Impact Assessment Report for the Stack Heights Regulations Final April, 1981 Control Programs Development Division Office of Air Quality Planning and Standards Office of Air, Noise, and Radiation ------- Introduction Section 123 of the Clean Air Act, as amended, requires the Administrator to promulgate regulations to prevent the use of tall stacks and other dispersion techniques in lieu of constant emission controls. The Act requires the Administrator to promulgate regulations for determining Good Engineering Practice (6EP) stack height based on the height necessary to avoid excessive pollutant concentrations in the immediate vicinity of a source due to downwash, wakes or eddies created by the source itself, nearby structures or nearby terrain features. The Administrator proposed regulations in the FEDERAL REGISTER on January 12, 1979 (44 FR 2608) and now is preparing to promulgate those regulations. This study refines the results of previous reports on the predicted worst-case impact of those regulations. In the proposed regulations, the Agency set forth a procedure for determining a source's GEP stack height. Generally, GEP stack height is determined by a formula based on the dimensions of nearby structures. However, the Agency provided for a de minimis height of 30 meters and for establishing a GEP stack height through fluid modeling study or a field study. Accompanying the proposed regulations was a regulatory impact study. This study was developed to evaluate the potential impact of the proposed stack height regulations in terms of emissions and estimated costs for a specific category of sources, coal-fired power plants. This category 2 ------- on 7 of sources was selected for study because of: (1) its significant emissions contribution, (2) its use of tall stacks, and (3) the availability of stack data to perform an assessment regarding the Impact of the regulations. The analysis, at the time of proposal, was limited in several areas. First, since specific information regarding building heights was not readily available, estimated building heights using a general formula relating boiler size to building height was used. Second, structure- based GEP estimates were calculated using a standard factor times the height of the structure, rather than the proposed formula because specific building widths were not available. Third, terrain-based GEP estimates were calculated using a standard factor times the height of the highest terrain feature within 7/2 mile of the plant because of the unavailability of specific wind tunnel studies to determine GEP for terrain features. Fourth, the potential increase or decrease in emissions for all plants as a result of the regulations was derived from an arithmetic average of modeling estimates of stack height changes to ambient pollutant level concentration changes. This relationship was derived from a sample of plants which covered the full range of actual plant stack heights using worst-case short-term meteorological conditions 1n EPA's PTMAX dispersion model. Fifth, since specific plant-by-plant economic information was not readily available, the direct cost of control was based upon the estimated average emission reductions resulting from implementation of the proposed regulations. Data on emission limitations and economic cost from the Ohio 3 ------- SOg State Implementation Plan study^ were used to convert the average percent emission reduction to an average change in emission limitation. These data were then used to estimate the control costs attributable to the change in emission limitation based upon the assumption that the costs identified in the Ohio Study were representative of those that would have occurred nationwide. Finally, since only a selected category of sources was analyzed, the results were highly dependent upon the rep- resentativeness of this category of sources to other categories which may be affected by the proposed regulations. However, it was believed that coal-fired power plant analysis represents the worst-case regarding the potential impacts of the proposed regulations. Thus, the Agency stated that, the results of the analysis should be interpreted as an estimate of the potential emissions and economic impact which the coal-fired power plant community may experience as a whole. Approximately 78 persons submitted comments on the proposed regulations prior to a public hearing held on May 31, 1979. Eight persons submitted comments orally at the hearing and 11 persons submitted post hearing comments. Many of the commenters referred to the impact study as being inadequate since it was not based on individual plant information for determining GEP stack height. Some of the commenters mentioned that the Agency should also study the effects of the regulations on sources other than coal-fired power plants. ^Study of the Economic Impact of Sulfur Regulations Promulgated by the U.S. Environmental Protection Agency for Ohio on August 27, 1976. 4 ------- In an effort to address the above concerns, the Agency contracted for two studies to better assess the technical and economic impacts of 2 the proposed regulations. The first report prepared by H. E. Cramer Co., (Cramer) identified the pollution source categories most likely to be affected by the stack height regulations, estimated the total amount of emission reductions the proposed regulations would require, and estimated the overall changes in air quality the proposed regulations would produce. The study based GEP stack height on the building dimensions of a small sample of sources in each source category. The review could not apply the GEP formula to all the sources expected to be subject to the regulations (i.e., stacks built after 1970) due to lack of building data. The expected necessary reductions 1n emissions were estimated using a simplified ratio of stack height to maximum ground level concentration. This ratio, based on modeling theories, was generally conservative, indicating large emission reductions for relatively small stack height changes because 1t was developed on some worst-case assumptions such as limited plume rise. The major result of this study was to confirm that the Industry most affected by the regulations would be the coal-fired steam electric plants. The second study prepared by Energy and Enviromental Analysis, Inc., (EEA) used the general source-category wide GEP height for coal-fired power plants as the basis for calculating cost of implementation of the regulations. Lack of specific data on plant boiler characteristics and other factors led to several worst-case assumptions on fuel consumption. This study predicted a worst-case costs of the regulations to lie between approximately 2 See "Identifying and Assessing the Technical Bases for the Stack Height Regulatory Analysis," H. E. Cramer Co., Inc., Dec. 1979. 3 See "Cost and Economic Impact Analysis of the Proposed Stack Height Regulations," EEA Inc., August 15, 1980. 5 ------- $223 million and $794 million. Their impact assessment on national electric rates predicted an increase from 0.5 to 1.3 percent. EEA also investigated the impact on particular power generation companies with this impact ranging from a 5 percent to a 26 percent increase in single utility electric rates. Based on the individual impacts of a small sample of sources for which information existed on building heights, boiler capacity, and emissions, the economic impacts predicted by the above studies seemed too high even for a "worst-case" figure. In order to better ascertain the impact of the GEP formula for setting emission limitations, the Agency decided to obtain more information on fossil-fuel fired power plants with new stacks. Since most power plants can justify GEP stack height above 65 meters 4 and since those plants with stacks below 65 meters have low total emissions, this study was limited to sources with stacks above 65 meters. The decision to study only fossil-fuel fired power plants is supported by the Cramer Report since that industry built close to 75 percent of the new stacks, excluding flares, over 65 meters since 1970. The Agency did not investigate terrain effects on GEP stack height at these plants for three reasons. First, in most cases, the plants had emissions within the limits predicted to be necessary to meet the standards while using a GEP stack height calculated for building dimensions. Second, to determine the GEP based on terrain-induced downwash would require an extensive fluid model study or field study for each plant. Finally, plants in complex terrain areas may have plume impaction on the terrain features which would require more restrictive emission limitations, cancelling the effect of increased stack height credit. 4 See "An Assessment of the Potential Effect of Stack Height on Sulfate Formations and Sulfate Deposition," EPA, Dec. 1979. 6 ------- Methodology An assessment of the fossil-fuel fired power plants that could be affected by the proposed regulations was developed first. The only criteria for a plant to be on this list was that at least one stack taller than 65 meters was constructed or permitted after 1970. The two previous studies provided a basic list of these plants which was expanded based on new permit applications and information from Regional and State offices. In total, 148 power plants were identified in this category. Emissions data, 1979 coal consumption, quality of the 1979 coal purchases and Information on boilers and their related stacks were compiled on these plants. Nearby structure information for the new stacks was collected for 102 plants. The number of plants in each Region is listed in Table 1. Me established a GEP stack height based on the formula (H + 1.5L) ® for each of the 102 plants where sufficient information existed ( i.e., structure dimensions and locations). For the remaining 46 plants, GEP stack height was assumed to be the average of the computed formula heights in the same Region. We assumed that plants built in a Region have generally the same physical characteristics. Table 2 shows the Regional GEP averages. This method is similar to that used by EEA, but is based on more specific plant data. In their report, EEA performed only two sets of calculations for each end of the range of formula GEP given by Cramer. This range was 122 meters (400 ft) to 183 meters (600 ft). 5See 44 FR 2614. 7 ------- Table 1 Number of fossil-fuel power plants that may be affected by Stack Heights Regulations EPA Region Plants Surveyed Plants With Building Data I 7 6 II 6 4 III 26 22 IV 31 24 V 30 26 VI 21 8 VII 13 5 VIII 6 2 IX 5 4 X 3 2 148 102 8 ------- Table 2 Average Regional GEP for Fossil Fuel-Fired Steam Electric Plants EPA Region Height (m) I 131 II 126 III 177 IV 142 V 157 VI 179 VII 152 VIII 171 IX 132 X 134 9 ------- Our new information provides actual building generated GEP formula heights for 102 plants. It should be noted, that the 46 plants without building information tended to be smaller in generating capacity and had shorter stacks than the rest of plants on the list. We compared the calculated GEP stack heights with the actual stack heights for all 148 plants. For those plants with stacks constructed after 1970 which exceeded their GEP stack heights, we calculated a revised emission limitation. The revised emission limitation was based on a ratio of actual to GEP stack height and the current State Implementation Plan (SIP) emission limitation. The development of the ratio was performed by Cramer and documented in Appendix C of that report. We recognized that in some cases this overestimates the amount of reductions required, yet it does provide a good worst-cost estimate. By comparing the sulfur content of fuel currently used at the plant (1979 consumption)® with the revised emission limitation, we identified the plants which may have to reduce actual emissions. Where existing fuel sulfur contents exceeded the plant's current SIP emission limitation, we assumed that the plant would be brought into compliance with its present SIP. We then calculated its cost based on the reduction from its SIP emission limitation. These calculations will have to be redone with actual modeling of each source before any emission limitations can be set and enforced. The plants identified here are not likely to have these exact reductions shown. 6See "Cost and Quality of Fuels for Electric Utility Plants - 1979" DOE/EIA - 0191(79). 10 ------- This study merely identifies the general impact on the entire source group. Some plants had actual emission levels low enough to meet the revised limitation and therefore would not be affected by the regulation, except for a numerical change in their SIP emission limitation. In calculating the emission reductions at each plant, EEA assumed that 75 percent of a plant's emissions exited through the tall stack(s). That assumption was not required for this study; the exact links between boilers and stacks were established for all plants where emission computations were required. The next step was to calculate the sulfur content of the coal needed to meet any revised emission limitation that was more restrictive than current emission levels. Based on the EEA report, we assumed that eastern power plants (in EPA Regions I-V) would not purchase coal with less than 0.7 percent sulfur content since it 1s not produced in large quantities in local mines. There 1s one exception to this, however, for a plant which currently uses 0.5 percent coal for approximately one- third of its Btu consumption. The difference in price for buying new coal with lower sulfur content was based on costs reported in the Department of Energy's "Costs and Quality of Fuels for Electric Utility Plants - 1979" (D0E/EIA0191(79)). Appendix A contains fuel prices for each Region by sulfur content. Next wedealt with how much high sulfur coal would be replaced with low sulfur coal. Based on the EEA report the shift across 1.7 percent 11 ------- sulfur content would be the best indicator of an absolute shift in coal markets, (1.7 percent is the mean sulfur content of coal produced in the U.S.^). Shifts in higher percentages would be traded off among current producers of coal shipping to different users. Shifts to coal with sulfur content below 1.7 percent would mean an increase in production of lower sulfur coal at the expenses of production of higher sulfur levels. Although the use of actual plant data for generating most of the formula stack heights indicates a much lower cost impact than previous studies, there are still assumptions that make these predictions worst- case estimates. In some cases, the current SIP level is under question as being more restrictive than necessary to protect the ambient air from violations of ambient air quality standards or prevention of significant deterioration air quality increments. When the SIP limitations are revised to incorporate the requirements of the proposed regulations, the State may use more accurate modeling than previously used to set the old SIP limit which could result in less actual change in emission levels at some sources. Terrain features near a source could reduce or increase the effect of the regulations. Also, different meteorological conditions from those assumed in the Cramer ratio calculations could lessen the restrictive impact of the regulations. Thus, the estimates presented in this report, although closer to the expected costs of implementation of the regulation, are still to be considered the upper bound of the actual costs. ^See "Cost and Quality of Fuels for Electric Utility Plants - 1979." DOE/EIA - 0191(79). 12 ------- RESULTS Appendix B to this report is the list of 148 power plants included in this study. Information on the SOg emission limitation was converted to the percent sulfur coal by weight needed to be burnt in order to comply with the emission limitation. This information is only provided for plants which would be required to reduce their emissions. Table 3 shows, by Region, the number of plants with existing stacks above their GEP formula height or the Regional formula height and the number of these plants that would be required to reduce emissions. Only Regions III, IV, and V have plants where actual emission reductions would be required. These 16 plants are fairly evenly distributed among the three Regions. For those Regions, Table 4 presents the total emission reductions anticipated to be necessary. The total reduction is estimated to be 412,000 tons of S02 per year. These S0£ reductions are estimated to come from shifts in sulfur content in fuel. The expected shift to low sulfur coal is presented in Table 5. Nationally, the total coal shift which may affect market production is estimated to be 14,997,000 tons per year. No increase in coal shipments from the western U.S. to the eastern U.S. is expected, since the eastern markets could supply the additional 7.5 percent increase in low sulfur coal based on yearly increases in low sulfur coal production. The annual national cost total for compliance with these regulations by the power industry is expected to be $32.5 million. Table 6 presents the Regional breakdown of these costs. 13 ------- Table 3 Plants Required to Reduce Emission EPA Region Plants Above Actual GEP Plants Above Regional GEP Plants Reduction No Reduction Reduction No Reduction Requiring Reductior Requi red Requi red Requi red Requi red i I 1 II 1 1 III 4 2 1 2 5 IV 4 6 2 3 6 V 5 7 1 5 VI VII 5 VIII IX X 1 Total 13 17 3 13 16 14 ------- Table 4 Regional Reductions in SO2 Emissions (tons/year) EPA Region SOg Reductions III 136,000 IV 107,000 V 169,000 National Total 412,000 15 ------- Table 5 Regional Expected Shifts in Annual Coal Demand by Sulfur Level Increase in Coal Demand in 1000 Tons Per Year EPA Region Shift to Low Sulfur (<1.7%) III 2,906 IV 7,796 V 4,295 National Total 14,997 16 ------- Table 6 Regional Expected Costs of Complying with the Proposed Stack Height Regulations Annual Costs (million 1979 dollars) Region Cost III 7.5 IV 10.9 V 14.1 National Total 32.5 17 ------- CONCLUSIONS The impact of these regulations will be substantially less than predicted in previous studies. The actual information on power plant dimensions demonstrates that many plants built within the past ten years are consistent with these regulations and thus will not be negatively affected by their implementation. Any costs incurred would be passed on to consumers of electricity mainly in the three affected regions. This study indicates that no power plant would be required to install scrubbers to meet the revised SIP limit. The total 1979 fossil-fuel cost for all electric utilities in the o U.S. was $30.5 billion. The impact of these regulations represents an approximate 0.1 percent increase in national utility fuel cost. Since fuel cost is only a portion of the total cost of producing electricity, the increase in national electric rates will be less than 0.1 percent. For the individual plants affected in Region III, the increase in fuel cost is estimated to range between 0.6 and 6.8 percent. In Region IV, the range is estimated to be 0.9 to 2.2 percent and for Region V the range is estimated to be 1.6 to 5.0 percent. The increase in fuel costs for the power plants will be passed on to the consumers in higher electric rates. These rates are based upon fuel costs and operating costs of the electric system. Most of the affected plants are part of a larger system which means that actual percent increase in a system's electric rates will be less than the percent increase in fuel cost for the single plant. In addition, since fuel costs are only a portion of the costs 8See "Cost and Quality of Fuels for Electric Utility Plants 1979." D0E/EIA—019(79). 18 ------- of producing and transporting electricity, the increase in consumer electric rates was taken as the ratio of increased fuel costs to the ranges from less than 0.1 percent to 2.5 percent of the systems' 1979 revenue. Thus, if the increase costs are passed directly on to the consumer, the electric rates would increase from 0.1 to 2.5 percent. The effect on the coal market is also less than previously predicted. The total shift from high sulfur content coal to low sulfur content coal would be less than 15 million tons per year. This represents approximately 7.5 percent of the 202 million tons of coal produced with sulfur content of 2 percent or greater in the eastern U.S. This shift could be less if coal washing, coal blending, or other control techniques were used to achieve the desired results. The average coal in Appalachian regions could be washed to remove a sufficient part of the sulfur content to meet reduction required by the regulations in some cases. In 1979, some Appalachian and Midwest coal was physically cleaned to remove from 1 to 22 percent of S02 emissions of the raw coal. The costs of coal washing increased the price of delivered coal 10 to 20 percent.^ This cost could make coal washing preferable to switching coal supplies. Coal washing could be used for small shifts 1n percent sulfur where the total costs are less than costs of interrupting current coal supplies. Although coal washing or other control systems could be used to reduce the economic impacts of these regulations, they were not considered in this worst-case study g 1979 revenues. The Increase In fuel costs for the affected plants ^"Coal Resources and Midwestern States," Teknekron Research, Inc., March 1981. 19 ------- because information was not available on the washability of the specific coal used. Coal washing or other control systems would only be used if they were less costly than purchasing lower sulfur coal. An evaluation of other source categories that may be affected by the regulation, was conducted by Cramer. That report identified the non-ferrous smelters, the pulp and paper industry, the steel industry and the oil, gas, and chemical industry as having potential impacts under the regulations. The majority of these plants would have stacks in the 65 to 90 meter range. Cramer estimated GEP heights for these source categories. In this review, Cramer identifies one smelter, no pulp and paper plant stacks, no steel plant stacks, and with the exclusion of flares, no oil, chemical gas plant stacks that are affected by the regulation. 20 ------- References Federal Register, Volume 44, No. 9, Friday, January 12, 1979, pp. 2608-251FT 2. H. £. Cramer Co., Inc., "Identifying and Assessing the Technical Bases for the Stack Height Regulatory Analysis," Final Report, prepared for the U.S. EPA, December 1979. 3. Energy and Environmental Analysis, Inc., "Cost and Economic Impact Analysis of the Proposed Stack Height Regulation," Final Report, prepared for the U.S. EPA, August 15, 1980. 4. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Steven L. Eigsti, "An Assessment of the Potential Effect of Stack Height on Sulfate Formation and Sulfur Deposition," December 1979. 5. U.S. Department of Energy, Energy Information Administration, "Cost and Quality of Fuels for Electric Utility Plants - 1979," June 1980. (DOE/EIA-0191(79)). 6. Regional Office Survey, conducted November 1980 - March 1981. 7. Teknekron Research, Inc. "Coal Resources and Sulfur Emission Regulation: A Summary of Eight Eastern and Midwestern States," March, 1981. Prepared under contract for Industrial Environmental Research Laboratory» U.S. EPA. 8. PEDCo Environmental Specialist, Inc. "Study of The Economic Impact of Sulfur Regulations Promulgated by U.S. Environmental Protection Agency for Ohio on August 27, 1976, Study Document No. 8, Cost Estimates for Various Sulfur Dioxide Strategies for Selecting Ohio Utility Power Plants". Final Report prepared for U.S. EPA, June 1976. (EPA 905/5- 76/008). 21 ------- Appendix A Delivered Coal Prices ($/ton) by Sulfur Content (1979) 0.51% S 1.01* S 1.51% S 2.01% S to to to to 1.00% S 1.50% S 2.00% S 3.00% S >3.00%S Region III 35.84 33.99 29.09 29.05 22.67 Region IV 36.18 34.19 34.27 32.53 23.95 Region V 30.58 28.88 28.16 27.55 25.72 Source: D0E/EIA-0191(79) A-l ------- Appendix B Regional Survey Data and Calculations No. Plant Name Actual Stack Height (hi) Grandfather Height or GEP Formula (m) % Boiler Cap affected Current SIP limit ts Actual Emissions Revised Emissions* %S %S 1-1 Brayton Point 107 1-2 Hyman 129 1-3 Canal 152 1-4 Newlngton 124 1-5 Salem Harbor 152 I-6 Schiller 69 il-l Oswego 213 II-2 Bowline 87 I!-3 Northport 183 II-4 England 76 II-5 Roseton 79 II-6 Astoria 92 166 0 132 0 152 0 [132] 0 128 SIP Modeled at GEP 73 0 [126] burning oil [126] burning oil 148 burning oil 76 0 burning oil 119 0 burning oil 202 0 burning oil not likely to cause violation at GEP not likely to cause violation at GEP * Based on Cramer (1979) Appendix C Methodology [ ] Average Regional GEP ------- Appendix B (continued) Regional Survey Data and Calculations Grandfather Height or Current No. Plant Name Actual Stack Height GEP Formula % Boiler Cap SIP Limit Actual Emissions Revised Emissions* (m) (m) affected %S %S %S II-l Indian River 122 150 0 11-2 Eddystone 76 76 0 11-3 New Castle 71 [177] 0 11-4 Willow Island 304 [177] 100 2.29 1.31 0.87* 0.80 ** 1.60 11-5 Wagner 213 [177] 30 1.00 0.87 11-6 Morganton 213 [177] 100 2.13 1.67 11-7 Benning 78 89 0 11-8 II-9 Oickerson Chalk Point 122 217 122 209 0 0 1.00 1.78 *** 1.00 11-10 Hatfield 213 213 0 11-11 Conemaugh 305 194 100 2.44 2.36 1.07 11-12 Shawville 183 114 41 2.44 2.07 1.14 11-13 Pleasants 190 232 0 ~ Based on Cramer (1979) Appendix C Methodology ick No substantial change in actual emissions required "icfcic No substantial change in SIP emissions required B-2 ------- Appendix B (continued) Regional Survey Data and Calculations Grandfather 11-21 Mitchell 11-22 Cheswlck 11-23 P. Sporn II-24 Mount Storm II-25 Amos 11 -26 Kammer 367 229 184 176 274 183 Height or Current No. Plant Name Actual Stack Height GEP Formula % Boiler Cap SIP Limit Actual Emissions (m) («•) affected %S %S III-14 Montour 183 195 0 III—15 Homer City 244 198 100 2.44 2.06 II1—16 Seward 184 109 100 2.44 2.30 III-17 Martins Creek 183 225 0 II I—18 Brunner Island 183 183 0 111-19 Mansfield 90 90 0 III—20 Harrlson 305 195 Current SIP 367 229 196 163 274 274 0 0 0 0 0 Modeled at GEP 1.77 2.05 %S 1.74 1.04 1.76 ** ~ Based on Cramer (1979) Appendix C Methodology. No substantial change In SIP emissions B-3 ------- Appendix B (continued) Regional Survey Data and Calculations Grandfather Height or Current No. Plant Name Actual Stack Height GEP Formula % Boiler Cap SIP Limit Actual Emissions Revised Emis (m) (m) affected %S %S %S IV-1 Widows Creek 300 109 50 3.0 0.7 0.7 IV-2 Harlee Branch 305 131 100 3.0 0.9 0.8 IV-3 Mitchell 152 82 100 3.0 1.2 1.1 IV-4 Yates 252 148 100 3.0 1.8 1.3 IV-5 Bowen 305 305 0 IV-6 Hammond 229 141 100 3.0 1.7 1.4 IV-7 Winyah 122 122 0 IV-8 Wateree 92 92 0 IV-9 Canadys 62 70 0 IV-10 Crist 137 140 0 IV-11 Big Bend 149 155 0 IV-12 Watson 122 153 0 IV-13 Lee 92 92 0 IV-14 Cape Fear 61 61 0 IV-15 Sutton 168 168 0 * Based on Cramer (1979) Appendix C Methodology. B-4 ------- Appendix B (continued) Regional Survey Data and Calculations No. Plant Name Grandfather Height or Actual Stack Height GEP Formula (m) (m) Current % Boiler Cap SIP Limit affected %S Actual Emissions Revised Emissions* %S %S IV-16 Belews Creek 183 207 0 IV-17 Cliffside 152 195 0 IV-18 Roxboro 244 171 60 1.4 0.7 1.3 IV—19 Brown 171 [142] 15 3.7 2.5 2.7 IV-20 Coleman 106 [142] 0 IV-21 Big Sandy 251 [142] 75 3.7 2.1 2.1 IV-22 Mill Creek 187 [142] 100 0.8 4.0 0.7 IV-23 Shawnee 243 77 100 *** IV-24 Gaston 229 [142] 67 2.4 1.9 1.1 IV-25 Gorgas 229 143 100 2.4 1.3 1.1 IV -26 Smith 183 1142] 100 1.1 1.0 0.8 IV—27 Kingston 304 304 0 IV-28 Paradise 244 244 0 IV-29 Cumberland 304 304 0 IV-30 Barry 183 183 0 IV-31 Henderson 106 [142] 0 tUt Based on Cramer (1979) Appendix C Methodology. This plant is involved in additions of haghouses and switching of coal. New SIP meets GEP requirements. B-5 ------- Appendix B (continued) Regional Survey Data and Calculations Grandfather Height or Current No. Plant Name Actual Stack Height GEP Formula % Boiler Cap SIP Limit Actual Emissions Revised Emissio (m) (m) affected %s %s %S V-l Baldwin 184 200 0 V-2 Dal1 man 152 121 52 3.7 3.7 2.5 V-3 Coffeen 152 199 0 V-4 Meredosia 160 160 0 V-5 Edwards 153 139 45 1.0 0.8 0.8 V-6 Powerton 152 180 0 V-7 Joppa 163 123 100 2.2 2.1 1.6** V-8 Petersburg 187 195 0 V-9 Stout 172 176 0 V-10 Michigan City 154 183 0 V-l 1 Gibson 152 [157] 0 V-l 2 V-l 3 Cayuga Cul1ey 152 152 190 133 0 50 0.7 3.7 *** 0.7 V-14 Monroe 240 240 0 V-l 5 Karn 137 162 0 V-16 Eri kson 142 [157] 0 V-l 7 Presque Isle 122 118 0 V—18 Shiras 88 88 0 Based on Cramer (1979) Appendix C Methodology. B-6 Terrain effects likely to influence GEP SIP limitation. ¦k** Ho substantial change in SIP required. ------- Appendix B (continued) Regional Survey Data and Calculations No. Plant Name Actual Stack Height (m) Grandfather Height or GEP Formula (m) % Boiler Cap affected Current SIP Limit Actual Emissions %S %S Revised Emissions* %S V-19 V-20 V-21 V-22 V-23 V-24 V-25 V-26 V-27 V-28 V-29 V-30 Boswell New Ulm Hi ami Fort Saamris Gavin Stuart Conesville Avon Lake East Lake Hamilton Columbia St. Clair 120 45 244 305 335 240 244 183 183 79 198 180 [157] 65 185 165 207 193 [157] 152 163 [157] 190 180 0 0 33 27 100 50 84 0 50 0 2.4 2.7 5.8 1.9 3.5 1.9 2.4 2.4 1.1 4.0 modeled at GEP formula modeled at GEP formula 1.5 0.9 2.1 1.1 1.5 0.7 0.8 0.7 "kit 1c Based on Cramer (I979) Appendix C Methodology. No substantial change in SIP required. B-7 ------- Appendix B (continued) Regional Survey Data and Calculations No. Plant Name 'Actual Stack Height (m) Grandfather Height or GEP Formula (m) % Boiler Cap affected Current SIP Limit Actual Emissions %S %S Revised Emissions* %S VI-1 San Juan 120 [179] 0 VI-2 Chouteau 150 [179] 0 VI-3 Monticello 122 [179] 0 VI-4 Martin Lake 120 [179] 0 VI-5 Oak Knoll 137 140 under construction VI-6 South Hallsville 160 160 0 VI-7 Independence 300 305 0 VI-8 Big Cajun 207 190 100 0.7 0 VI-9 Muskogee 152 152 0 VI-10 Coleto Creek 124 140 0 VI-11 Escalente 152 [179] under construction VI-12 Welsh 91 [179] 0 VI-13 Forest Grove 137 [179] under construction VI-14 Sandow 122 [179] 0 VI -15 Gibbins Creek 142 [179] 0 Based on Cramer (1979) Appendix C Methodology. B-8 ------- Appendix B (continued) Regional Survey Data and Calculations Grandfather Height or No. Plant Name Actual Stack Height GEP Formula % Boiler Cap (m) (m) affected VI-17 Willon Site 213 213 0 VI-18 Ua Parrash 152 [179] 0 VI-19 Oklaunlon 91 [179] 0 VI-20 Folk Station 122 122 0 VI-21 Fayette Power 122 [179] * Based on Cramer (1979) Appendix C Methodology. Current SIP Limit Actual Emissions Revised Emissions* %S %s %s under construction under construction B-9 ------- Appendix B (continued) Regional Survey Data and Calculations Grandfather Height or Current No. Plant Name Actual Stack Height GEP Formula % Boiler Cap SIP Limit Actual Emissions (m) (m) affected %S %S VII-1 Sikeston 137 87 100 modeled at GEP VII-2 Ottumwa 183 174 under construction VI1-3 Jeffrey 163 [152] no probable reduction, burning VI1-4 Columbia 90 [152] 0 VI1-5 Streeker 92 [152] 0 VII-6 Rush Island 183 [152] no probable reduction, burning SIP = 2% S VII-7 New Madrid 183 155 100 none (9.6)** 5.7 VII-8 Southwest Station 122 122 0 VII-9 Lawrence 106 [152] 0 VII-10 la tan 213 220 0 VII-11 Nearman Creek 107 [152] 0 •kick 0.9 1.3 VI1-12 La Cynge 209 [152] VII-13 Labadie 213 [152] kk none (9.6) 2.5 Revised Emissions %S 7.0 0.8 6.2 *Based on Cramer (1979) Appendix C Methodology. -k-k No Federal Limit. 80% SO2 scrubbing on one unit not included in this emissions estimate. B-10 ------- Appendix B (continued) Regional Survey Data and Calculations No. Plant Name Actual Stack Height Grandfather Height or GEP Formula (m) % Boiler Cap affected Current SIP Limit is Actual Emissions Revised Emissions* %S %S VIII-1 VIII-2 VIII-3 VIII-4 VIII-5 V1II-6 Hayden Martin Drake Jim Bridger Huntington Craig Commanche 120 62 151 103 181 151 [171] [171] 151 [171] 190 [171] 0 0 0 0 0 0 IX-l Navajo IX-2 Coronado IX-3 Kahe IX-4 Tracy #3 IX-5 Pittsburgh #7 70 91 91 137 181 [132] 110 91 144 0 0 0 under construction X-l X-2 X-3 Central11a Boardman Fairchild 141 200 46 [134] 208 65 100 0 0 3.6 1.3 3.6 Based on Cramer (1979) Appendix C Method®logy. B-ll ------- |