off. Thanks for the opportunity to check this over.N No response.While answering a coworker’s inquiry, I just ranacross one SCC that shouldn’t be included in the2002 or the 2018 Oregon area source EI: 24-20-020-055 Coin-Op Perc Drycleaners. There are noneof these in Oregon and the VOC estimates from them should be removed. Thanks again.Y ERG will remove this SCC.Mark Fisher, ORDEQ, via email9/30/05I looked over the point source inventory and noticed a few anomalies, but I did not have time toreview it in detail. Just a few things I noticed were that the following sources have shutdown andshould not be included in the 2018 projections:Ellingson Lumber shut down in 1997Glenbrook Nickel is shut downCrown Pacific in Prineville shut down in 2004Ochoco Lumber in Prineville shut down in 2004Willamette Industries in Bend shut down in 2002International Paper in Reedsport shut downDee Forest Products in Hood River shut down in 1997Y This comment is superseded bycomment made on 10/14/05.As mentioned in the meeting last week, it looks like there may be some double counting offacilities/emission units, but we would need more time to review the data to recommend anychanges.N No response.13Commenter Comment Affects2002?ResponseMark Fisher, ORDEQ, via email10/14/05I am sorry that I could not get back to you by the 7th and I would not be commenting at this late dateif there were only minor problems with the emissions inventory for Oregon. However, upon furtherreview, we have found that there are several problems that could have a significant impact on the2002 baseline inventory. As I mentioned before, it appears that the inventory includes severalsources that shut down prior to 2002. In addition, the inventory includes minor sources that wethought were not included in our 2002 NEI submittal. And, finally, we think the inventory mayinclude multiple entries for some of the sources.We did a spot check to see if some of the sourcesthat we know have shutdown are included in the2002 NEI and confirmed thatthey are not. This led us to wonder how they got included in theWRAP inventory. Did you use the 2002 NEI? If so, is it possible that data from previous yearscould have been included in the extract? Or, maybe the data is carried forward somehow?One thing I noticed is that there is incomplete data for some sources (e.g., the SIC and NAICS aremissing). These appear to be either minor sources or sources that shut down prior to 2002. Wedon't think these were included in our 2002 NEI submittal, so we are not sure why these are in theinventory.A few specific examples:Blue Mountain Asphalt is not included in our 2002 NEI, but it is included in the WRAP inventory.This is a minor source. Note that this is oneof the sources missing SIC, NAICS, and other data.Ellingson Lumber is included in the WRAP inventory, but not in the 2002 NEI. This source shutdown prior to 2002. This is true for several other sources.There are two sets of emissions data for Seaswirl. The SCCs are slightly different, but we haveconfirmed that the emissions represent two separate years or they are double entries. This may be anerror on our part if we entered the data twice for 2002 using separate SCC. However, if the datarepresents multiple years, then confining the inventory to the 2002 NEI will eliminate theduplication.Y ERG contacted OR DEQ, andit was agreed to remove all1996 and 1999 records.14Commenter Comment Affects2002?ResponseI also checked the Microsoft Access database that is provided on the WRAP website and it doesn'tseem to match the one that can be downloadedfrom the NEI website. We are not sure if theproblems are with the NEI, our submittal, or the extraction process, so any feedback would behelpful.N Based on our understanding ofthe WRAP EDMS for theversion 1.0 inventory, thesedata should be the same as arecontained in your 2002 NEI. Itis possible that your EDMSdownload query did notcapture all of your sources, orthat a different version (0.9,1.1, etc.) than 1.0. Try thedownload again for version1.0, and compare that to yourNEI submittal.Mark Fisher, ORDEQ, via email11/8/05Add Coyote Springs (CTG-2) to the 2018 projections. We missed this one. It came on line after2002.N ERG added this EGU.Jason Knapp, SDDE&NR, viaemail 9/28/05Could you tell me what data you used to determine the harvested acreage, for the following eightmajor crops (corn, sorghum, barley, oats, wheat,rice, upland cotton, and soybeans) as well as theemission factors used to determine the 2018 projections for tilling of crops. (via telephone, requestedan additional week to provide comments.)N ERG provided background onthe ag tilling growth factor(USDA crop projections). Noother comments have beenreceived.Jim Schubach,UT DEQ, viaemail 9/30/05In general UDAQ has found the Draft 2018 Inventoryto be an adequate reflection of the conditionof point and area sources in Utah. It is the position of UDAQ that the 2018 projection can beimproved in the following ways:1. The determination of retirement and replacements, for point sources, would be a more accuratereflection of the permitting situation in Utah ifcontrol factors for replacement units were based onBACT control efficiencies rather than NSPS or BART.N ERG is changing new sourcerates to BACT levels.2. ERG has requested clarification, concerning voluntary emission reductions under taken since the2002 inventory, on a the following sources: Intermountain Power Unit 1 & 2 (EGU 1222) andPacifiCorp Huntington Power Plant 2 (EGU 1221):a. A review of Intermountain Power permits since 2002 indicates that projects undertaken withinthat time frame would not be considered voluntary reductions.b. PacifiCorp has undertaken an emissions control retrofit project at the Huntington 2 site.PacifiCorp was granted a preconstruction permit (Approval Order) from UDAQ on April 6, 2005and it is our understanding that the project is currently under construction. UDAQ has estimated thecontrol efficiencies at the plant as follows:i. PM 10: 0.80 reductionii. SO2: 0.70 reductioniii. NOx: 0.30 reductionN ERG is providing thisinformation to theWRAP/SSJF for use in controlstrategy development.3. UDAQrequests ERG to review the emissionprojections associated with the Future Coal Power ERG will investigate this issue15Commenter Comment Affects2002?ResponsePlants 1-6. The 2018 projection worksheet is showing zero emissions for these future plants. Areview of the Arizona spread sheet for futurecoal plants indicates that 2018 projects wereundertaken and that the values in the sheet havebeen inputted and not calculated from elements ofthe 2018 spreadsheet. The Future Coal Plant values inthe Utah spreadsheet have been calculated inthe spreadsheet and some cell references seem inappropriate for the calculation.and make corrections asnecessary.4. UDAQ requests an extension of the review period for area source review and permit review forpoint sources. While we have been able to review the BART eligible sources and a cross-section ofother major sources for conflicts between the 2018projections and existing permit limits there are anumber of point sources that we have not been able to review. We also need additional time tocomplete our review of the area source projections.N See response below.5. In the BART Flag column (O) a number of sources have been flagged as either “potential” or“not known”. At this time UDAQ has identified onlyfour BART eligible sources: the two Hunterunits 1 & 2 and Huntington 1 &2.TBD Lee Alter to respond.Carol Nielsen,UT DEQ, viaemail 10/5/05Sent spreadsheet with area source SCCs that areduplicated, or whose emissions are reported underother SCCs. Requests that these duplicates be removed from the 2002 and 2018 area sourceinventory.Y ERG will remove these SCCsfrom the 2002 and 2018projections spreadsheet forUtah.Sally Otterson,WA Ecology, viaemail 9/30/05(attachment)Please find changes to the WRAP draft 2018 inventory attached. Only the "WA Point" worksheet inthe spreadsheet "WA_projections" was reviewed. A detailed review could not be completed.Updates are provided for items known to be of major significance, but there may be others thatsimply could not be identified in the time allowed. Also, no records from the Puget Sound CleanAir Agency's sources were reviewed (most sourcesin counties 033, 035, 053 and 061), since ourrecords did not allow for easy comparison. A few notes on the attached file:CThe first worksheet "WA Point" was copied from the review worksheet of the same name.CRecords highlighted in pink should be deleted from the database. In most cases, these sources areno longer in operation (and not expected to resume). A few are emitting at very low levels, muchlower than listed in the draft, and no longerneed to be tracked as individual sources.CRecords highlighted in green should be replaced with the information in the worksheet"Aluminum_smelter_updates."CRecords highlighted in yellow should be replaced with the information in the worksheet"Other_updates."Y ERG will make the changes asrequested by the agency.Two notable items were:1. Some sources had PM or PM10 emissions but not the complete set of PM, PM10, PM2.5N ERG did not augment missingPM species.2. It is very possible that sources not identified in our review may have had significant changesbetween 2002 and the present. I know this is a challenge inherent in this project. Please let meknow if you have any questions on our recommended changes. Thank you for all your work.N No response.Sally Otterson,WA Ecology, viaemail 10/11/05[Clarified that Ecology has jurisdiction over aluminum and pulp mills. Changes from SpokaneCounty (Studer) have priority of any suggested, or not suggested by Ecology.]N No response.16Commenter Comment Affects2002?ResponseSally Otterson,WA Ecology, viaemail 11/9/05Add new EGUs that came on-line in 2004: Goldendale (CT-1) 256 MW, and Encogen (CT1, 2, 3) at56 MW each.N ERG will add these post-2002EGUs to the 2018 base case.Alan Newman,WA Ecology, viaemail 10/7/05.Hopefully these additional comments are useful though probably late. Since the message from SallyOtterson last week, there have been additionalconcerns surface about the inventory projectionsrelated to the retirement projections for oil refinery and other industrial source equipment.Washington's experience is that the oil refinery equipment is not retired after 30 years or so, butcontinue in operation for 40 or more years. We still have operating process heaters and refiningequipment originally constructed in the 1950s that isin operation as the primary heater/process unit.At 3 of our refineries the newest process equipment installed dates from the early or late 1970s(except for equipment that has been added to theplant to meet recently mandated motor fuel sulfurcontent requirements). Thus for Washington, the projection that oil refinery equipment will beretired/replaced on a 30 year cycle is not realistic.N ERG consulted with the WorkGroup on this comment. It wasdecided that the retirementrates for all non-coal EGUswill not be changed for the firstversion of the 2018 base caseprojections. This is an area thatwill likely be examined moreclosely by the WRAP in thefuture in the form of asensitivity analysis todetermine the impacts onemissions from retirement/replacement versus nonretirement/replacement ofthese equipment.I couldn't decipher the retirement rate projection for aluminum and chemical pulp mill equipment,but again our experience is that once the equipmentis installed, it is in place forever before theplant's owner considers performing significant maintenance projects (not equipment or whole unitreplacement). The aluminum smelter and secondary aluminum plant equipment is installed onceand essentially never replaced. Instead, capacityis added or plants close. Chemical pulp millprocess units are replaced only when the unit becomes uneconomical to operate, not when it "wearsout".N These particular equipment arenot being retired, althoughgrowth is applied. Noadjustment is necessary basedon this comment.Experience indicates that unit lifetimes of 50+ yearsfor an industrial oil or natural gas fired boiler isnot unrealistic in Washington. We also have a number of natural gas/oil fired simple cyclecombustion turbines used to provide peaking electricity that are still in operation 30+ years frominitial installation.N Pursuant to the Work Groupdecision, these lifetimes willremain in the projectioncalculation for purposes of thefirst 2018 base casecalculation. The impact ofretirement vs. no retirementmay be examined in the future.As Sally Otterson noted in her message from last week, the inventories for the Puget Sound CleanAir Agency counties are hard to compare, but, as I scanned the Washington point source inventory, Inoted that the following facilities are noted in thecompany name as "out of business", or "closed":NORTHWEST MANUFACTURING INC (OUT OF BUSINESS) #5303315138MERIDIAN AUTOMOTIVE SYSTEMS INC (OUT OF BUSINESS) #5303317625N ERG will remove these fromthe 2018 projections.17Commenter Comment Affects2002?ResponseDERBY CYCLE CORP (CLOSED) #5303328611Sally Otterson,WA Ecology, viaemail 10/10/05I did a very broad review of the "WA Area" worksheet in the spreadsheet "WA_projections." Icompared our 2002 EI with the "WA Area" worksheet baseline planning inventory values. First, Iremoved counties 53033, 53035, 53053 and 53061 since the NEI values for these counties are underthe jurisdiction of the Puget Sound Clean Air Agency. I summed the remaining counties andcompared them by SCC code to the 2002 inventorythat WA completed for the NEI. We relied onEPA's inventory for many of the SCCs - so we have no values to compare for those. Thecomparisonshowed some that matched, and some potential double-counting issues. Those we did inventory andthe result of the comparison are:Exact match (or nearly so)2104008000 (residential wood combustion)2401002000 (architecturalsurface coating - solvent based)2401003000 (architecturalsurface coating - water based)2460100000 (consumer/commercial solvents - personal care products)2460200000 (consumer/commercial solvents - household products )2460400000 (consumer/commercial solvents - automotive products)2460500000 (consumer/commercial solvents - coatings)2460600000 (consumer/commercial solvents - adhesives/sealants)2460800000 (consumer/commercial solvents - FIFRA)2460900000 (consumer/commercial solvents - miscellaneous)2610000400 (residential yard waste burning)2461003000 (residential trash burning)2801000003 (agricultural tilling)N No change is necessary.Potential Double-Counting (NEI records from EPA potentiallydouble-counting state-submitted data under other SCCs)2461* (commercial solvents) - potential double count with SCC 2460*2465* (consumer solvents) - potential double count with SCC 2460*2610000100 (open burning of leaves) - likely double count with 2610000400, since all residentialyard waste was included in 2610000400 in WA's 2002 EI.(After taking a closer look at the individual SCCs, I would recommend removing the following ashaving a high probability of being double-counted: 2465*, 2610000100The other codes that I thought may be double counted, were not. They should be retained in theWRAP EI: 2461*)Y ERG will remove the SCCs asindicated in the parentheticalcomment from both the 2002and 2018 inventories.We inventoried other categories that were not inthe "WA Area" worksheet, but I believe they are all(?) being taken care of elsewhere in the WRAP effort (road dust, prescribed burning, agriculturalburning, onroad, nonroad, fertilizer, livestock). Please let me know if you need further information.N Yes, these other categories arebeing handled elsewhere in theWRAP effort. No change isneeded here.Gail King, Line # 2617 - 2620 Source, PSE South Whidbey Generating Station was dismantled in 1999. Y ERG will make the changes as18Commenter Comment Affects2002?ResponseNWCAA (WAstate), via email10/3/05Line # 6032 - 6061 Source Tecnal removed equipment that put them into the T5 program. 2003Line # 6062 - 6070 CRS #5: Name change to Rinker Materials #5Line #6253 - 6263 Lignotech went out ofbusiness - no one will take their placeLine # 7799 – 7836 Georgia Pacific West. They are no longer a Title V source they shut down thepulp and paper mill they are currently operating a tissue plant with a total of 30 tons of criteriapollutant / yr.Line 8580 PRAXAIR INC. in Ferndale. Never heard of this source.requested.Lynn Billington,NWCAA (WAState), via email10/6/05(spreadsheetattached); followup call 10/11/05Table 1 provides lifetime and annual retirement rates. This table delineates industrial boilers firedon oil as having a 45 year expectedlifetime, industrial boilers fired on natural (gas) having a 30 yearexpected lifetime and petroleum refineries having a30 year expected lifetime. In our jurisdictionthese retirement rates are not accurate. NWCAA has refineries with large boilers and heaters wellover the 30 year expected lifetime continuing to operate. Three of the refineries in our region, werebuilt in the 1950's and continue to use some of their original equipment (i.e. heater, boilers, catcracking unit, reformers, etc.).N Pursuant to the Work Groupdecision, these lifetimes willremain in the projectioncalculation for purposes of thefirst 2018 base casecalculation. The impact ofretirement vs. no retirementmay be examined in the future.In addition, we reviewed the facilities that were in the emission inventory baseline in 2002. I wasn'tsure of your criteria for including facilities but believe some sources should probably be added andother left out due emission levels. I have attached brief emission summaries. There are a fewsources that are over 50 tons that should probably in the WRAP inventory and are not currentlylisted. Also, some of the smaller sources should probably be left out. In addition, we are in theprocess of permitting a new Sawmill and Cogen thatwill be a Title V source(Sierra-Pacific) with acombined emission of about 200 tons of NOx, SOx, and PM. I would expect it to be up and runningin 2006. How can we get this source be included in the WRAP EI? If you need more informationon these sources please Gail or me a call.Follow-up call decisions:C2002: Remove sources on spreadsheet shown to emit <25 tpy; 2002: Remove PSE So. Whitbey(closed 1999); change name of CRS#5 to Rinker Materials #5; removed PRAXAIR (neverheard of them).C2018: Remove Tecnal (reduced ops in 2003, no longer TV source); remove Lignotec (OOB6/03); remove Georgia Pacific West (reduced ops in 2003; no longer TV source); add note thatSierra-Pacific sawmill will install cogen by 2006Y ERG will make all the changesrequested by the agency.Chuck Studer,SCAPCA (WAstate), via email10/10/05(spreadsheetattached);10/13/05 sentrevisedThere are some errors in Spokane County’s pointsource facilities (53063). See attached spreadsheet.[These include instructions to remove/change names on some records, add new facilities althoughemission are not provided, and information on sources that will become minor emitters in thefuture.]10/13/05: Revised spreadsheet indicates dates of name changes and closures.ERG will make changes torenamed/closed facilities.ERG will not addressnew/missing facilities as notemissions were provided, andare expected to be insignificantfor visibilityanalyses(mainly19Commenter Comment Affects2002?ResponsespreadsheetHAPs).Sunil Varma, SaltRiver Project, viaemail 9/29/051. In AZ_projections.xls, there is duplication of emission units. For example, CO, SO2, and VOCemissions from SRP’s Coronado Generating Station are represented twice. The CO emissions valuein Row 16 is the sum of the values in Rows 4 and5. The SO2 values in Rows 6 and 7 are the sameas those in Rows 24 and 25. The units at Coronado are CAMD EGUs. They are correctly identifiedas such in Rows 16-26 by setting the CAMD EGU flag = Y. However, the same facility in Rows 4through 9 is not recognized as containing CAMD EGUs. Therefore,the same units are duplicatedand not treated in the same fashion. Rows 4 through 9 should be deleted.Y ERG will remove the duplicaterecords.2. Similarly, there is repetition for Desert Basin Generating Station (Desert Basin rows withEmission Unit ID = 1 are redundant). There isrepetition for Kyrene Generating Station and SRPAgua Fria Generating Station, but the values are solow, that there will likely not be a major impact.Y ERG will remove the duplicateSO2and NOxDesert Basinrecords (lines 9476+9495, AZprojections spreadsheet). ForKyrene and Agua Fria,pollutants are not duplicated.3. In Rows 16, 22, 23, and 26, the CAMD EGU flag is left blank. The flag should be set to Y.The spreadsheet logic should be examined to makesure that if a unit is a CAMD EGU, the flagshould be set to Y for all pollutants emitted from the unit. This is important because if the CAMDEGU is not set to Y, a retirement rate is calculated for the pollutant.N ERG is investigating thiscomment, and will makechanges as necessary.4. The emission rate from new EGUs should be calculated using BACT rates, rather than BARTor NSPS values. BACT rates are availablefrom EPA’s RACT/BACT/LAER Clearinghouse.N ERG will use BACT.5. There is a conversion error in the worksheet titled “Future EGU Emission Rates” inAZ_projections.xls. The lb/MMBTU rate is converted to lb/MWHr using a conversion ratio of 3410BTU/KWh (Row 28). For coal EGUs, a heat rate of approximately 10,000 BTU/kWhrs is moreappropriate,N ERG will change the heat ratefor coal to 10,000 BTU/KWhr.6. In the worksheet titled “Agency Identified EGUs” in the spreadsheet EGU-projections.xls,some of SRP’s post-2002 units are missing. They are – Unit K7 at Kyrene Generating Station; UnitsS-5A, S-5B, (operational) and S-6 (planned 2006 operation) at the Santan Generating Station.N ERG will make these updatesas appropriate. Note:K-7 is in projections (CAMD);S-5A, S-5B (Santan) are nonCAMD EGUs (not on “AgencyIdentified EGUs list”; andS-6 is a “future” EGU that canbe accounted for in the futureEGU allocation method,however, Santan is a nonCAMD facility.7. General comment – as stated in the material, projections were based on data gathered fromEIAs Annual Energy Outlook 2005. It would be useful to confirm that this document takesemerging renewable portfolio standards into consideration. If the document does not do so, it mightbe advisable to give some consideration to the possible impact of increased renewables in the Weston the projection scenario.N The EIA projections take intoaccount the amount ofgeneration expected in thefuture from allfuels/technologies, including20Commenter Comment Affects2002?Responserenewable, hydro, nuclear, etc.Sunil Varma,SRP, via email toDennis Schwehr10/26/95From what I have seen heat rates are in the range of- Coal : 9500 - 10,500 BTU/kWhr. So 10,000BTU/kWhr is not a bad average. > Combined Cycle Gas : 7000 - 7500 BTU/kWhrN ERG will change the heat ratesas suggested.Nancy Norem,PNM, via email11/22/05Noticed that the SO2 numbers for San Juan Generating Station in 2018 base case seemed low. Thelb/MMBtu SO2 numbers in the spreadsheet ranged from 0.11 lb/MMBtu to 0.15 lb/MMBtu. As youknow, SJGS is under a consent decree to lower both SO2 and NOx emissions. There are severalnew SO2 emission limits are a result of the consent decree – a 90% annual removal and a 0.25lb/MMBtu averaged over 7 days. The most stringent of these emission limits is the annual 90%limit. Based on the number in our recent permitapplication, the SO2 lb/MMBtu emission limit(annual basis) would be 0.195 lb/MMBtu for each of the SJGS units – not sure where the 0.11 to0.15 numbers came from...the lb/MMBtu numbers in the spreadsheet are not too different fromwhat we hope to achieve.N SO2 emission rate waschanged to 0.195 lb/MMBtu.Gary Magno,XCEL Energy,via email 9/29/05As a follow-up to our conference call last Friday, attached is a file containing my comments on theColorado spreadsheet and assumptions associated with the 2018 emission projections for the PublicService Company of Colorado facilities. I primarily looked at the coal-fired boilers and did notreview specific information regarding some of the other sources such as natural gas compressorstation engine emissions. If you have any questions regarding my comments, please let me know.Plant Retirements: The general assumption that coalunits under 100 MW will retire in 45 years andunits over 100 MW will retire in60 years is not valid for Public Service Company of Colorado(PSCo) sources. According to our Energy Markets group there are no planned retirements in thePSCo system before 2018. The Colorado Projections Spreadsheet assumes that Cameo 2, Arapahoe3 and 4, and Cherokee 1 will be retired by 2018. This is not a valid assumption.N Based on current assumptions,there are ~10 coal EGUsprojected to retire by 2018;however, based on this andother comments (and Pat’srevised 2018 EGU projectionsmethod), ERG will change themethod per Cummins and willnot retire any coal-fired EGUs.Also, there seems to be some problem with the spreadsheet in that if these units were to in factretire, future emissions should be less and emissions remain unchanged from the 2002 baseline andare only adjusted for growth, not adjusted for replacement by new sources.Y ERG is investigating thisquestion and will makechanges as appropriate (i.e.,which might effect othersources, not just EGUs).Future Emission Rate Assumptions:This issue was discussed on the call but I would agree that anyfuture emission rates for units replacing retired units or just new units in general should be based onBACT, not NSPS or presumptive BART levels.The EPA BACT, RACT, LAER clearing house isthe best source for this emission rate information.N ERG will use BACT.BART Flag:I’m not actually sure of the purpose of this flag but there are PSCo units that have theBART flag and are not BART eligible. These units include Cherokee Units 1, 2, and 3. OnlyCherokee 4 is actually BART eligible. Also, Pawnee Unit 1 is shown witha BART flag. Thequestion of whether Pawnee is or is not BART eligible is still beingdiscussed with the Colorado AirN Lee Alter to respond.21Commenter Comment Affects2002?ResponsePollution Control Division. For the purposes of this projection spreadsheet, Pawnee should beindicated as potentially BART eligible.Agreements/Enforcements:The SO2control assumptions used for Arapahoe 3 and Cherokee 2 of37.5% control from baseline is not correct. An overall reduction from 2002 baseline emissions of20% is more accurate based on actual experience meeting the SO2tonnage cap for all the DenverMetropolitan Area emission units covered by this agreement.N The Denver agreementestimates reductions of 20-50%; ERG assumed a midpoint(37.5%). ERG has askedCDPHE to confirm that theyagree with a change to 20% forthese two units.10/26 telephone call from RoyDoyle: CDPHE agrees with achange to 20% SO2control onthese EGUs.Future Permit Limits:The SO2 and NOx projections for Comanche Units 1 and 2 are above permitlimits. Permit limit for Unit 1 is 3093 tons/yrNOx and 1856 tons/yr SO2. For Unit 2 the NOxprojection is below the permit limit of 3050 tons/yr but the SO2 projection is above the limit of 1830tons/yr. It should be noted, however, that theactual permit limits for these two units are combinedannual limits and not individual stack limits. For the purposes of these projections, however, thelimits noted above are appropriate for modeling and planning purposes.N The NOxand SO2emissionshave been changed accordingto the permit limits.Ammonia Emissions From Coal and Gas Combustion:I see the spread estimates ammoniaemissions from coal and gas fired boilers. To my knowledge AP-42 does not contain any emissionfactors for ammonia from sources like this. The source of that emission factor and validity is inquestion.N ERG used estimates from the2002 NEI. Per EPAdocumentation on developmentof EGU emissions for the NEI(http://www.epa.gov/ttn/chief/net/2002inventory.html#point):NH3 emissions were estimatedfrom “EIA data and newdefault emission factors”.AngeliqueLeudeker, ITEP,via email andteleconference10/7/05For some tribes, the facility names are not right....duplicates...I highlighted errors. Also, there isone facility (South Pavilion Compressor Station )on the Arapahoe Tribe of the Wind RiverReservation that we do not have in our database.Y ERG will make corrections to2002 and 2018 records havingerroneous facility names.The So. Pavilion CompressorStation is new, but emissionshave not been provided. Noother action will be taken.Tom Rice, UteMountain Tribeof Ute MountainNew sources on line after 2002 include “1 compressor station and approximately 12+ wells.” N These were added to “note” ofthe tribal spreadsheet, althoughemissions were not provided.22Commenter Comment Affects2002?ResponseUte Reservation,via email 9/7/05Pat Cummins,WRAP, via email10/7/05Attached for your review andcomment is a corrected2018 projection of SO2 and NOx emissionsfrom existing coal-fired EGUs in the Westernpower grid (contiguous WRAP region minus theDakotas). When finalized, this projection will replace the 2018 base case projection for these unitspreviously released by ERG. Please review the attached memo and spreadsheet and let me know ifyou have any questions or comments. It would be most helpful to receive your comments byThursday, October 20.N ERG will replace the draftEGU projections withCummins’ corrected versionfor the applicable coal-firedEGUs.Lee Alter,WRAP, via email 9/28/05Below are my comments on the 2018 projections in general, followed by some EGU comments. AsI told Paula after the call, I thought the call went very well and I'm impressed with the effort youhave put into this. The way Excel works, it's too hard / time consuming to make sense of theformulas as they appear in the cell contents bar, but the spreadsheets appear to do what they have todo methodology-wise, and they are well organized and transparent (which is important), and thememos were very handy.N No response.1. Emissions Summary.As Paula, Tom, and I have discussed, it would be helpful to have asummary table(s) of the preliminary 2002 and 2018 inventories for major source categories for SO2,NOx, and PM10.N ERG will prepare this afteraddressing comments on thedraft 2018 EI.2. Sample Sources/Calculations.It would be helpful if the memo / draft report contained twoexamples of how a "source" wasprojected to 2018. The examplewould show the numerical resultof applying each factor in sequence -- growth, retirement, control,etc. A flow chart may help too.N ERG will provide these detailsin the draft and final reports.3. Subsequent Revisions.We are only providing folks two weeks to review this large and veryimportant data set. To the extent a reasonablyaccurate preliminary regional inventory is neededsoon to produce some preliminary2018 visibility projections on time,I think that's fine because wehave no modeling results at all and really need some. However, I'd like to think that we'd have theresources and/or process to accept any changes to the 2018 base case from the states and tribes up tosome date after Sept 30. Say, Nov 15??? Is something like that part of the plan???N ERG’s schedule is to finalizethe projections for purposes ofdeveloping summaries forreview by 11/4. Commentsfrom WRAP are due on 11/15.Final summaries will begenerated by 11/18. Changescould be received as part of thecomments on 11/15.4. Emissions From New Sources.I agree with one of the concernsraised on the call. Aren't BARTand (to some extent) NSPS under representative of actual controls achieved on new sources? BACTwould seem more appropriate, but I don't know the issues involved in using the BACTClearinghouse or similar resources.N ERG will use BACT rates fornew sources.Also, I'm not sure how you calculate emissions for non-EGUs that have either been fully retired andreplaced or partially retired/replaced (per the annual percentagemethod). The "retirement andreductions" worksheet shows substantial reduction percentages for several (but not nearly all)SCCs.N For non-EGUs, annual %method of retirement was used.% not retired maintainsexisting emissions rates; %retired/replaced and newgrowth uses new emissionrates.23Commenter Comment Affects2002?ResponseThe memo says these are the control efficiencies relative to existing sources? Really? They seemrelative to uncontrolled sources, not necessarilyexisting sources, which may have been originallybuilt with some controls, or retrofitted for a variety of purposes. I hope you can provide at least ashort description/reference on that point.N ERG will change wording tosay “relative to uncontrolledsources” as appropriate. (Note,there is not a feasible way todetermine if existing sourcesare already controlled.)And for those SCCs for which no new control efficiencies are provided, I assume you assumeexisting emission rates. I thought I read or heard that somewhere, but can't find it now.N Correct, these are not beingretired since new sourceemission rates are not readilyavailable.5. NEI vs CAMD Data.I thought the states preferred theNEI over the CAMD data, but the memosays CAMD data were used as the basis for projections.N Some states (e.g., CA) do notprefer CAMD data; however,for this project the CAMD datawere selected for consistencyin reporting. Also, in recentyears, as compared to the past,CAMD data are greatlyimproved in quality andcoverage.(Note that WY and AZ [fewsources] also preferred theirown data over CAMD; theseemissions are reflected in theircorrections submitted by ERGon 10/24/05 to the modelers.The differences between thestate emissions and CAMD forthese sources is 5% or less.)6. Placement of New EGUs.Your memo shows 27 new coal-fired EGUs will be required, and only7 specific locations have been identified by the states. The other 20 are distributed across states withexisting coal-fired plants. How did you decide on the number per states? Also, these would be putat existing plants, but the spreadsheet doesn't show which plants. The locations are unspecified.Are we expecting the states to specify? If they don't, what do we do?N ERG modified the sitingprocedure based on input fromthe WRAP SSJF/Projectionswork group (10/4/05). This isbased on (in this order): (1)power plant announcementsand (2) locations of existingcoal EGUs and infrastructure.7. Are all the new gas fired units combined cycle? Y No. Both simple cycle andcombined cycle natural gasEGUs are currentlyunder24Commenter Comment Affects2002?Responseconstruction or beingpermitted. No new futurenatural gas-fired EGUs wereallocated in the future.8. There are no CTs provided for gas-fired boilers.As I said in an earlier email, there are severalsuch boilers in the WRAP region, some of which are BART-eligible.N ERG did not apply CTs forgas-fired boilers. However, wewill assume a 0.5 CT and makethis correction.9. Table 1 identifies post 2002 voluntary reductions at Coronado and Navajo, but I don't recallhearing about these, nor do I seemthem in Table F that Paula has been maintaining. On the otherhand, I have heard about negotiations for Cholla.N This information was providedby Steve Frey, EPA Region 9.10. Arapahoe and Cherokee show some units with a retired flag of "Y", but they have 2018emissions anyway. Was that flag over ridden and how? I can't really tell by a cursory look at thespreadsheet.N Based on discussions with theProjections Work Group, nocoal-fired EGUs are beingretired.11. On page 2, I'm confused by the second paragraph ("Data for this calculation ..."). As notedabove, you used CAMD data rather than NEI, in which case you would have the CF data. So whydiscuss matching of CAMD units to "WRAP units" for the purpose of obtaining CF data?N The NEI matching only pulledin emissions (CF was notknown to be needed at thatjuncture). Another effort tocompile CF data was necessaryfor the projections method.12. On page 2, second-to-last paragraph ... It says "The capacity threshold represents the theoreticallevel ...". I think you mean the typical or expectedlevel. Theoretically, they could probably achieve>0.85 for coal-fired EGUs, as is sometimes the case in reality.N We will change the wording assuggested.13. On page 3, last paragraph, first sentence identifies number of new "plants." Should be "units."Same goes for the Facility Name in Column L of the point source tables.N ERG will make this change inthe EGU discussion for thedraft and final reports, as wellas the spreadsheets.Finally, as a general matter, you might consider pointing out in future memos / reports the majorsources of uncertainty, especially those likely to have the largest impact on results.N ERG will add this informationto a revised memo, and draftand final reports.Lee Alter,WRAP, via email10/10/05Note, for reasons stated in my email regarding a sample "pivot table deliverable", you may want touse multiple columns to provide text descriptions at multiple SCC levels.N ERG will include SCCdescriptions to the SCC_L3level as requested. Thischange will affect ALL states’spreadsheets.Lee Alter,WRAP, via email10/12/05[Sent link to EPA announcement concerning Refinery Compliance Initiative, new consent decreewith ExxonMobil; affects Billings, MT refinery.]... The sulfur dioxide emissions would end up inthe few hundred tons range" (100-400 tpy) for the "next generation" catalyst additives and/or controlequipment.N ERG will make a note in theMT spreadsheet thatExxonMobil is subject to CDreductions.25Commenter Comment Affects2002?ResponseLee Alter,WRAP, via email10/25/05Passed along information on new consent decree affecting ExxonMobil refinery in Great Falls, MT N ERG added a flag and note tothe MT spreadsheet indicatingreductions are expected,although currently notquantified.Dennis Schwehr,WEST Assoc.,via email 9/23/05Quick comment...might be more later...retirementrates for EGUs, as shown on page 7, show apercentage retirement, equivalent to a percentage reduction in emissions, for each year of theexpected life of the various types of units. Pechan didnot do it this way if they knew the start date ofthe unit. I thought you were also going to apply that concept. In other words, a unit's emissionswould continue to grow until ithit the capacity threshold orwhen the unit reached its lifeexpectancy.N All of the CAMD EGUs(which were the EGUs withcommencement dates) usedlifetimes; other sources(including non-CAMD EGUswhich did not havecommencement dates) used theannual retirement rateapproach. ERG will includesuch a clarification in a revisedmemo, and draft and finalreports.Dennis Schwehr,WEST Assoc.,via email 9/29/05Regarding capacity factors for EGUs, other than coal boilers, did you do any research on CFs for oldgas/oil boilers, simple cycle gas turbines and gas combined cycle units? The CFs used in yourassumptions for growth purposes were really off the top of my head and I expect some utilitieswould say they should be otherwise. But you may need to do a little research in the EIA or CAMDrecords to see what is realistic. Even though a few utility folks may think the coal unit CF should behigher than 85%, others are OK with it. Being that utilities OK'd the use of 85% in previousprojections work, I am hesitant to see you change it...N ERG compiled CAMD EGUdata and calculated CFs (1999-2000); documented in memoand spreadsheet 4/14/05.However, these data are notdisaggregated bytechnology/fuel. We will dothis and report the findings inattempt to justify or adjust theCFs for the non-coal EGUs.Public Service Colo (Xcel) is sending you some of their own comments. They take exception to theretirement of some of their coal units within the 60 year timeframe. I remember when that point wasraised a few years ago, someone mentioned that even though a unit may be operated more than 60years, it is expected that units would likely be retrofitted with new controls at some point, making itessentially a "new unit". The life expectancy assumption for coal boilers is probably better left as is,again, because changing it would create some controversy that may not be easily defensible.N Pursuant to Work Groupdecision, there will be noretirements of coal-firedEGUs.Dennis Schwehr,WEST Assoc.,via email 9/29/05(Forward fromLyle Nelson,SCE)If Mohave operates in the future we project up to86% C.F. as was used inour application for ourpermit to construct the consent decree air pollution controls. 85% C.F. is probably close forplanning purposes.N No response; see comment andresponse from Nevada Dept. ofEnvironment regardingMohave plant.No comment on the oil/diesel fired EGUs. The "Naturalgas-fired turbines areprobably'PeakingN ERG is investigatingthe26Commenter Comment Affects2002?ResponseUnits' which would most likely operated in the 25% annual C.F. range, or less. The natural gas-firedcombined cycle units, however, would tend to operate closer to abaseload plant because of theirextremely low heat rates. 60% annual C.F. may betoo low. Granted they will operate at higher costthan base loaded coal plants (fuel cost differential), however, because of their ~ 7000 BTU/KWHheat rates should call them out on dispatch quite a bit... maybe closer to 70% annual C.F.assumptions of CF for the NGturbines, using CAMD data(see response to Schwehr,above). We may makeadjustments depending onfindings.The NOx rate for coal seems ok, i.e., 90% reduction by SCR on a new coal plant should yield anuncontrolled NOx rate of (0.11/.90 = 1.10 LB/MMBTU). Mohave’s NOx rate currently is 0.41LB/MMBTU. The NOx rate seems good enough to me. The SO2 rate of 0.15 LB/MMBTU isachievable for Mohave at an 85% reduction. Assuming a BACT requirement of 95% scurbbing thiswould give some room for higher sulfur content in the coals in some cases in the west. Therefore, Iwould hate to see the limit tightened beyond 0.15 LB/MMBTU.N See comment and responsefrom Nevada Dept. ofEnvironment regardingMohave plant.Only one correction needs to be added for Mohave in Table 1: In the 'Notes' column for Mohave,the note states that, 'Heat input limit (per NDEP) is 73,925,640 MBTU/YEAR.' This should becorrected to show as '... 73,925,640 MBTU/YEAR per unit.'N ERG will make this change.Doug Latimer,via email 9/28/05I have a few comments listed here. My comments are solely on the EGU portion of the analysis.The EGU component of the analysis is currentlybiased because new EGUs are assumed to emit atNSPS or presumptive BART levels. These are emission rates much higher than BACT as currentlyenforced in the West (and documented to some extent in EPA's BACT/RACT/LAERClearinghouse). Also, BACT is constantly evolving (tightening) as technology improves. There aresome who advocate IGCC and CFB, both technologies that can reduce emissions significantly (evenCO2 in the case of IGCC). Increasingly, new technology will be substituted for old, possibly(hopefully) even in the 13-year timeframe out to 2018.N ERG will apply BACT levelsto new sources based on thiscomment (and many others).The EGU analysis does not account for renewables (wind, primarily) offsetting some coal-firedgeneration or energy efficiency measures, which could change the rate of growth of electricitydemand.N Similar comment as SunilVarma (SRP). The EIAprojections take into accountthe amount of generationexpected in the future from allfuels/technologies, includingrenewable, hydro, nuclear, etc.Because of significantly escalating natural gasprices, I question the assumptions regarding newnatural-gas-fired single- and combined-cycle gas turbines.The EIA 2005 Outlook waspublished in February 2005,thus is includes the most up todate projections. We have notother basis for generationprojections, so no change willbe made.EGUs are assumed to have a 60-year life with an annual retirement rate factor of 1.67%. I realizethese assumptions were used in the GCVTC and the IAS, but I question the validity of them. Isthere anyevidence that utilities will want to abandon EGUs after 60years? There is abundantN Pursuant to Work Groupdecision, there will be noretirements of coal-fired27Commenter Comment Affects2002?Responseevidence that they will want to renovate them over time. With NSR power plant enforcementuncertain at this time, it is unclear how that power plant upgrading will translate into emissionscontrol. I would recommend against using the annual retirement factor. I would explore thesensitivity of the results (1) by assuming retirement at age 60 and never retiring, (2) with and (3)without BACT (enforcement level) controls.EGUs. The sensitivity analysismay be done after this firstversion of the 2018 base caseemissions are completed.Assumptions are made regarding the coal Btu content which are not valid for much of the West.Better, site-specific assumptions should be made .N This will be revised to 10,000BTU/KWhr for coal based onother comments.I wonder if it would be useful to do any sensitivityanalysis and to do a best estimate with upper andlower bounds. We are projecting out 13 years. We have seen already how significantly weunderestimated the rate of control in the West when developing the SO2 Annex, and that was just 3years ago. Could anybody have anticipated the extent of control in the West that has occurred in1992 (13 years ago)?N Sensitivity analyses areplanned by the WRAP SSJFusing the final form of thespreadsheets/summaries. (Seecomment/response toCummins, Moore, and Alter,below.)Wayne Leopold,Phelps-Dodge,via email 9/23/05The problem with growth factordifference between ASARCO andPhelps Dodge Miami (PDMI) isdue to the fact that all the PDMI listings have a SCC code starting with 10, which is not correct for asmelter.N This was the SCC that wasreported for the emission unit(combustion). No changeswere made to the growthfactors.Line 705 (Arizona spreadsheet) NOx for smelter has a permit limit but it is higher than yourprojection.N ERG will add a “Y” to permitlimit fields, and a note to thiseffect.Tom Moore,WRAP, viatelephone 9/30/05The three tribal power plants need to have a tribal code indicating their jurisdiction: Four Corners,Navajo, and Bonanza. All summary tables should reflect these as tribal sources (i.e., not part of thestate inventory.)Y ERG will make this correctionin the 2002 and 2018 EIs forFour Corners and Navajo. Notethat the Bonanza plant willremain under UTDEQ perdirection from ITEP (i.e.,should not be associated withit’s tribal jurisdiction).Pat Cummins,Tom Moore, LeeAlter, viatelephone 10/3/05Summary reports need to be developed:CShow the tonnage change due to retirements (-), new sources (+), and increased capacity ofexisting EGUs (+) and new facilities.CShould show tons/year by state for the majorsource categories: Utilities-coal, utilities-other,smelters, refineries, cement production (e.g., top source categories), PLUS the tonnage changes(+/-) due to (1) growth/decline from existing facilities (ton changes), (2) retirements, (3) newsources/replacements, (4) post-2002 controls.CShow the SO2 emissions for the annex states/sources.N ERG will develop thesesummary tables afteraddressing comments andincorporating the changesnoted in this table.ERG should set upa final spreadsheet/database that can be used for selectingdifferent combinations NERG will do as requested.28Commenter Comment Affects2002?Responseand groups of SCCs/source categories. This would be similar to what Lee developed for the previousprojections (he’ll provide an example). Will be used for sensitivity analyses, control strategydevelopment, etc. This should be the next step after the comments are addressed from thestates/tribes and the spreadsheets are finalized for 2018.Priorities for the near-term are to examine and QAthe coal-fired EGUs and the BART sources. Weneed to make sure that these 2018 estimates are correct.Next steps in the 2018 analysis need to be:CExamining what projections say about the SO2annex sources; how do their summed emissionscompare to the milestone amount?CLooking at ERG’s assignment of location for newfacilities? Which stateswere these placed in,which counties?N ERG will address allcomments, revise spreadsheets,and develop summary tables toaid in this assessment.ND (and MT) area source SO2emissions need to be addressed (too high due to EPA gap-filling) Y ERG will make changes toND’s area source inventory for2002 and 2018 based oncomments received.(Note: No comments oralternative estimates wereprovided by MT, so nochanges will be made.)ERG’s report should include explanation of why local demographic data could not be used (e.g.,EGAS limitation; mostly applicable to local/O3 modeling inventories), why MACT impacts oncriteria pollutants weren’t addressed.N ERG will include thisinformation in the draft andfinal reports.ERG should make changes in the NIF and IDA filesfor 2018 that are sent to the WRAP modelers toaddress:CTribal codes for Navajo and Four Corners (on Navajo Nation) and Bonanza (on the Uintah andOuray Reservation of the Ute Indian tribe)Y ERG will make these changesfor 2002 and 2018 for FourCorners and Navajo (not forBonanza per ITEP direction).Lee Alter, viaemail 10/14/05CFuture changes in BART codes (to be provided by Lee based onupcoming info. From states) Y ERG will make the changes to2002 and 2018.WRAPSSJF/ProjectionsWork Group, viaconference call,10/4/05Retirement of existing facilities: The approach implemented in the spreadsheets is fine, with theseexceptions:CAdd a flag for new oil/diesel EGUs. These maynever be built due to high price of fuel.Alternatively, they could be more viable than a natural gas plant if there is no local pipeline.CERG should place new oil/diesel plants in NV (1),AZ (1), and CO or NM (1); not all in NV.N Based on discussions with theProjections Work Group, itwas assumed that no future oilEGUs would be built.ERG should revise the ERG Projections Memo, table on page 5, to include emissions from the newfacilities, and where these are sited for projections purposes.N ERG will incorporate thesechanges into the overall draftand final report.Modify the approach for siting gas EGUs to follow this hierarchy: NNo response; ERG is following29Commenter Comment Affects2002?Response1. Place gas EGUs at locations indicatedby agencies as a potential site; next2. Place gas EGUs at locations of existing gas EGUs; and next3. Place gas EGUs at locations ofother existing fossil-fuel EGUs.procedure per 10/27/05conference call (below).Alison Pollack,ENVIRON, viaemail 10/24/05My understanding from our emails or phone discussions was that for the point source O&Gprojections, you'd run out of time and just used EGAS, instead of using the growth factors thatJames developed from the RMPsand EIA production forecasts. Tom wants the projections to beconsistent; i.e., that ERG's point source O&G projections be updated to use James' growth factors.N ERG will use ENVIRON’sgrowth factors to update theprojections for the applicablepoint source SCCs.Main comments/decisions during the call were:CNo reason to retire coal EGUs.N ERG will not retire coal EGUs.WRAPSSJF/ProjectionsWork Group, viaconference call,10/27/05CCurrent retirement/replacement assumptions for other typesof EGUs and other equipment (e.g.,refinery heaters) should remain the same (i.e., WA’s comment will not be addressed at thistime, but can be examined later in a sensitivityanalysis that focuses on effects of retirementversus no retirements of certain sources). Be sure to note in projections report that extendingthe lifetimes of existing equipment may “mimic” the effect ofretirement/replace for equipmentthat have already undergone PSD review or other retrofits that create emission reductions.N ERG will make no changes tothe currentretirement/replacementassumptions for non-coalEGUs. ERG will incorporatenote as suggested.CAZDEQ comments: ERG should make technical changes, but defer procedural changes untillater (i.e., documentation, etc.). The focus in the short term is in generating a complete set of2018 base case emissions for WRAP to review and the modelers to use. Other changes can bemade later.N No changes needed.CCurrent allocation method for future EGUs doesn’t make sense. Method needs to ignore thepower-pool in which growth is projected, since this information can be misleading (e.g., newoil-burning EGUs are projected, but these will not be built in the West). ERG should follow thisapproach for allocating new coal and NG EGUs:#1 – What is the new capacity? Determine new capacity using previous procedure based on CTs andEIA growth projections.#2 – Which states/tribes get the new capacity? Document information provided by the states thatindicate new/permitted plants under construction. This step will allocate part of the new capacity.Note that emissions for CA’s new NG EGUs should be estimated using their stricter emission rates.#3 – Which specific locations get the remaining new capacity? Document information provided bystates indicating new plants permitted but not yet under construction. The work group will reviewthis information and evaluate on a case-by-case basis to determine sites of new EGUs. Thisallocation step will consume the remaining new capacity and associated emissions.N ERG will develop thedocumented needed by theWork Group to complete theallocation of future new EGUsto specific locations.