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Center for the New Energy Economy Project Report for WESTAR-WRAPAnalysis of EGU Emissions for Regional Haze Planning and Ozone Transport Contribution Draft - April 22, 2019Project Website: Center for the New Energy Economy (CNEE) at Colorado State University conducted an analysis of current and future NOx and SO2 emissions from fossil-fueled electricity generating units (EGUs) in 13-Western states for the Western States Air Resources Council (WESTAR) and Western Regional Air Partnership (WRAP). WRAP state representatives participated in the project along with representatives of Western electric utilities to develop the parameters for the study, including information needed for Western regional air quality analyses and planning under the federal Clean Air Act.The information developed through this project will be used in regional modeling as part of the ongoing implementation of the Regional Haze Rule and for ozone analysis and planning. This report describes results related to the project’s two major objectives:A comprehensive database of information on the fleet of fossil-fired EGUs in 13-Western states (circa 2014-2018) that contains information on the plants operating characteristics and NOx and SO2 emissions; and A projection of 2028 NOx and SO2 emissions based on expected plant closures, fuel switching, and emission controls under a “rules on the books”. The data developed through this project will also help WESTAR and WRAP quantifying how emissions transport from fossil-fired EGUs affects ozone formation at urban and rural locations across the West. This question needs to be addressed for compliance with the 2015 National Ambient Air Quality Standards (NAAQS) for ozone. The contribution from EGUs is part of the regional evaluation of local versus regional sources, which also must address the question of uncontrollable background contribution.Data ReviewAs part of the national Acid Rain Program, EGU operators from across the country are required to submit emissions information and other data on plant operations to EPA’s Air Markets Program. This information is publicly available on the Air Markets Program website - . In order to compile and QA a comprehensive database of information on the fleet of fossil-fired EGUs in the 13-Western states covered by this project, the information contained in the EPA database was downloaded and circulated to project participants for review. A complete description of the data review process can be found on the project website - this review process, state and utility participants confirmed the accuracy of the Acid Rain Program data for 2014-18. Calendar year 2014 data for EGU’s will be used in the WRAP’s shakeout modeling runs and calendar year 2018 EGU data will be used in the baseline modeling run. In addition to confirming the accuracy of the historical emissions information contained in EPA’s data base, project participants were asked to address the following: Provide information on any units not covered by the Acid Rain Program (referred to here as non-CAMD units). These are units that due to age (old) or size (small) are not reported to EPA under the Acid Rain Program.Identify years when units experienced overhauls or major unplanned outages, or were off-line for extended periods due to one-time events such as installation of pollution control equipment.Provide information on current emission controls and emission rates for each unit, including any new controls or permit conditions that are not fully reflected in the 2014-18 data.Dates for planned unit retirement dates.Identify units that switched fuel from coal to natural gas.The information provided in response to these questions has been incorporated in the data files described below in order to prepare the 2028 “Rules-on-the-Book” emissions inventory that will be used in the WRAP’s initial 2028 modeling runs to evaluate continued progress toward improving visibility at the Class 1 Areas covered by the Regional Haze Rule.Summary of ResultsNote: Each of the data files referenced below can be found along with this report on the project website. 1: Electricity Generation in the Western U.S.Power plant emissions in the West over the last ten years have been influenced by a number of factors, including changes in the generation mix. While total generation across the 13-state region has not increased significantly over the last 10 years, there has been a pronounced decrease in coal generation (-28%) and a corresponding increase in renewable generation (+349%). This trend away from coal and toward more renewables will continue as more Western coal plants retire in the coming years. Unlike other parts of the country, the West has not seen a marked increase in natural gas generation over the last ten years. Fluctuations in natural gas generation in the West correspond with fluctuations in hydro power. Source: (See: Data File 1 – Net Generation)Figure 2: Western US Power Sector Emissions TrendsSO2 and NOx emissions from the Western power sector have decreased dramatically over the last 20 years. 2018 EGU emissions of SO2 were 84% below 1998 levels and NOx emissions were 71% below 1998. Source: (See: Data File 2 – 1998-2018 CAMD)Figure 3: Coal vs. Gas Contribution to EGU Emissions InventoryMost EGU emissions of SO2 and NOx in the Western US in 2018 came from the 84 generating units powered by coal. Gas-fired generation contributed almost zero SO2 and 8% of EGU NOx emissions in 2018. Most of the NOx emissions from gas-fired generation in 2018 came from the 253 units emitting 10 tons per year or more. The 271 units that emitted less than 10 tons per year contributed less than 0.5% of 2018 EGU NOx emissions in the West. Source: (See: Data File 3 – 2018 Charts)Western Coal Unit Retirements by 2028 (See: Data File 4 – Western Coal Units)State Facility Name Unit IDNameplate Capacity (MW)In-Service YearRetirement YearnotesAZCholla111419622025APS IRPAZCholla331219802025APS IRPAZCholla441419812025PAC IRPAZNavajo Generating Station180319742019announced retirementAZNavajo Generating Station280319752019announced retirementAZNavajo Generating Station380319762019announced retirementCOComanche (470)138319732022Xcel Colorado Energy PlanCOComanche (470)239619752025Xcel Colorado Energy PlanCOCraigC144619802025Legal/RegulatoryCONucla17919912022Legal/RegulatoryMTColstrip135819752022Legal/RegulatoryMTColstrip235819762022Legal/RegulatoryMTLewis & ClarkB15019582020announced retirementNDR M HeskettB12519542021announced retirementNDR M HeskettB27519632021announced retirementNMSan Juan136919762022PNM IRP (has SNCR)NMSan Juan455519822022PNM IRP (has SNCR)NVNorth Valmy127719812025NV IRP (may retire earlier)NVNorth Valmy229019852025NV IRPORBoardman1SG64219802021Legal/RegulatoryUTIntermountain1SGA82019862025announced retirementUTIntermountain2SGA82019872025announced retirementWACentraliaBW2173019722021Legal/Regulatory (12/31/2020)WACentraliaBW2273019732026Legal/Regulatory (12/31/2025)WYNaughton338419712018Switched to gas 1/31/19 WYDave JohnstonBW4113419592027PAC IRPWYDave JohnstonBW4213419612027PAC IRPWYDave JohnstonBW4325519642027PAC IRPWYDave JohnstonBW4440019722027PAC IRPTable 1:29 of the coal units operating in the West in 2018 will retire by 2028. Emissions from these units are therefore zeroed out of the 2028 emissions projections produced by this project. Figure 4:Emissions from coal units that will retire by 2028 comprised 27% of the SO2 and 34% of the NOx emitted in 2018 by all EGUs (coal and gas) in the 13-state Western region.(See: Data File 3 – 2018 Charts)Figure 5: NOx Controls on Existing Coal UnitsOf the NOx emissions from coal units in 2018, 12% of the emissions came from units with SCRs installed or required; 13% came from units with SNCR installed; and 38% came from units that are not planned to retire by 2028 and which do not have post-combustion controls for NOx. The list of units in each category is shown below. (See: Data File 3 – 2018 Charts & Data File 4 – Western Coal Units)Table 2: Coal Units by Type of NOx Controls (See: Data File 4 – Western Coal Units)State Facility Name Unit IDNameplate Capacity (MW)In-Service Yearnotes?SCR INSTALLED????AZCoronado Generating StationU1B4111979Retire or install SCR in 2025AZCoronado Generating StationU2B4111980SCR 2014AZSpringerville44582009SCRAZSpringervilleTS34582006SCRCOComanche (470)38572010SCRCOCraigC24461979SCR 2017COHaydenH11901965SCR in 2015COHaydenH22751976SCR 2016COPawnee15521981SCR 2014MTHardin11162006SCRNMFour Corners48181969SCR 2017NMFour Corners58181970SCR 2017NVTS Power Plant12422008SCRSDBig Stone14501975SCRWYDry Fork Station14842011SCRWYJim BridgerBW736081976SCR 2015WYJim BridgerBW746081979SCR 2016WYLaramie River15701981SCR 2019WYWygen I1902003SCRWYWygen II1952008SCRWYWygen III11162010SCR?SNCR INSTALLED????AZApache Station32041979SNCR 2017COCraigC34741984SNCR 2017NDLeland Olds12161966SNCRNDLeland Olds24401975SNCRNDMilton R YoungB12571970SNCRNDMilton R YoungB24771977SNCRNDSpiritwood Station11062014SNCRWYLaramie River25701981SNCR 2018WYLaramie River35701982SNCR 2018Table 2: Coal Units by Type of NOx Controls (cont.) ?NO POST COMBUSTION CONTROLS FOR NOX????State Facility Name Unit IDNameplate Capacity (MW)In-Service YearnotesAZSpringerville14251985?AZSpringerville24251990?COMartin Drake6751968ULNB/OFA - Round 1 RH SIPCOMartin Drake71321974ULNB/OFA - Round 1 RH SIPCORawhide Energy Station1012941984Enhanced OFA-Rnd 1 RH SIPCORay D Nixon12071980ULNB/OFA - Round 1 RH SIPMTColstrip37781984?MTColstrip47781986?NDAntelope ValleyB14351984?NDAntelope ValleyB24351986?NDCoal Creek16051979?NDCoal Creek26051980?NDCoyoteB14501981?NMEscalante12571984?UTBonanza1-Jan5001986?UTHunter15251978Round 1 RH FIP in LitigationUTHunter25251980Round 1 RH FIP in LitigationUTHunter35271983?UTHuntington15411977Round 1 RH FIP in LitigationUTHuntington24961974Round 1 RH FIP in LitigationWYJim BridgerBW716081974New plantwide permit (2019)WYJim BridgerBW726171975New plantwide permit (2019)WYNaughton11921963?WYNaughton22561968?WYNeil Simpson II1901995?WYWyodakBW914021978Round 1 RH FIP in LitigationDescription of Methodology for 2028 Emissions Projections After incorporating input from project participants on current operating characteristics of Western EGUs, including current and required controls, “Rules-on-the-Books” NOx and SO2 emissions scenarios were developed for the year 2028 using the following methodology:Remove coal units that will retire by 2028 (per Table 1 above)Calculate 2028 emissions from remaining coal units using the following information:Gross load (MW-hr) based on: Scenario 1: highest annual gross load over the last three years (2016-18)Scenario 2: the average gross load over the last three years (2016-18)Heat Rate (btu/kw-hr) for each unit based on the 2016-18 three-year average.NOx and SO2 emission rates (lbs/mmbtu) for each unit based on one of the following:average emission rates over the last three years (2016-18) for units with no recent changes to emission controls; 2018 emission rates for units that recently added emission controls; oremission rates expected in accordance with current permit conditions but not reflected in 2018 data.2028 tons per year of NOx and SO2 were then calculated for each remaining coal unit as follows: Ton Per Year = ((Gross Load) x (Heat Rate) x (Emission Rate)) / 2x106. Results for each remaining coal unit under Scenario 1 and Scenario 2 are shown in “Data File 5 – 2028 Coal Scenarios”.2018 actual emissions are used to estimate 2028 emissions from the fleet of natural gas-fired EGUs. “Data File 6 – 2018 and 2028 gas units” shows the 2028 NOx and SO2 inventory for gas units across the 13-state region. The 2028 inventory has: 1) retiring gas units removed, 2) new gas units added, and 3) capacity factors adjustments as noted by the operators.2017/18 actual emissions for the “non-CAMD” units (which are not included in EPA’s database) are used to estimate 2028 emissions from these sources with 1) retiring units removed, 2) new units added, and 3) expected changes in capacity factors as noted by the operators. (See Data File 7: non-CAMD units)The resulting 2028 NOx and SO2 emissions for Western EGUs are shown below. (See: Data File 5 - 2028 Coal Scenarios)2028 ScenariosAs described above, two 2028 emissions scenarios have been developed for the remaining coal units. The only difference between the two scenarios is the assumption regarding capacity factors (i.e., gross load expressed as MW-hours per year). Scenario 1 calculates 2028 emissions using the highest gross load over the last three years, whereas Scenario 2 calculates 2028 emissions using average gross load over the last three years (2016-18). As shown in Figures 6 and 7, the difference in total emissions between these two scenarios is relatively small, especially compared to the overall reductions from 2008.Since there is no specific guidance on which methodology to use for forecasting 2028 emissions from EGUs for Regional Haze planning, and because there are good arguments to be made in favor of both scenarios, WRAP members will have to engage in further discussions to determine whether Scenario 1 or Scenario 2 should be used in the 2028 Rules-on-the-Books modeling runs. Total Scenario 2 emissions from remaining coal units are about 9.5% higher than Scenario 1, but it is important to note that no adjustments have been made to the three-year average capacity factors used to calculate Scenario 2. During the data review process for this project, plant operators identified years when units were down for extended periods due to unplanned outages or major overhauls, or for installation of pollution controls. If the WRAP elects to use Scenario 2 emissions for modeling, it may be appropriate to remove data for years when units experienced extended outages. A preliminary analysis indicates that incorporating these adjustments would shrink the difference between the two scenarios to about 5%.Figure 6:2028 Scenario 1 NOx emissions are 73% below 2008 levels and 33% below 2018 levels.2028 Scenario 2 NOx emissions are 75% below 2018 levels and 38% below 2018 levels.Figure 7:2028 Scenario 1 SO2 emissions are 76% below 2008 levels and 23% below 2018 levels.2028 Scenario 2 SO2 emissions are 78% below 2018 levels and 29% below 2018 levels.Figure 8: (See: Data File 8 – 2018 and 2028 by State)Figure 9a: NOx Emission Rates (#/mmbtu) and 2028 Tons Per Year (Scenario 1) for each remaining coal unit (See: Data File 9 – scatter plots). See Table 3 below for key to numbering on this graph.Figure 9b: SO2 Emission Rates (#/mmbtu) and 2028 Tons Per Year (Scenario 1) for each remaining coal unit (See: Data File 9 – scatter plots). See Table 3 below for key to numbering on this graph.Table 3: Key to numbering of units on Figures 9a and 9b. Column 1 in the table below shows the data label number corresponding to each remaining coal unit included in the graphs.Data LabelState Facility Name Unit ID2028 NOX ER2028 NOX Tons2028 SO2 ER2028 SO2 Tons1AZApache Station30.1911,2030.0332082AZCoronado U1B0.0558210.0071053AZCoronado U2B0.0558120.006834AZSpringerville10.1722,1860.2312,9475AZSpringerville20.1702,2810.2092,7956AZSpringerville40.0809450.0819617AZSpringervilleTS30.0771,0350.0771,0368COComanche30.0661,6880.0832,1409COCraigC20.0609580.03149210COCraigC30.2193,2210.1311,92811COHaydenH10.0443300.12392212COHaydenH20.0503830.13199713COMartin Drake60.2175650.0318014COMartin Drake70.2309970.02510715COPawnee10.0541,1300.0941,94916CORawhide1010.1211,3260.08087717CORay D Nixon10.1671,1800.07553018MTColstrip30.1524,2360.0912,52419MTColstrip40.1554,2420.0892,42820MTHardin U10.0801930.09322521NDCoal Creek10.1263,0280.1433,44522NDCoal Creek20.1262,9460.1423,32623NDLeland Olds10.1471,1310.09170524NDLeland Olds20.3004,4980.0891,33825NDMilton R YoungB10.3323,7380.07483326NDMilton R YoungB20.3346,3690.1262,40927NMEscalante10.3512,4540.12688328NNFour Corners40.0801,4820.05092629NNFour Corners50.0801,7830.0501,11430NVTS Power Plant10.0502810.03017131SDBig Stone10.0831,1020.07296132UTBonanza434660.2775,7220.0621,28133UTHunter10.1962,7880.06794634UTHunter20.1862,8550.0851,29935UTHunter30.2694,3490.0771,25236UTHuntington10.2122,9750.0931,30137UTHuntington20.2043,1080.0751,14738WYDry Fork Station10.0437410.0601,03039WYJim BridgerBW710.1883,0070.1432,28740WYJim BridgerBW720.1823,1630.1542,67741WYJim BridgerBW730.0508210.1442,34442WYJim BridgerBW740.0508310.1422,38643WYLaramie River10.0601,1190.0951,76644WYLaramie River20.1503,1940.0921,95545WYLaramie River30.1503,8530.1243,18046WYNaughton10.2021,4660.13699147WYNaughton20.2141,8320.1351,15348WYNeil Simpson II10.1355790.09540949WYWygen I10.1315920.08237050WYWygen II10.0542490.05324251WYWygen III10.0432130.05426752WYWyodakBW910.2253,6100.1522,45053NDAntelope ValleyB10.1132,02654NDAntelope ValleyB20.1021,938NOT GRAPHED – VALUES OUTSIDE RANGE OF GRAPHS:NDAntelope ValleyB10.3616,483NDAntelope ValleyB20.3456,554NDCoyoteB10.4567,8520.86314,878Figure 10: Source: EPA CAMD (See Data File 10 – gas 2014-18)The 2028 emissions projections developed for this project generally use 2018 actual emissions for natural gas-fired EGUs. As shown in Figure 10, 2018 NOx emissions from natural gas-fired EGUs in the West were higher than in recent years. This is due in part to some coal units fuel-switching to natural gas, along with a 14% increase in gas generation between 2017 and 2018. ................
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