# Acid Rain Program; Nitrogen Oxides Emission Reduction Program > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A96-31839 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** December 19, 1996 - **Citation:** 61 FR 67112 ## Text SUMMARY: This action promulgates standards for the second phase of the Nitrogen Oxides Reduction Program under Title IV of the Clean Air Act (``CAA'' or ``the Act'') by establishing nitrogen oxides (NOX) emission limitations for certain coal-fired electric utility units and revising NOX emission limitations for others as specified in section 407(b)(2) of the Act. The emission limitations will reduce the serious adverse effects of NOX emissions on human health, visibility, ecosystems, and materials. EFFECTIVE DATE: December 19, 1996. ADDRESSES: Docket. Docket No. A-95-28, containing information considered during development of the promulgated standards, is available for public inspection and copying between 8:30 a.m. and 3:30 p.m., Monday through Friday, at EPA's Air Docket Section (LE-131), Waterside Mall, Room M1500, 1st Floor, 401 M Street, SW, Washington, DC 20460. A reasonable fee may be charged for copying. Background information document. The background information document containing responses to public comments on the proposed standards may be obtained from the docket. Please refer to ``Phase II Nitrogen Oxides Emission Reduction Program--Response to Comments Document''. FOR FURTHER INFORMATION CONTACT: Peter Tsirigotis, Source Assessment Branch, Acid Rain Division (6204J), U.S. Environmental Protection Agency, 401 M Street S.W., Washington, DC 20460 (202-233-9620). SUPPLEMENTARY INFORMATION: Regulated Entities Entities regulated by this action are electric service providers that run or operate coal-fired electric utility boilers including dry bottom wall-fired and tangentially fired boilers (Group 1) and certain other boiler types including boilers applying cell-burner technology, cyclone boilers, wet bottom boilers, and other types of coal-fired boilers (Group 2). Regulated entities and boilers include: ------------------------------------------------------------------------ Regulated Entities Regulated Boilers ------------------------------------------------------------------------ Electric Service Providers................ Dry bottom wall-fired. Tangentially fired. Cell Burners. Cyclones (larger than 155 MWe). Vertically fired. Wet bottoms (larger than 65 MWe). ------------------------------------------------------------------------ This table is not intended to represent a definitive enumeration of all existing and future entities regulated by this action. Rather, its intent is to provide a general guide for readers and to list entities that EPA is now aware will be regulated by this action. Other types of entities not listed in the table could also be regulated. To determine whether your (facility, company, business, organization, etc.) is regulated by this action, you should carefully examine the applicability criteria in Secs. 72.6 and 76.1 of title 40 of the Code of Federal Regulations. If you have questions regarding the applicability of this action to a particular entity, consult the person named in the preceding ``For Further Information Contact'' section. The information in this preamble is organized as follows: I. Rule Background A. Purpose of Acid Rain NOX Emission Reduction Program B. Summary of Final Rule 1. NOX Standards Promulgated by this Rule 2. Rationale for Revising Group 1 NOX Emission Limits and Environmental Impact of Group 2 NOX Emission Limits II. Public Participation III. Summary of Major Comments and Responses A. Phase II, Group 1 Boiler NOX Emission Limits 1. Boiler Population Used to Assess NOX Emission Limits 2. Time Period/Averaging Basis Used to Evaluate Performance of Low NOX Burner Technology 3. Analysis Method Used to Establish Reasonably Achievable Emission Limitations for Phase II, Group 1 Boilers 4. Percentile Used to Define Achievability B. Group 2 Boiler NOX Emission Limits 1. Cost Comparability and Its Basis 2. Cost Comparison Methodology 3. Retrofit Nature of Group 2 Controls 4. Group 2 Boiler Size Exemption 5. Cyclone Boiler NOX Controls 6. Wet Bottom Boiler NOX Controls 7. Vertically Fired Boiler NOX Controls 8. Cell Burner Boiler NOX Controls 9. Revision of Proposed Group 2 Boiler NOX Emission Limits C. Compliance Issues D. Title IV NOX Program's Relationship to Title I and NOX Trading Issues IV. Administrative Requirements A. Docket B. Executive Order 12866 C. Unfunded Mandates Act D. Paperwork Reduction Act E. Regulatory Flexibility Act F. Submission to Congress and the General Accounting Office G. Miscellaneous I. Rule Background A. Purpose of Acid Rain NOX Emission Reduction Program The primary purpose of the Acid Rain NOX Emission Reduction Program is to reduce the multiple adverse effects of the oxides of nitrogen, a family of highly reactive gaseous compounds that contribute to air and water pollution, by substantially reducing annual emissions from coal-fired power plants. Since the 1970 passage of the Clean Air Act, NOX has increased about 7%; it is the only conventional air pollutant to show an increase nationwide. Electric utilities are a major contributor to NOX emissions nationwide: in 1980, they accounted for 30 percent of total NOX emissions and, from 1980 to 1990, their contribution rose to 32 percent of total NOX emissions. In 1994, electric utility emissions represented about 33 percent of the total annual NOX emissions. Approximately 90 percent of estimated electric utility NOX emissions were attributed to coal combustion (see docket item IV-A-8 (USEPA, National Air Pollution Emission Trends, 1900-1994 (EPA-454/R- 95-011) at 2-2, October 1995)). The NOX emissions discharged into the atmosphere from the burning of fossil fuels consists primarily of nitric oxide (NO). Much of the NO, however, reacts with organic radicals in the air to form nitrogen dioxide (NO2) and, over longer periods of time, reacts with and forms other pollutants, including ozone (O3), nitric acid (HNO3) and fine particles. These pollutants are harmful to public health and the environment. NO2 and airborne nitrate also degrade visibility, and when they return to the earth through rain, snow, or fog (``wet deposition'') or as gases (``dry deposition''), they contribute to acidification of lakes and streams and to excessive nitrogen loadings to estuaries and coastal water systems such as in the Chesapeake Bay (``eutrophication''). NO2 has been documented to cause eye irritation, either by itself or when oxidized photochemically into peroxyacetyl nitrate (PAN). Ozone, the most abundant of the photochemical oxidants, is a highly reactive chemical compound which can have serious adverse effects on human health, plants, animals, and materials. Fine particles at current ambient levels contribute adversely to morbidity and mortality. [[Page 67113]] B. Summary of Final Rule 1. NOX Standards Promulgated by This Rule EPA today is promulgating new emission limitations to be implemented for nitrogen oxides (NOX) emissions for wall-fired and tangentially fired boilers (Group 1 boilers) and establishing emission limitations for certain other boilers (Group 2 boilers). The final rule implements section 407 (b)(2) of the Act, which applies to NOX emission limitations for Group 1 and Group 2 boilers during Phase II of the Acid Rain Program (January 1, 2000 and beyond). Under section 407(b)(2) the Administrator ``may revise'' the applicable NOX emission limitations for Group 1 boilers in Phase II if the Administrator determines that ``more effective low NOX burner technology is available,'' i.e., that data on the effectiveness of low NOX burner technology (LNB) installed after passage of the Clean Air Act Amendments of 1990 supports emission limitations more stringent than the limitations established for Group 1 boilers during Phase I of the Acid Rain Program pursuant to section 407(b)(1) of the Act. 42 U.S.C. 7651f(b)(2). Also under section 407(b)(2) of the Act, the Administrator must establish NOX emission limitations (on a lb/ mmBtu annual average basis) for Group 2 boilers, which include wet bottom boilers, cyclone boilers, cell burner boilers, and all other types of utility boilers not classified as dry bottom wall-fired and tangentially fired boilers, and must meet certain requirements in establishing these limitations. In setting the final emission limitations for Group 1 and Group 2 boilers, as summarized below, the Administrator has met the requirements in section 407(b)(2) of the Act. i. Revision of NOX Emission Limits for Phase II, Group 1 Boilers The Agency has developed a computerized database containing detailed information on the characteristics and emission rates of all coal-fired units with Group 1 boilers on which low NOX burners (LNBs) have been installed without any other NOX controls, and for which EPA has both quality assured long-term post-retrofit hourly NOX emission rate data, measured by continuous emission monitoring systems (CEMS), certified pursuant to 40 CFR part 75 (Acid Rain Continuous Emission Monitoring Rule), and quality assured short-term CEM or test data measurements of uncontrolled emission rates. This database, called the ``LNB Application Database,'' consists of 39 dry bottom wall-fired boilers and 14 tangentially fired boilers and forms the technical basis for EPA's evaluation of the effectiveness (percent NOX removal) of LNBs applied to Group 1 boilers. For the final rule, EPA has adopted a methodology that employs ``load-weighted annual average NOX emission rates'' over the full ``post-optimization period'' for evaluating the effectiveness of LNBs. The post-optimization period includes all available data beginning with the first hour of the low NOX period,1 when the LNBs were operating under optimized NOX removal conditions, and extending to the end of the entire data set, i.e., through June 30, 1996, the end of the latest available reporting period from the Acid Rain Emissions Tracking System (ETS). The post-optimization period contains quality assured CEM data spanning at least 4 calendar months for every boiler and at least 11 calendar months for most boilers (83%). In addition, EPA applied a NOX/load weighting scheme, using hourly load data reported for 1995, to develop ``load-weighted'' annual average NOX emission rates from the data set (see discussion in section III.A.2.iii of this preamble). Two advantages of using load-weighted annual average NOX emission rates over the post-optimization period are that the criteria used to define the ``post-optimization period'' take into account the site-specific nature of the LNB equipment optimization and operator training processes while the use of ``load weighting'' accounts for any potential impact of annual load dispatch patterns on NOX emissions. --------------------------------------------------------------------------- \1\ The ``low NOX period'' EPA used for assessing performance of LNBs applied to Group 1 boilers was defined by identifying the lowest average NOX emission rate each boiler has sustained for at least 52 days, i.e., over a period of 1,248 hours when the boiler was operating and valid CEM data, measured by CEMS certified pursuant to 40 CFR part 75, were available. (Data for 30 calendar days following estimated date boiler began operating after shutdown for LNB retrofit are not used when making this determination. See Table 1, DQO #4D). --------------------------------------------------------------------------- Following the identification of appropriate LNB applications and time period for analysis, EPA developed a two-part model to estimate: (1) Annual average emission rates that can be sustained by LNBs installed on Phase II units with Group 1 boilers and (2) percentile distributions of Phase II units that can comply with various performance standards. The first part of the model calculates the percent reduction achievable by LNBs as a function of uncontrolled emission rate, and the second part applies the estimated percent reduction to boiler-specific uncontrolled emission rates for the population of units that will be subject to any revised NOX emission limitations in Phase II. EPA used the percentile distributions to select reasonably achievable emission limits for the two types of Group 1 boilers, where ``reasonably achievable'' is defined as the controlled emission rate 85 to 90 percent of the affected population of units can meet or exceed on an annual average basis. EPA concludes that more effective low NOX burner technology is available for dry bottom wall-fired and tangentially fired boilers. Further, EPA concludes that for dry bottom wall-fired boilers, 0.46 lb/mmBtu is a reasonable emission limitation that is achievable using such technology. EPA estimates that 85 to 90% of the Phase II dry bottom wall-fired boilers can achieve this emission rate. The implementation of this standard, will result in an additional NOX emissions reduction of approximately 90,000 tons per year, beginning in 2000, below the emission levels anticipated under the Phase I Acid Rain NOX Emission Reduction Rule (60 FR 18751, April 13, 1995). Finally, EPA concludes that for tangentially fired boilers, 0.40 lb/mmBtu is a reasonable emission limitation that is achievable using such technology. EPA estimates that 85 to 90% of the Phase II tangentially fired boilers can achieve this emission rate. The implementation of this standard will result in an additional NOX emissions reduction of approximately 30,000 tons per year, beginning in 2000, below the emission levels anticipated under the Phase I Acid Rain NOX Emission Reduction Rule. As discussed below, EPA exercises its discretion under section 407(b)(1) to adopt these revised Group 1 NOX emission limitations because the resulting additional reductions are a reasonable step toward achieving necessary, significant NOX reductions and are consistent with the guideline in section 401(b) concerning the level of NOX reductions to be achieved. ii. Establishment of Group 2 Emission Limitations In order to meet the requirements of section 407(b)(2), EPA is using the following methodology for establishing Group 2 emission limitations: First, EPA determines what NOX control technologies are the best systems of continuous emission reduction available for each category of Group 2 boilers. Further, EPA considers only technologies for which there is reliable cost information on which to base a determination of whether they are of comparable cost to LNBs, applied to Group 1 boilers. Second, EPA evaluates each such NOX control technology and estimates the dollar cost per ton of NOX removed using the control technology on each boiler in the Group 2 population that is in the appropriate Group 2 boiler category. EPA then compares the dollar cost per ton of NOX removed for each [[Page 67114]] NOX control technology applied to the Group 2 boiler category to the dollar cost per ton of NOX removed for low NOX burners applied to dry bottom wall-fired and tangentially fired boilers. Based on this comparison, EPA determines whether the NOX control technology applied to the Group 2 boiler category has a cost- effectiveness comparable to that of LNBs applied to Group 1 boilers. Third, EPA estimates the percent change in electricity rates for consumers resulting from costs (in mills per kilowatt-hour) associated with the application of emission limitations on Group 2 boilers. This value is then compared to the percent change in nationwide electricity rates due to the establishment of emission limitations for LNBs on Group 1 boilers. EPA also estimates the emission reductions that are likely to be achieved and considers any other environmental impacts likely to result from application of each NOX control technology. Fourth, EPA assesses the performance (percent NOX reduction) of each cost-comparable Group 2 control technology and applies that reduction percentage to data on the uncontrolled emissions of each boiler that is in the particular category of Group 2 boilers and that will be subject to the Group 2 emission limitation. The emission limitation that will be achievable by 85 to 90% of the boiler population is generally selected, after taking account of energy and environmental impacts, as the emission limitation for that category of Group 2 boiler. EPA concludes that for cell-burner fired boilers, 0.68 lb/mmBtu is a reasonable emission limitation that meets the requirements of section 407(b)(2). For cell burner boilers, plug-in retrofits and non-plug in retrofits are the best continuous control systems that are available and meet the cost comparability requirement. EPA bases the emission limitation on the use of these control technologies and estimates that 80% of the cell burner population can achieve the limitation. The energy impact, i.e., impact of mills/kWh cost on electricity consumers, of using these technologies to meet the emission limitation is small and similar in magnitude to the energy impact of using LNBs on Group 1 boilers. The emission limitation will result in a total NOX emissions reduction of approximately 420,000 tons per year, beginning in 2000, without significant increases in other air pollutants or solid waste. As discussed below, the resulting NOX reductions are a reasonable step toward achieving necessary, significant NOX reductions and are consistent with section 401(b). EPA concludes that for cyclone fired boilers larger than 155 MWe, 0.86 lb/mmBtu is a reasonable emission limitation that meets the requirements of section 407(b)(2). For cyclone fired boilers, gas reburning, and SCR are the best continuous control systems that are available and meet the cost comparability criteria. The energy impact, i.e., impact of mills/kWh cost on electricity consumers, of using these technologies to meet the emission limitation is small and similar in magnitude to the energy impact of using LNBs on Group 1 boilers. EPA bases the emission limitation on the use of these technologies and estimates that 85 to 90% of the cyclone fired boiler population can achieve the emission limitation. The emission limit will result in a total NOX emissions reduction of approximately 225,000 tons per year, beginning in 2000, without significant increases in other air pollutants or solid waste. As discussed below, the resulting NOX reductions are a reasonable step toward achieving necessary, significant NOX reductions and are consistent with section 401(b). EPA has decided not to set a NOX emission limitation for cyclone boilers of 155 MWe or less. EPA concludes that for wet bottom boilers larger than 65 MWe, 0.84 lb/mmBtu is a reasonable emission limitation that meets the requirements of section 407(b)(2). For wet bottom boilers, gas reburning, and SCR are the best continuous control systems that are available and meet the cost comparability requirement. EPA bases the emission limitation on the use of these technologies and estimates that 85 to 90% of the wet bottom boiler population can achieve the emission limitation. The energy impact, i.e., impact of mills/kWh cost on electricity consumers, of using these technologies to meet the emission limitation is small and similar in magnitude to the energy impact of using LNBs on Group 1 boilers. The emission limitation will result in a total NOX emissions reduction of approximately 80,000 tons per year, beginning in 2000, without significant increases in other air pollutants or solid waste. As discussed below, the resulting NOX reductions are a reasonable step toward achieving necessary, significant NOX reductions and are consistent with section 401(b). EPA has decided not to set a NOX emission limitation for wet bottom boilers of 65 MWe or less. EPA concludes that for vertically fired boilers 0.80 lb/mmBtu is a reasonable emission limitation that meets the requirements of section 407(b)(2). For vertically fired boilers, combustion controls are the best continuous control system available and meet the cost comparability requirement. EPA bases the emission limitation on the use of these technologies and estimates that 85 to 90% of the vertically fired boiler population can achieve this emission limitation. The energy impact, i.e., impact of mills/kWh cost on electricity consumers, of using these technologies to meet the emission limitation is small and similar in magnitude to the energy impact of using LNBs on Group 1 boilers. The emission limitation will result in a total NOX emissions reduction of approximately 45,000 tons per year, beginning in 2000, without significant increases in other air pollutants or solid waste. As discussed below, the resulting NOX reductions are a reasonable step toward achieving necessary, significant NOX reductions and are consistent with section 401(b). EPA has decided not to set a NOX emission limitation for arch-fired boilers, a subset of the vertically fired boiler category. Finally, EPA has decided not to set a NOX emission limitation for FBC boilers. Because these units are already low NOX emitters by design, the NOX emissions reduction achieved by installing any additional control technology, would not meet the cost-comparability requirement of section 407(b)(2). Moreover, setting an emission limitation that can be achieved by every existing FBC boiler without installing any additional control technology would have an adverse environmental impact. Some existing boilers emit at rates considerably below the highest annual rate observed among FBC boilers and these boilers could offset the emission reductions otherwise required of other affected boilers through emissions averaging under Sec. 76.10. EPA has also decided not to set a NOX emission limitation for stoker boilers. EPA has not found any continuous control technology for stoker boilers that meets the cost-comparability requirement. 2. Rationale for Revising Group 1 NOX Emission Limits and Environmental Impact of Group 2 NOX Emission Limits EPA is exercising its discretion to revise the Phase II, Group 1 NOX emission limitations because: (1) NOX emissions have significant adverse effects on human health and the environment; (2) significant, additional regional NOX reductions from current levels are likely to be necessary; (3) without additional actions NOX emissions are projected to increase [[Page 67115]] nationwide starting in 2002; (4) the revision of Phase II, Group 1 emission limitations is one of the most cost-effective means of achieving additional NOX reductions; and (5) the additional reductions from the revision represent a reasonable step toward achieving necessary NOX reductions. In addition, the resulting NOX reductions are consistent with section 401(b). The adverse health and environmental effects of NOX emissions are discussed in the proposed rule on Phase II NOX emission limitations. 61 FR 1442, 1453-55, January 19, 1996. EPA reaffirms that discussion, which summarizes the adverse impact of NOX emissions through: The formation of ozone, particulate matter, and nitrogen oxides; and atmospheric deposition resulting in eutrophication of water bodies and acidification of lakes and streams. For the same reasons, EPA also concludes that the adoption of the Group 2 emission limitations set forth in today's rule is supported by the environmental impact of the emission reductions that will result. The contribution of nitrogen oxides to the formation of ozone, acid deposition and eutrophication of water bodies is substantial. Consequently, in order to address these problems, significant NOX emission reductions are likely to be needed on a regional scale, particularly in the eastern half of the U.S. This is the portion of the nation in which most of the boilers subject to NOX emission limitations under the Acid Rain Program are located; 87% of Phase II, Group 1 boilers and 89% of Group 2 boilers covered by today's final rule are in the eastern U.S. i. Ozone With regard to ozone, additional regional NOX reductions of at least 50% from current levels are likely to be needed over large portions of the nation to attain and maintain the national ambient air quality standard for ozone. Modeling results using EPA's Regional Oxidant Model (ROM) estimated that NOX reductions of about 75% will be needed over large portions of the nation to reduce ozone concentrations to levels at or below the NAAQS (see docket item IV-J-8 (EXISTMOD.TXT, OTAG Modeling and Assessment Subgroup Files on EPA's TTN Bulletin Board, February 7, 1996)). The ROM modeling results were among the reasons for the formation of the Ozone Transport Assessment Group (OTAG), comprised of the 37 eastern-most States and tasked with developing a consensus approach for reducing regional NOX emissions. OTAG recently completed atmospheric modeling simulations using SAI's Urban Airshed Model (UAM-V) (see docket item IV-J-21 (OTAG Air Quality Analysis Workgroup, 1996)). The results indicate that: broad NOX emission reductions will decrease regional ozone, high ozone, and ozone in non-attainment areas; and NOX emission reductions in each OTAG sub-region will be needed to both lower ozone in that same sub-region, as well as other sub-regions. Further, necessary NOX reductions to achieve or maintain the ozone standard have been estimated for several other areas of the country: 50-75% from 1990 levels throughout the Northeast Ozone Transport Region (OTR) (60 FR 4712, 4722, January 24, 1995); up to 90% reductions in the Southeast (see docket item II-I-98 (State of the Southern Oxidants Study, 1995)); and a combination of 75% reductions for NOX and 25% for VOCs regionally, combined with 25% for NOX and 75% for VOCs locally in the New York region (60 FR 4721); and significant NOX reductions in the Lake Michigan area, not yet quantified. The results of a study analyzing ozone non-attainment in the eastern U.S. found that nationwide NOX emission reductions of about 50% from 1990 levels will be needed to approach achievement of the necessary ozone standards (see docket item IV-J-9 (Rao, S.T., et.al., Dealing with the Ozone Non-Attainment Problem in the Eastern United States, AWMA journal, January 1996)). ii. Acid Deposition Similarly, additional, regional NOX reductions of at least 40% are likely to be necessary in order to mitigate the effects of acid deposition. In particular, it is estimated that between 40-50% reductions of NOX in the Eastern U.S. beyond those already required in the Clean Air Act may be necessary simply to keep the number of acidified lakes in the Adirondacks in New York at 1984 levels. (See docket item IV-A-6 (Acid Deposition Standard Feasibility Study (EPA 430-R-95-001a) at xvi).) Without additional reductions, the number of acidic lakes in the Adirondacks are projected to increase by almost 40% by 2040. Id. at 47. Significant, additional reductions may also be necessary with regard to the Mid-Appalachian region (see docket item IV-A-6 (Acid Deposition Standard Feasibility Study at xvi)). iii. Eutrophication NOX emissions also contribute significantly to eutrophication, i.e., an overabundance of nitrogen to water bodies that leads to problems of nutrient enrichment. Regional NOX emission reductions of up to 40% are likely to be needed. The signatories to the Chesapeake Bay Agreement, (Maryland, Pennsylvania, Virginia, the District of Columbia, the Chesapeake Bay Commission, and the federal government) have agreed on a goal of a 40% reduction in nitrogen loadings to the Bay by 2000 (relative to a 1985 baseline), representing a reduction of 34 million kilograms of nitrogen (see docket item IV-J-11 (Hicks et al., 1995:6)). In addition, they agreed to maintain, after 2000, a cap on nitrogen loadings at 60% of baseline loadings. Present estimates are that approximately 27% of total nitrogen loading to the Bay system comes from atmospheric sources in the form of NOX emissions (see docket items IV-J-26 (Linker et al., 1993) and IV-J-19 (Valigura et al., 1995)). Since reducing nitrogen loading through the control of NOX emissions can be as cost-effective as controlling non- atmospheric sources of nitrogen loading (e.g., point sources such as waste water treatment and non-point sources such as farms), up to a 40% reduction of the contribution in NOX emissions to the Bay in areas contributing to the eutrophication of the Bay is likely to be necessary. Although the watershed of the Chesapeake Bay encompasses approximately 64,000 square miles, the Chesapeake Bay ``airshed,'' which is the contiguous area providing 70% of the atmospheric deposition loads to the watershed (see docket item IV-J-18 (Dennis, 1996)), covers up to 600,000 square miles in area (see docket item IV- J-3 (Valigura et al., 1996:23)). The airshed extends upwind of, as well as bordering the water body itself: south to South Carolina, north to Ontario, Canada, and westward up to 500 miles (see docket item IV-J-11 (Hicks et al., 1995:6)). NOX emissions from outside this area not only contribute to eutrophication in the Bay but also to the entire coastline, such as from the Carolinas to New York (see docket item IV- J-3 (Valigura et al., 1996:23)). iv. Utility Contribution to Atmospheric NOX Emissions Electric utilities contributed approximately 33% of total atmospheric NOX emissions in 1994, thus substantially contributing to ozone formation, acid deposition, and eutrophication. Table 1 summarizes the reductions in atmospheric NOX emissions likely needed and the additional reductions provided by today's final rule. Although the additional reductions from coal-fired utility boilers under the final rule are substantial, they represent only [[Page 67116]] about 5% of all atmospheric NOX emissions from all sources of NOX emissions. The additional reductions under the final rule represent about a 15% reduction in total utility emissions. Since utilities presently contribute about 33% of total NOX emissions, the final rule provides reductions of about 5% of total NOX emissions. This reduction level is significantly less than the reduction level likely to be needed to mitigate ozone, acid deposition, and eutrophication (see docket item IV-A-8 (EPA, ``National Air Pollution Emission Trends, 1900-1994'' at 2-2, October, 1995, EPA-454/ R-95-011)). Table 1.--Estimated Regional Reductions Necessary to Mitigate Various Environmental Effects ---------------------------------------------------------------------------------------------------------------- Environmental effect ----------------------------------------------------------------------------------------------------------------- Ozone Acid deposition Eutrophication ---------------------------------------------------------------------------------------------------------------- Regional NOX Reductions Necessary.... More than 50%.......... More than 40%.......... Up to 40% NOX Reductions Achieved from the 5%..................... 5%..................... 5% Final Rule as Percentage of Total NOX Emissions. ---------------------------------------------------------------------------------------------------------------- v. NOX Reductions Not Sustained Although national NOX emissions are expected to decrease up to the year 2000, (see docket item IV-A-8 (EPA, ``National Air Pollution Emission Trends, 1900-1994'' at 5-5, October, 1995, EPA-454/R-95-011)), emissions are projected to begin increasing after 2000 (id. at 5-2 and 6-8 2). The existing NOX control programs under the Clean Air Act (including the Mobile Source Program under title II and the Acid Rain NOX Program under title IV) limit NOX emission rates (e.g., the pounds of NOX emissions per amount of fuel consumed (under title IV)) for emission sources. The programs do not cap the total tonnage of nationwide emissions. As the number of emission sources and the use of emission sources increases, reductions due to emission rate limitations are offset to an increasing extent. For this reason, after 2002, when implementation of these NOX control programs is largely completed and growth in sources and source use continues, NOX emissions will gradually increase for the foreseeable future (id. at 5-5). Section 401(b) of the Act suggested, as a guideline, that NOX emissions should be reduced nationwide by 2 million tons from the 1980 level. By about 2006, total NOX emissions will surpass that guideline unless additional efforts are made (e.g., under title IV) to reduce NOX emissions (See figure 1, below). The projected increase in total NOX emissions is well within the time frame considered by Congress in title IV. EPA notes that the nationwide annual cap for SO2 emissions, also established under section 402, begins to apply in the year 2010. Until 2010, total annual allocated SO2 allowances will exceed the cap, because of additional allowances allocated under section 409 for repowered units and bonus allowances under section 405. Additional NOX reductions, such as these under today's final rule, are necessary both in light of the likely need to reduce NOX to address ozone, acid deposition, and eutrophication, and in light of the NOX reduction guideline in section 401(b) of the Act. In short, new initiatives are needed to reduce NOX emissions on a regional scale in order to improve environmental quality and health beyond 2000. \2\ Report's projections take into account requirements for Reasonably Available Control Technologies (RACT) under title I, enhanced programs for inspection and maintenance of mobile sources under title I, and title IV Group 1 emission limits promulgated April 13, 1995 (id. at 6-8, (assuming, for analytical purposes, that title IV emission limits are set at RACT)). --------------------------------------------------------------------------- BILLING CODE 6560-50-P [[Page 67117]] [GRAPHIC] [TIFF OMITTED] TR19DE96.000 BILLING CODE 6560-50-C vi. Cost-Effectiveness The revision of Phase II, Group 1 emission limitations and establishment of Group 2 emission limitations is a cost-effective means of achieving the likely necessary, additional regional NOX reductions. The control technologies on which the revised Group 1 limits and the Group 2 limits are based are more cost-effective (i.e., have a lower cost per ton of NOX removed) when applied to the respective Group 1 and Group 2 boiler types than most other control technologies applied to these boiler types or to non-utility sources. As shown below, the dollar cost per ton of NOX removed for reductions under the final rule is less than, or at the lower end of, the range of dollar cost per ton of NOX removed for most alternative reductions. In short, the NOX reductions achievable under this final rule are among the less expensive that can be made. [[Page 67118]] Utility Sources: For coal-fired utility boilers using higher level control technologies, (e.g., SCR with higher NOX reduction capability) than the technologies on which the title IV limits are based, the average cost-effectiveness for typical wall-fired boilers ranges from $1,226/ton to $1,670/ton with percent reductions ranging from 60-90%. For typical tangentially fired boilers, the cost- effectiveness ranges from $1,439/ton to $1,935/ton with percent reductions ranging from 60-90%. For typical cyclone boilers, the cost- effectiveness ranges from $440/ton to $880/ton with percent reductions ranging from 60-90%. For typical cell-burner boilers, the cost- effectiveness ranges from $624/ton to $801/ton with percent reductions ranging from 60-80%. For typical wet bottom boilers, the cost- effectiveness ranges from $572/ton to $733/ton with percent reductions ranging from 60-90%. For typical roof-fired (vertically-fired) boilers, the cost-effectiveness ranges from $750/ton to $907/ton with percent reductions ranging from 60 to 90%. For typical oil and gas utility boilers, the average cost-effectiveness for wall-fired dual-fired boilers under various NOX reduction technologies ranges from $748/ ton to $2,263/ton with percent reductions ranging from 40-90%. For typical tangentially fired dual-fired boilers, the cost-effectiveness ranges from $507/ton to $1,573/ton with percent reductions ranging from 30-90% (see docket item IV-J-4 (Ozone Transport Assessment Group, Control Technologies and Options Workgroup, Final Report, April 11, 1996)). As compared to the cost-effectiveness ranges for higher level control technologies applied to typical utility boilers, the average cost-effectiveness for meeting the Group 1 and Group 2 emission limits under today's final rule, using the control technologies on which the limits are based, is approximately $229/ton of NOX removed. Non-Utility Point Sources: Non-utility point sources NOX reductions are less cost effective, on average, than NOX reductions under today's final rule. For example, the average cost- effectiveness for process heaters ranges from $290-50,000/ton at an average reduction of 5-90%. For cement manufacturing, the average cost- effectiveness ranges from $470-4,870/ton at an average reduction of 20- 90%. For wood manufacturing, the average cost-effectiveness ranges from $1,000 to over $10,000/ton at an average reduction of 0-60% (see docket item IV-J-4 (Ozone Transport Assessment Group, Control Technologies and Options Workgroup, Final Report, April 11, 1996)). Mobile Sources: For mobile sources, the cost-effectiveness under various NOX control options is also high, on average, as compared to reductions under today's final rule. For example, the average cost- effectiveness for light-duty on highway vehicles ranges from $1,100- $260,000/ton, with percent reductions ranging from 0.2-21%. For heavy- duty on highway vehicles, the average cost-effectiveness ranges from $1,000/ton to $40,000/ton, with percent reductions ranging from 0.02- 5.6%. For non-road sources, the average cost-effectiveness ranges from $119/ton to $23,000/ton, with percent reductions ranging from 0.4-3.4% (see docket item IV-J-6 (Mobile Sources Assessment: NOX and VOC Reduction Technologies for Application by the Ozone Transport Assessment Group, Final Report, March 4, 1996)). Table 2 summarizes the cost-effectiveness ranges of NOX controls for the three major NOX emitting sources, as compared to the cost-effectiveness of reductions under the revised Group 1 limits and Group 2 limits. Other: The reductions from applying control technologies to coal- fired power plants under today's final rule can be as cost-effective to achieve as reductions from other point sources (e.g., wastewater plants) and area sources (e.g., farms, animal pastures). Studies concerning eutrophication in the Chesapeake Bay estimate the following average cost-effectiveness of control technologies applied to non- utility sources: chemical addition or biological removal of nitrogen from wastewater processing, $4,000 to over $20,000/ton of nitrogen removed; and management practices to reduce nitrogen from fertilizers, animal waste, and other non-point sources, $1,000 to over $100,000/ton of nitrogen removed (see docket items IV-J-25 (Camacho, 1993:97-98) and IV-J-27 (Shulyer, 1995:6)). Table 2.--Average Cost-Effective of NOX Controls by Source [Utility, other point source, mobile] ------------------------------------------------------------------------ Range in typical cost- Percent effectiveness ($/ reduction ton) ------------------------------------------------------------------------ Utility sources (Coal w/advanced NOX controls): Wall-fired........................... $1,226-1,670 60-90 Tangentially-fired................... 1,439-1,935 60-90 Cyclones............................. 440-880 60-90 Cell burners......................... 624-801 60-80 Wet bottoms.......................... 572-733 60-90 Roof (vertically-fired).............. 750-907 60-90 Utility sources (Oil and Gas): Wall dual-fired...................... 748-2,263 40-90 Tangential dual-fired................ 507-1,573 30-90 ------------------------------------------------------------------------ Source: Ozone Transport Assessment Group, Control Technologies and Options Workgroup, Final Report, April 11, 1996. ------------------------------------------------------------------------ Average cost- effectiveness Percent Title IV phase II NOX rule of Sec. reduction 407(b)(2) ($/ under Sec. ton) 407(b)(2) ------------------------------------------------------------------------ Group 1 and group 2..................... $229 20 ------------------------------------------------------------------------ See section IV.B (Table 17) of this preamble. [[Page 67119]] ------------------------------------------------------------------------ Range in typical cost- Percent Non-utility point sources effectiveness ($/ reduction ton) ------------------------------------------------------------------------ Non-utility boilers...................... $490-19,600 5-90 Process heaters.......................... 290-50,000 20-90 I.C. engines............................. 180-13,400 5-98 Gas turbines............................. 130-2,760 60-90 Residential fuel combustion.............. 1,600-62,500 50-100 Cement manufacturing..................... 470-4,870 20-90 Metals processing........................ 120-11,600 12-96 Wood manufacturing....................... 1,000-10,000+ 0-60 Agriculture chemical manufacturing....... 76-715 44-99 Incineration............................. 800-10,000 10-77 ------------------------------------------------------------------------ Source: Ozone Transport Assessment Group, Control Technologies and Options Workgroup, Final Report, April 11, 1996. ------------------------------------------------------------------------ Range in typical cost- Percent Mobile sources effectiveness ($/ reduction ton) ------------------------------------------------------------------------ Light-duty (on highway).................. $1,100-260,000 0.2-21 Heavy-duty (on highway).................. 1,000-40,000 0.02-5.6 Non-road................................. 119-23,000 0.4-3.4 ------------------------------------------------------------------------ Source: Mobile Sources Assessment: NOX and VOC Reduction Technologies for Application by the Ozone Transport Assessment Group, Final Report, March 4, 1996. ------------------------------------------------------------------------ Average cost- effectiveness Percent Title IV phase II NOX rule of Sec. reduction 407(b)(2) ($/ under Sec. ton) 407(b)(2) ------------------------------------------------------------------------ Group 1 and Group 2..................... $229 20 ------------------------------------------------------------------------ vii. Need to Revise Group 1 Limits and Establish Group 2 Limits As discussed above, in order to mitigate adverse effects on health and the environment due to NOX emissions, significant, additional reductions in regional atmospheric NOX emissions from current levels are likely to be necessary. Further, the contribution of the final rule toward the overall NOX reduction goal is approximately 5%. The NOX reductions under the rule represent only a portion of the much larger NOX reductions likely to be needed and are among the most cost-effective reductions available. EPA concludes that the reductions under the final rule represent a reasonable step toward achieving necessary NOX reductions. Some commenters suggested that, because the authority to revise the Phase II, Group 1 emission limitations and to issue Group 2 emission limitations arises under title IV of the Clean Air Act, EPA must consider only the acidification impacts of NOX emissions in deciding whether to revise or issue limitations. Allegedly, all other impacts must be addressed only under other provisions of the Act. EPA rejects this crabbed view of its authority under section 407(b)(2) as having no basis in statutory language or logic. In granting EPA the authority to decide to revise the Phase II, Group 1 emission limitations, section 407(b)(2) only requires a determination of the availability of more effective LNB technology and does not bar consideration of non-acidic deposition impacts. Similarly, in requiring EPA to issue Group 2 emission limitations, section 407(b)(2) sets forth several criteria for setting the limitations but none of the criteria bars consideration of non-acidic deposition impacts. On the contrary, section 407(b)(2) has a general requirement that EPA take account of ``environmental impacts'' in setting Group 2 emission limitations. 42 U.S.C. 7651f(b)(2). In the absence of a statutory bar on considering all environmental impacts of NOX emissions and in light of the general purpose of the Clean Air Act to, inter alia, ``protect and enhance the quality of the Nation's air resources so as to promote the public health and welfare and the productive capacity of its population'', it would be illogical for EPA to focus exclusively on acid deposition.3 42 U.S.C. 7401(b)(1). The latter approach would require EPA to regulate on a piecemeal basis and to blindly ignore a major part of the harmful effects of NOX emissions when setting nationwide NOX emission limits under title IV. In any event, EPA maintains that, even if the Agency were confined to considering only the acidic deposition effects, referred to above, of NOX emissions, it would still conclude that additional NOX reductions are necessary and that the emission limitations set forth in today's rule should be adopted. --------------------------------------------------------------------------- \3\ Although, as discussed below, section 401(b) states that the general purpose of title IV is ``to reduce the adverse effects of acid deposition'', this provision should not be interpreted as barring consideration of other environmental impacts for purposes of setting emission limitations under section 407. 42 U.S.C. 7651(b). EPA's interpretation--which harmonizes sections 101(b)(1) (stating the general purposes of the Clean Air Act) and 401(b) (stating the general purposes of title IV)--is that, while the primary focus in promulgating regulations under title IV is reduction of acidic deposition, other environmental impacts may also be considered. --------------------------------------------------------------------------- Some commenters also noted that section 401(b) states that the purpose of title IV is to reduce acidic deposition through reduction of annual SO2 emissions of ten million tons from 1980 levels ``and, in combination with other provisions of this Act, of nitrogen oxides emissions of approximately two million tons from 1980 emission levels, in the forty-eight contiguous States and the District of Columbia.'' 42 U.S.C. 7651(b). According to such commenters, because this goal is already met by the existing Phase II, Group 1 emission limitations (as well as by regulations under other parts of the Clean Air Act), there is no basis for revising the limitations. However, section 401(b) provides only general guidance concerning implementation of title IV and, in light of the imprecision of its language, does not--and was not intended to--impose an absolute limit on the amount of NOX reductions that can be required under emission limitations promulgated under section 407. In contrast to the SO2 provisions of title IV, which set a nationwide cap on total tonnage of SO2 emissions (i.e., 8.95 million tons starting in 2010), the NOX provisions of title IV provide only for limits on the NOX emitted per mmBtu of fuel burned. Even if the NOX emission limitations are met, increased use of existing coal-fired and other [[Page 67120]] utility boilers in the future in response to growth in demand for electricity can result in increased tonnage of NOX emissions. The NOX emissions reductions projected to be achieved through adoption of any given set of NOX emission limitations under title IV are therefore not permanent. For this reason, when EPA estimates NOX reductions resulting from title IV emission limitations, the estimates are tied to a specific year, in this case the year 2000. Regulatory Impact Analysis of NOX Regulations at 1-7 and 1-8, December 8, 1995. Moreover, as discussed above, total NOX emissions are projected to decline through 2000, increase thereafter, and exceed the two million guideline by around 2006. In short, the commenters' claim that a two-million-ton emission reduction ``goal'' is ``satisfied'' by the existing Group 1 emission limitations is inaccurate because a two- million-ton level of reductions from 1980 achieved for a given year (e.g., for 2000) through these limitations is unlikely to be maintained, in the near future without further reductions. Although EPA maintains that the 2 million ton guideline in Section 401(b) aims at total NOX emissions of 2 million tons below the 1980 levels, EPA notes that the final rule will result in total Group 1 and Group 2 boiler NOX emissions around 2 million tons less than what they otherwise would have been in 2000. The annual NOX reductions anticipated from the existing Group 1 emission limitations under the April 13, 1995 rule and additional annual reductions anticipated from the Phase II, Group 1 and Group 2 emission limitations under today's final rule are about 1,170,000 tons and 890,000 tons respectively for the year 2000, for a total of about 2,060,000 tons. EPA's current estimate of reductions from the April 13, 1995 rule is lower than the reductions originally estimated (i.e., about 1,890,000 tons for the year 2000) for that rule. 59 FR 13538, 13562-63 (March 22, 1994); see also 59 FR 18760 (adopting for April 13, 1995 rule the Regulatory Impact Analysis originally promulgated for the March 22, 1994 rule). In making the original estimates of reductions, EPA used emissions factors (i.e., estimated uncontrolled emission rates based on coal type and boiler type) to determine the uncontrolled emissions of boilers to which the existing Group 1 emission limitations were to be applied. In response to comment in today's rulemaking concerning the inaccuracy of emission factors, EPA has minimized its use of emission factors and instead relied almost exclusively on actual, short-term, uncontrolled emissions data from continuous emissions monitoring obtained during annual monitor certification testing (i.e., CREV data) or submissions of CEM, EPA reference method, or other test data by utilities. This data was not generally available to EPA when the April 13, 1995 rule was published.4 As a result of using more accurate uncontrolled emissions data, EPA's estimates of anticipated reductions under the existing Group 1 emission limitations are now more accurate and are lower. Even if section 401(b) were viewed as imposing a ``ceiling'' of ``approximately two million tons'' of NOX reductions under section 407, the reductions anticipated under the emission limitations adopted in the April 13, 1995 rule and today's final rule are consistent with that ``ceiling.'' --------------------------------------------------------------------------- \4\ For the January 19, 1996 proposal in the instant rulemaking, EPA replaced many, but not all, of the emissions factors with actual data, which resulted in estimated annual reductions under the current Group 1 emission limitations of about 1,540,000 million tons. See Regulatory Impact Analysis for the proposed rule (docket item II-F-2). --------------------------------------------------------------------------- For the reasons discussed above, EPA concludes that it should exercise its discretion under section 407(b)(2) to revise the Phase II, Group 1 emission limitations. The revised Group 1 limits represent a reasonable step toward achieving the significant NOX reductions that are likely to be necessary, and are consistent with the 2 million ton guideline for NOX reductions. The revision of the Group 1 emission limitations will result in about 120,000 tons of additional annual NOX reductions. Actions to achieve NOX reductions beyond those realized under title IV are being considered, or will be considered in the future, under other titles of the Clean Air Act. Unlike the Group 1 limitation revisions, which are discretionary under section 407(b)(2), the issuance of Group 2 emission limitations is mandatory under that section so long as the requirements of the section (e.g., cost comparability) are met. However, as noted above, EPA is required, when setting Group 2 emission limitations under section 407(b)(2), to consider environmental impacts. EPA's application of the section 407(b)(2) requirements for setting Group 2 emission limitations--including the consideration of environmental impacts--is set forth in detail below in section III.B of this preamble. EPA concludes that, like the Group 1 revisions, the Group 2 emission limitations supported and adopted in that section of the preamble represent a reasonable step toward achievement of necessary, significant NOX reductions and are consistent with the 2 million ton guideline for NOX reductions. II. Public Participation Regulations were proposed in the Federal Register on January 19, 1996 (61 FR 1442). The notice invited public comments and copies of the proposed rule were made available to interested parties. EPA held a public hearing to provide interested parties the opportunity for oral presentation of data, views, or arguments concerning the proposed regulations. The hearing was held on February 8, 1996 in Washington, DC. Four persons testified at the hearing concerning issues related to the proposed regulations. The hearing was open to the public, and each attendee was given an opportunity to comment on the proposed regulations. (See docket items IV-F-1, IV-F-2 and IV-F-3.) The initial public comment period (January 19, 1996 to March 4, 1996) was extended by two weeks to March 19, 1996 to allow additional time for inspection of interagency review materials which EPA added to the docket on January 26, 1996. (See docket item III-A-2.) III. Summary of Major Comments and Responses EPA received approximately 100 comment letters regarding the proposed regulations, presenting more than 200 issues. Commenters included public and municipal utilities, utility associations, state/ local agencies and Attorneys General, environmental organizations, vendors, general industry, research/trade groups, and private citizens. A copy of each comment letter received is included in the rulemaking docket. A list of commenters, their affiliations, and the EPA docket item number assigned to their correspondence is included in the background information document. All of the comments have been carefully considered, and where determined to be appropriate by the Administrator, changes have been made in the final regulations. The background information document includes a summary of all the comments and EPA's response on each of the relevant issues. The following sections of the preamble provide a summary of the major comments received and the Agency's response to those major comments. [[Page 67121]] A. Phase II, Group 1 Boiler NOX Emission Limits 1. Boiler Population Used To Assess NOX Emission Limits Background. For the proposed rule, EPA developed a computerized boiler database containing detailed information on the characteristics and pre-retrofit and post-retrofit emission rates of coal-fired units with Group 1 boilers on which low NOX burners (LNBs) had been installed without any other NOX controls (``the LNB Application Database''). This database contained all known applications of LNBs to Group 1 boilers that were installed subsequent to 11/15/90 (the date of enactment of the 1990 amendments to the CAA) and for which EPA had at least 52 days of quality assured post-retrofit data measured by continuous emission monitors (CEMs) certified according to 40 CFR part 75. The 24 wall-fired boilers and 9 tangentially fired boilers in this database formed the empirical basis for EPA's assessment of the effectiveness of low NOX burner technology and the revised annual NOX emission limitations provisions for Group 1 boilers in the proposed rule. Comment/Analyses: EPA received approximately 25 comment letters (from 19 utilities, 3 utility associations, 2 states, and an environmental organization) on the appropriateness of including or excluding certain boilers and the selection criteria used to define eligibility for the LNB Application Database. Several commenters suggested that EPA include specific boilers to increase the size and improve the representativeness of the tangentially fired subset in the LNB Application Database: Riverbend 7 and 8, Allen 1 and 3, J.H. Campbell 3, Gallatin 4, and Lansing Smith 2 (see, for example, docket items IV-D-22, p. 1; IV-D-21, pp. 2-3; IV-D- 20, pp. 7-9, and IV-D-65, p. 22). The commenters acknowledged that many of these retrofit cases did not satisfy the quality assurance criteria that EPA had established for inclusion in the LNB Application Database. They believed, however, that the general benefits of broadening the experiential basis for tangentially fired boilers outweighed specific data quality concerns. As one commenter said, ``Although not [based on] CEM data, Gallatin Unit 4's performance test result of 0.47 lb/10 6 Btu is reliable, relevant evidence * * * and should be considered by EPA.'' (See docket item IV-D-20, p. 9.) Commenters also suggested that EPA include specific boilers to improve the representativeness of the wall-fired subset in the LNB Application Database, particularly with respect to boilers with high uncontrolled emission rates: Hammond 4, Watson 4 and 5, Valley 1 and 2 (see, for example, docket items IV-D-65, p.22). Several commenters cited additional wall-fired retrofit cases within the context of the related issue of the dependence of NOX emissions on boiler load: Conesville 3, Picway 9, Amos 1 and 2, Big Sandy 2, Glen Lyn 6, Colbert 5, Valley 1-4; Presque Isle 5 and 6 (see docket items IV-D-73, p.1; IV- D-20, p.5; IV-D-26, p.2). On the other hand, several commenters fully endorsed the quality assurance criteria EPA has used to determine eligibility for the LNB Application Database (see, for example, docket items IV-D-063, p.12; IV-D-046, p.3-4). They said that EPA properly excluded older LNB installations (such as Gallatin 4, Lansing Smith 2, and Hammond 4) for which quality assured long-term post-retrofit CEM data did not exist. (EPA notes that this criterion generally excludes experimental or otherwise short-lived LNB installations such as those used for technology demonstrations, and the Allen units.5) These commenters also recommended that EPA should attach greater significance to (or rely exclusively on) LNB applications in the 13-state Northeast Ozone Transport Region (OTR) for the evaluation of LNB technology effectiveness because these applications have been required to meet a NOX emission limit beginning May 31, 1995, whereas most other applications have not had to comply with a recently established NOX standard. --------------------------------------------------------------------------- \5\ The Allen plant is located in Gaston County, NC, which, until July 1995, was considered in non-attainment for ozone. The utility installed LNBs on two Allen boilers, the vendor is reported to have optimized in mid 1995. In July 1995, Gaston County was redesignated to ozone attainment and low NOX operation was discontinued on Allen 1 and 3 on September 1, 1995 (see docket item IV-D-22, p. 1). As a result, Allen units 1 and 3 each have less than 52 days of emissions data after optimization of their respective LNBs. --------------------------------------------------------------------------- Some commenters correctly noted that one wall-fired boiler in the LNB Application Database used for the proposed rule analysis, North Valmy 1, should be excluded because this boiler had pre-existing NOX controls (i.e., Babcock and Wilcox (B&W) DRB version LNBs) so its baseline measurement does not represent an uncontrolled emission rate. EPA notes that this NSPS boiler, when retrofitted with modern LNBs (i.e., B&W XCL version), has sustained an average post-retrofit controlled emission rate of 0.264 for calendar year 1995 (see docket item II-A-9). ``NSPS boilers'' are new coal-fired utility units on which construction commenced after August 17, 1971, which are subject to New Source Performance Standards (NSPS) (40 CFR part 60, subparts D or Da). Some NSPS boilers had early versions of LNBs and/or some other type of NOX combustion control installed as original equipment. EPA has excluded these ``controlled NSPS boilers'' from the LNB Application Database and regression models because their measured baseline emission rates do not generally represent uncontrolled emissions. EPA has included all NSPS boilers, both controlled and those without built-in NOX combustion control equipment, in the Phase II, Group 1 boiler set to which the models are applied since NSPS boilers represent approximately one third of the units affected by this rulemaking. One commenter recommended that EPA exclude two boilers, Coleman C1 and Pulliam 7, because, according to this commenter, these boilers have low NOX combustion controls beyond the LNB definition in 40 CFR 76.2. EPA disagrees with this commenter's opinion that these two retrofits include auxiliary combustion air outside the waterwall hole which are `` `staging' combustion on active burners analogous to overfire air'' (see docket item IV-D-51, p. 9). EPA also notes that another commenter, who represents 67 utilities, included both units in their regression analyses on the performance of LNBs applied to wall- fired Group 1 boilers (see docket item IV-D-65, p. 58 and Enclosure 8, Table 4-1). DOE included Coleman C1 in its regression analyses, but excluded Pulliam 8 (probably because, as EPA learned after the rule proposal, the utility switched to Powder River Basin coal for both Pulliam 7 and 8) (see docket item II-D-62). Some commenters recommended that EPA include Group 1 boilers that installed both LNB and overfire air (OFA) in the LNB Application Database, primarily because they believe units with high uncontrolled emission rates were under-represented in the proposed rule analysis (see, for example, docket item IV-D-58, p. 4). These commenters provided supporting data for certain boilers, including: Eastlake 1, 3, and 4; and Ashtabula 7 (see docket item IV-D-23, p. 5). As discussed later in this section of the preamble, EPA disagrees with this recommendation. First, OFA cannot be considered in determining whether to revise the Group 1 limits and the assessment of the achievable performance of LNBs alone is problematic when LNBs are used in combination with other technologies. Further, the addition of 20 units to the LNB Application Database has [[Page 67122]] significantly improved the robustness of EPA's regression models for units with high uncontrolled emission rates. Several commenters agreed with EPA's decision to exclude boilers using Powder River Basin or other subbituminous coal from the LNB Application Database (see, for example, docket items IV-D-15, p. 3; IV- D-65, p. 20). For such boilers, measured post-retrofit NOX emission reductions reflect the combined effects of switching to a coal with inherently lower NOX emissions plus the application of LNBs. Response: In light of the comments requesting the inclusion and/or exclusion of specific boilers from the LNB Application Database, EPA has formalized and expanded the data quality assurance criteria used in the rule proposal into Data Quality Objectives (DQOs). The DQOs are rigorous and precisely defined rule tables which were used to screen all candidate boiler retrofit cases and hourly CEM data observations. The DQOs are designed to ensure that the LNB Application Database satisfies objective and consistent data quality assurance standards. Table 3 presents EPA's DQOs for evaluating candidate boiler retrofit cases (DQOs Applied to Boilers) and for quality assuring hourly post- retrofit CEM data (DQOs Applied to Data). Table 3.--Data Quality Objectives Applied to Boilers and Data to Screen Boilers for Inclusion in the LNB Application Database ---------------------------------------------------------------------------------------------------------------- DQO# DQOs applied to boilers Rationale ---------------------------------------------------------------------------------------------------------------- 1B Only dry bottom wall-fired and tangentially NOX emission rates for Group 1 boilers affect fired boilers will be included in the dry bottom wall-fired and tangentially fired database. boilers only. 2B Boilers must have an installed LNB control Consistent with Alabama Power v. EPA, 40 F.3d technology only. Boilers with LNB plus 450 (D.C. Cir. 1994), EPA cannot consider overfire air (OFA) or other controls will LNB+OFA installations when setting Group 1 not be included in the database. This limits. determination is made by either (1) information in EPA's Program Tracking System Database or (2) direct contact with individual utilities. 3B Any boiler with an LNB installation date Revised Group 1 limits are to be based on prior to November 15, 1990 will not be improved performance of LNBs installed after included in the database. LNB installation passage of 1990 Clean Air Act Amendments dates are determined from (1) EPA's Program (CAAA). Tracking System Database, (2) estimation of the dates from visual interpretation of hourly emissions plots, or (3) direct contact with the utilities. 4B Only boilers with at least 52 days of post- 52 days is generally accepted as the minimum retrofit data, following an equipment time period for assessing long-term ``break-in'' period of 30 calendar days, performance of NOX combustion control will be included in the database. technology (see preamble section III.A.2.ii). Vendors and utilities acknowledge existence of ``break-in'' period, lasting about 30 calendar days, during which boiler operations are often highly irregular. 5B Boilers for which LNB design, installation Boilers with serious and persistent LNB and/or operations are known to be seriously design, installation, and operational flaws flawed will be excluded from the database. do not reflect the true NOX emission This determination will be made on the basis reduction associated with LNB retrofit. of published utility papers or information (This DQO is a logical extension of a submitted to EPA for a rulemaking docket. pertinent statutory concept. Section 407(d) (This DQO, however, was never used as the requires selection of appropriate control sole basis for rejecting any candidate equipment ``designed to meet the applicable boiler retrofit cases from current emission rate'' as well as proper database.). installation and operation of such equipment for determining eligibility, and an appropriate emission rate, for an alternative emission limitation). 6B Boilers must have a pre-retrofit uncontrolled Quality assured short-term uncontrolled emission rate based on quality assured short- emission rate data are needed to perform term CEM or test data that is verifiable in consistent analysis and projections using the CREV database, the Acid Rain Cost Form first and second parts of model (see for NOX Control Costs, or another source preamble, section III.A.3.ii.). available to EPA. 7B Quarterly report submissions for boilers must Quarterly report submissions that do not pass the quality assurance (QA) criteria in satisfy the CEM and other QA criteria in 40 40 CFR part 75. CFR part 75 contain insufficient information to verify the accuracy of reported NOX emission rate data. 8B NSPS boilers are excluded from the database.. Pre-NSPS boilers differ from NSPS boilers with regard to furnace volume and heat release rates and, as a result, NSPS units can more easily meet a NOX reduction target by retrofitting LNBs. This makes NSPS units unrepresentative for establishing overall LNB NOX reduction efficiency. 9B Only boilers not using Powder River Basin Powder River Basin coal has been identified coal will be included in the database. by utilities as a subbituminous coal which produces very low NOX emission rates. Its performance cannot necessarily be reproduced by any other type of coal for LNB applications. ---------------------------------------------------------------------------------------------------------------- DQO# DQOs applied to data Rationale ---------------------------------------------------------------------------------------------------------------- 1D Data generated using EPA's missing data The missing data routines include a penalty substitution procedures will not be used (40 for not properly maintaining CEM equipment. CFR part 75). In order to assess actual LNB performance, only measured NOX emission rate data will be used. 2D Hourly emission rate data will be adjusted Using bias adjusted NOX emission rates will using the appropriate bias adjustment factor ensure compatibility of CEM NOX emission for the boiler. rate measurements obtained from different monitors. [[Page 67123]] 3D NOX emission rates greater than 10 lb/mmBtu Such reported data values are clearly and less than or equal to 0 lb/mmBtu will be erroneous (i.e., physically impossible) and, discarded. thus, should not be included when estimating achievable emission rates. 4D Hourly emission rate data for ``break-in'' Vendors and utilities acknowledge existence period, defined as the 30 calendar days of ``break-in'' period, lasting about 30 following estimated date the boiler began calendar days, during which boiler operating after shutdown for LNB retrofit operations are atypical due to vendor (denoted on tables as ``LNB retrofit performance guarantee testing. Discarding date''), will be discarded. hourly emissions data for ``break-in'' period also allows for any uncertainty associated with exact date of beginning of post-retrofit period. ---------------------------------------------------------------------------------------------------------------- EPA applied these DQOs to candidate boilers: those used in the Phase II proposed rule analysis (Tables 2 and 3, 61 FR 1442, 1446-1447, January 19, 1996); those that commenters requested EPA to consider (many of which are named above); and additional LNB boiler applications which EPA identified using 1995 and first and second quarter, 1996 CEM data submitted pursuant to 40 CFR part 75 and other program information. A detailed presentation of the results of EPA's comprehensive data evaluation appears in docket item IV-A-6. The resulting LNB Application Database, presented in Tables 4 and 5, consists of 39 wall-fired boilers and 14 tangentially fired boilers and contains over 477,800 hours of quality assured post-retrofit CEM data on LNB performance. Table 4.--Wall-fired Boilers in the LNB Application Database ---------------------------------------------------------------------------------------------------------------- Load weighted Uncontrolled post- Obs. No. ORISPL Unit name/unit ID Phase NoX rate (ln/ optimization Percent NoX mmBtu) NoX rate (ln/ removal mmBtu) ---------------------------------------------------------------------------------------------------------------- 1. 26 Gaston unit 1..... 1 0.900 0.384 57.3 2. 26 Gaston unit 2..... 1 0.780 0.384 50.8 3. 26 Gaston unit 3..... 1 0.800 0.413 48.4 4. 26 Gaston unit 4..... 1 0.800 0.413 48.4 5. 47 Colbert unit 1.... 1 0.800 0.421 47.4 6. 47 Colbert unit 2.... 1 0.670 0.421 37.2 7. 47 Colbert unit 3.... 1 0.830 0.421 49.3 8. 47 Colbert unit 4.... 1 0.860 0.421 51.0 9. 47 Colbert unit 5.... 1 0.780 0.434 44.4 10. 641 Crist unit 6...... 1 1.040 0.492 52.7 11. 641 Crist unit 7...... 1 1.160 0.517 55.4 12. 856 Edwards unit 2.... 2 1.000 0.514 48.6 13. 1043 Ratts unit 1SG1... 1 1.080 0.508 53.0 14. 1043 Ratts unit 2SG1... 1 1.090 0.468 57.1 15. 1295 Quindaro unit 2... 1 0.635 0.405 36.2 16. 1355 Brown unit 1...... 1 1.000 0.495 50.5 17. 1357 Green River unit 5 1 0.836 0.400 52.2 18. 1381 Coleman unit 1.... 1 1.410 0.489 65.3 19. 1381 Coleman unit 2.... 1 1.290 0.466 63.9 20. 1384 Cooper unit 1..... 1 0.900 0.419 53.4 21. 1384 Cooper unit 2..... 1 0.900 0.419 53.4 22. 2049 Watson unit 4..... 1 1.100 0.413 62.5 23. 2049 Watson unit 5..... 1 1.220 0.431 64.7 24. 2629 Lovett unit 4..... 2 0.570 0.349 38.8 25. 2629 Lovett unit 5..... 2 0.585 0.329 43.8 26. 2840 Conesville unit 3. 1 0.852 0.412 51.6 27. 2843 Picway unit 9..... 1 0.866 0.415 52.1 28. 3131 Shawville unit 1.. 1 0.990 0.486 50.9 29. 3131 Shawville unit 2.. 1 1.020 0.483 52.6 30. 3159 Cromby unit 1..... 2 0.600 0.378 37.0 31. 3178 Armstrong unit 2.. 1 1.042 0.420 59.7 32. 3948 Mitchell unit 1... 1 0.999 0.500 50.0 33. 3948 Mitchell unit 2... 1 0.999 0.500 50.0 34. 4042 Valley unit 1..... 1 1.100 0.477 56.6 35. 4042 Valley unit 2..... 1 1.100 0.477 56.6 36. 4042 Valley unit 3..... 1 1.050 0.473 55.0 37. 4042 Valley unit 4..... 1 0.925 0.473 48.9 38. 6041 Spurlock unit 1... 1 0.900 0.414 54.0 39. 6085 RM Schahfer unit 2 0.420 0.228 45.7 15. ---------------------------------------------------------------------------------------------------------------- [[Page 67124]] Table 5.--Tangentially Fired Boilers in the LNB Application Database -------------------------------------------------------------------------------------------------------------------------------------------------------- Uncontrolled Load weighted NOX rate post- ---------------- optimization Percent NOX Obs. No. ORISPL Unit name/unit ID Phase NOX rate removal (ln/mmBtu) ---------------- (ln/mmBtu) -------------------------------------------------------------------------------------------------------------------------------------------------------- 1. 710 McDonough unit 1......................... 1 0.657 0.388 40.9 2. 710 McDonough unit 2......................... 1 0.600 0.388 35.3 3. 728 Yates unit Y4BR.......................... 1 0.561 0.421 25.0 4. 728 Yates unit Y5BR.......................... 1 0.650 0.421 35.2 5. 1374 Elmer Smith unit 2....................... 1 0.859 0.419 51.2 6. 1710 Campbell unit 1.......................... 1 0.690 0.456 33.9 7. 2554 Dunkirk unit 1........................... 2 0.478 0.343 28.2 8. 2554 Dunkirk unit 2........................... 2 0.478 0.331 30.8 9. 2642 Rochester 7 unit 4....................... 2 0.587 0.365 37.8 10. 2732 Riverbend unit 7......................... 2 0.580 0.421 27.4 11. 2732 Riverbend unit 8......................... 2 0.640 0.383 40.2 12. 2732 Riverbend unit 10........................ 2 0.772 0.357 53.8 13. 4041 S. Oak Creek unit 7...................... 1 0.661 0.377 43.0 14. 4041 S. Oak Creek unit 8...................... 1 0.665 0.377 43.3 -------------------------------------------------------------------------------------------------------------------------------------------------------- The Agency believes that the addition of 20 units to the LNB Application Database increases the overall representativeness of the database for use in analyzing the achievable emission rates for Group 1 boilers and addresses commenters'' concerns that the original database may not adequately represent units with high uncontrolled emission rates. The current database contains 22 units with uncontrolled emission rates above the rates classified by one utility commenter as ``high'' (i.e., for wall-fired boilers, above 0.90 lb/mmBtu and for tangentially fired boilers, above 0.68 lb/mmBtu, see docket item IV-G- 16, p. 7). For several reasons, the Agency believes these additions to the database are more appropriate than adding boilers with LNB and overfire air (OFA) as suggested by some commenters. First, under the ruling in Alabama Power v. EPA, 40 F.3d 450 (D.C. Cir. 1994), EPA cannot consider LNB with OFA installations in the LNB Application Database for setting Group 1 limits. Second, isolating the true NOX reduction performance of the LNB portion of LNB+OFA systems is problematic because the controls are designed to reduce NOX as an integrated system and site-specific factors influence the relative contribution that each component (LNB vs. OFA) is designed to achieve. Further, there is no basis for assuming that the performance of the LNB portion, even if this could be measured accurately, is representative of the performance that could be achieved by LNBs without the addition of OFA. 2. Time Period/Averaging Basis Used To Evaluate Performance of Low NOX Burner Technology i. Background Because the Acid Rain Phase I NOX Emission Reduction Program did not go into effect until January 1, 1996, EPA did not have, at the time the proposed rule was issued, CEM data on the performance of LNBs applied to Group 1 boilers during a period when affected boilers were required to meet the annual Phase I NOX emission limitations. Further, for the reasons discussed below, it could not be assumed that all the CEM data available, some of which had been recorded as early as January 1, 1994, reflected LNB performance during optimized NOX removal conditions. As discussed in the Regulatory Impact Analysis (RIA) for the proposed rule (see docket item II-F-2), plants incur both fixed and variable operation and maintenance (O & M) costs when operating LNBs to reduce NOX emissions to the lowest practicable level consistent with prudent boiler operations to comply with regulatory emission limitations. Therefore, even though LNB controls are installed, utilities have a financial incentive not to operate units throughout an extended period of pre-compliance to sustain the emission reductions the controls were designed to achieve, since this would increase O & M costs when the NOX emission reductions are not yet required. Thus, the average NOX emission rate measured over an extended pre- compliance period may not be a good predictor of LNB performance under actual compliance conditions. On the other hand, it is reasonable to expect that utilities operated their newly installed NOX controls for some period of time following optimization of the equipment to simulate compliance conditions, perhaps as a dry run or for training purposes. EPA's objective, then, was to identify the time period in the stream of post-retrofit hourly CEM data that corresponds to operation under optimized NOX removal conditions. EPA believed this time period should contain 52 days of valid CEM data since, in publications and in past rulemakings, the Department of Energy (DOE) and the utility industry have stated that acceptable results of long-term performance require data sets of at least 51 days with each day containing at least 18 valid hourly averages (see docket items II-I-99, Advanced Tangentially-Fired Combustion Techniques for the Reduction of Nitrogen Oxide (NOX) Emissions from Coal-Fired Boilers, and II-I-100, Demonstration of Advanced Wall-Fired Combustion Modifications for the Reduction of Nitrogen Oxide (NOX) Emissions from Coal-Fired Boilers). EPA defined a 52-day ``low NOX period'' for the purposes of assessing performance of LNBs applied to Group 1 boilers in the proposed rule. The ``low NOX period'' was determined by identifying the lowest average NOX emission rate each boiler has sustained for at least 52 days, i.e., over a period of 1,248 hours when the boiler was operating and valid CEM data (measured by CEMS certified pursuant to 40 CFR part 75) were available. The low NOX period for most boilers is considerably longer than 52 calendar days since hours during which the boiler did not operate or hours for which valid CEM data were not recorded are ignored and do not count [[Page 67125]] towards the required total of 1,248 hours. Even prior to the proposed rule, utility commenters and DOE had expressed the concern that by not using essentially all the recorded by post-retrofit CEM data, EPA was not accurately assessing the long-term performance capabilities of LNBs (61 FR 1442).\6\ Further, these commenters believed that using a fixed-length shakedown period of 30 to 90 days, applied universally to all installations, to allow for optimizing LNBs and operator training was more objective than using the variable-length and site-specific shakedown periods implicit in EPA's low NOX period methodology. Accordingly, for the proposed rule, EPA also developed estimates of post-retrofit average NOX emission rates for another time period beginning 30 calendar days after the estimated date the boiler began operating after shutdown for LNB installation and continuing to the end of the CEM data set. This period is referred to as the ``overall post-retrofit period'' in the proposed rule (61 FR 1447 (Tables 4 and 5); also see docket item II-A-9, Table 2 ) and as the ``post-retrofit minus 30 days period'' (abbreviated as ``30-day post-retrofit period'' in tabular column headings) in the technical support document for the final rule (see docket item IV-A-6). --------------------------------------------------------------------------- \6\ EPA notes that the tangentially fired boilers in the LNB Application Database used for the proposed rule had little more than the requisite 52 days of quality assured post-retrofit CEM data. Only CEM data reported through June 30, 1995, the end of the second quarter reporting period, were available for analysis and the LNB retrofit dates for tangentially fired boilers occurred in late 1994 or early 1995. --------------------------------------------------------------------------- For the proposed rule, EPA developed estimates of post-retrofit average NOX emission rates for a third period which, like the overall post-retrofit period, uses most of the recorded post-retrofit CEM data and, like the low NOX period, allows for a variable- length shakedown period to accommodate the site-specific nature of LNB equipment optimization and operator training processes. This time period begins with the first hour of the low NOX period and continues to the end of the CEM data set. It is referred to as the ``post-optimization period'' in both the proposed rule and final rule analyses. As mentioned previously in section B of this preamble, the post-optimization period forms the basis for EPA's final assessment of the effectiveness of LNBs applied to Group 1 boilers. Another concern, which was raised prior to the proposed rule by utility commenters and DOE, is that limited time periods such as the low NOX period may not adequately capture annual dispatch patterns and seasonal variations in demand for electrical power generation. Accordingly, for the proposed rule, EPA also investigated the representativeness of load dispatch during the low NOX period by comparing it to the load dispatch during calendar year 1994 for each boiler or common stack in the LNB Application Database. EPA developed two histograms using ``load bins'' for the horizontal axis: (1) Average hourly NOX emission rate as a function of load during the low NOX period; and (2) frequency of various boiler operating loads throughout 1994 (for which EPA had actual performance data from the CEM data set ). Then, EPA used these histograms to estimate ``load-weighted annual average NOX emission rates'' based on weighted averages of the average emission rate during the low NOX period for each load bin times the number of hours the boiler operated in that load bin during 1994 (61 FR 1448 (Tables 6 and 7)). To test the representativeness of boiler operations during the low NOX period, EPA also created bar charts comparing the percentage of time a boiler operated in each load bin during the low NOX period to the percentage of time it operated in that load bin during calendar year 1994 (see docket item II-A-9, Appendix B). Using these graphical analyses, EPA concluded that most boilers in the LNB Application Database had a load dispatch pattern during their low NOX period similar to their annual dispatch pattern in 1994. When analyzing long-term post-retrofit CEM data for the proposed rule, EPA found no strong correlation between boiler operating loads and hourly average NOX emission rates for either wall-fired boilers or tangentially fired boilers in the LNB Application Database. While earlier technical analyses performed for EPA in support of other utility NOX emission rulemakings had generally adopted the industry accepted presumption of a NOX vs. boiler load relationship for many uncontrolled Group 1 boilers, they also showed the direction, magnitude, and form of this correlation to be both highly boiler-specific and difficult to predict (see, for example, docket item IV-J-20). Nevertheless, EPA recognized that a predictable systematic correlation between hourly average NOX emission rates and boiler load for all or some boilers could have significant ramifications for proper application of a 52-day low NOX period methodology. Accordingly, EPA developed the ``load-weighted annual average NOX emission rates,'' defined above, to account for the potential existence of a NOX vs. boiler load relationship. Because the load-weighted annual average NOX emission rates were essentially the same as or lower than the average NOX emission rates for the low NOX period for these boilers (see 61 FR 1446 (Tables 5 and 6)) EPA selected the simpler form, a straight average over the low NOX period, as the basis for the proposed rule. The Agency received many detailed comments and supporting data about the appropriateness of using a limited low NOX period for assessing LNB performance, the merits of site-specific variable-length vs. universal fixed-length shakedown periods to reflect LNB equipment optimization and operator training, the advantages and disadvantages of the alternative time periods EPA had considered for the proposed rule analysis, and the technical issue of the existence of a NOX vs. load relationship and its relevance for assessing LNB performance applied to Group 1 boilers. The first three issues are discussed in the next section within the context of the low NOX period methodology whereas the last issue, for which EPA received approximately 25 site- specific data submissions from utility boiler owners or operators, is treated separately in the subsequent section. ii. Use of 52-Day Low NOX Period Comment/Analyses: EPA received approximately 29 comment letters (from 22 utilities, 2 utility associations, 3 states, a gas industry representative, and an environmental association) on the appropriateness of using a 52-day low NOX period for assessing LNB performance when, for some boilers, considerably more post-retrofit data was available. Some commenters fully endorsed EPA's 52-day methodology and implicit assumption that utilities not under a compliance obligation are unlikely to operate the controls for maximum emission reductions following LNB optimization and a low NOX test period. They believed EPA had demonstrated that the 52-day methodology and ``load- weighted annual average NOX emission rates'' adequately addressed annual dispatch and load patterns in most cases. A utility that owns and operates coal-fired units which have become subject to state- mandated NOX Reasonably Available Control Technology (RACT) requirements in 1995 said EPA should go even further and ``use NOX data only from units that have had to comply with a recent NOX standard (such as NOX RACT)'' for [[Page 67126]] evaluating the effectiveness of LNB technology (see docket item IV-G- 14, p. 1). EPA notes that 6 wall-fired boilers and 3 tangentially fired boilers in the LNB Application Database are located in the Northeast Ozone Transport Region and are subject to NOX RACT requirements. The mean load-weighted annual average NOX emission rates over the post-optimization period for these boilers are: 0.403 lb/mmBtu (wall- fired) and 0.344 lb/mmBtu (tangentially fired). One commenter noted that utilities had an explicit disincentive for operating their LNBs to achieve the maximum practicable emission reductions during 1994 and 1995, since section 407(b)(2) allows EPA to promulgate revisions to Group 1 emission standards if measured average post-retrofit NOX emission rates during this time frame indicate ``more effective low NOX burner technology is available'' (see docket item IV-D-63, p.14). Another commenter endorsed the conclusion that observations during the 52-day low NOX period may understate the actual reduction capability of LNBs (see docket items IV-D-047, p. 2 and IV-D-063, p. 12-14). Other commenters disagreed with the assumption that utilities did not have any incentive to operate the installed LNBs to achieve maximum emission reductions consistent with prudent boiler operations. One utility stated that plant personnel ``operated [their] NOX control systems in a compliance mode even though its units were technically not yet subject to the Phase I NOX standard. [The utility] established performance goals based on operating NOX reductions systems to meet the standard and management bonuses were geared to meeting these goals'' (see docket item IV-D-020, p. 6). EPA notes that all of this utility's wall-fired units sustained average NOX emission rates below 0.44 lb/mmBtu throughout their ``post-optimization'' periods (i.e., the post-retrofit period excluding a shakedown period based on actual boiler experience). The post-optimization periods for these units varied in length from 12 to 18 months. Another utility stated that boilers were operated in a manner to optimize NOX emission reduction; to do otherwise would be ``counterproductive to the design of the burners and would defeat the training of the operating staff'' (see docket item lV-D-023, p. 4). EPA notes that the units owned and operated by both of these utility commenters are located outside designated ozone nonattainment areas and are not subject to NOX RACT or any other state-mandated NOX control requirements. Their decision to operate in a low-NOX mode, therefore, was voluntary and not made on the basis of whether a compliance obligation existed. Several commenters indicated that the best approach for estimating annual average NOX emission rates is to use a full year of post- retrofit monitoring data (see, for example, docket item IV-D-38, p. 3). Commenters reiterated the concern raised prior to the proposal rule, that by not using essentially all the recorded post-retrofit CEM data, EPA is not accurately assessing the long-term performance capabilities of LNBs (see, for example, docket items IV-D-35, p. 3; IV-G-15, pp. 2- 3). They said EPA's 52-day low NOX period methodology fails to take into account all of the operating variables that affect LNB performance and biases the LNB performance assessment toward emission reduction levels that may not be achievable over the long term. Further, commenters who participated in DOE Clean Coal Technology Demonstrations where the 52-day methodology was used, said the ``52-day rule'' defines ``the minimum number of continuous days of data needed before a data set can be considered `long-term' data. It is not a rule that justifies selective editing of data, when more data are available'' (see docket item II-D-65, p. 29). Some of these commenters suggested using all CEM data recorded after a fixed-length shakedown period whereas others believed a variable-length shakedown period is more appropriate given the site- specific nature of the LNB equipment optimization and operator training processes. EPA notes that one utility commenter reported that burner optimization for each of their five tangentially fired retrofits was completed within 120 days of startup (see docket item IV-D-23, p.4), which is considerably longer than the fixed 30-day shakedown period recommended by DOE and others. Another utility commenter reported that one of their wall-fired boilers, E.D. Edwards 2, was still being optimized more than a year after the retrofit date (see docket item IV- D-73, p. 3). Several commenters indicated support for the post-optimization period approach, which EPA had presented in the proposed rule together with the 52-day low NOX period methodology and load-weighted annual average NOX emission rates. As one utility said, `the post- optimization period' emission results are the best data set characterizing long-term low-NOX mode boiler operation. This database maximizes the amount of low-NOX mode data (i.e., sample size) collected following a period of demonstrated minimum NOX operation.'' (See docket item IV-D-051, p. 8.) Some commenters indicated a 52-day low NOX period methodology would be credible for assessing the long-term performance of LNB technology if NOX emission rates following LNB optimization do not vary significantly with boiler load (see, for example, docket item IV- D-72, p. 4). While these commenters generally believe NOX emission rates are a function of load for many boilers (see discussion below under NOX vs. Boiler Load Relationship), they do endorse the concept of using less than essentially all the recorded post-retrofit CEM data for assessing LNB performance. Response: EPA believes that the 52-day low NOX period methodology is technically justified for evaluating the achievable NOX reduction capability of LNBs. This time period is sufficiently long, in most instances, to reflect long-term operation as evidenced by the generally similar load dispatch patterns observed during the low NOX period and for calendar year 1994 for most boilers in the LNB Application Database. However, assuring proper selection of a low NOX period that is representative of long-term boiler operating conditions in all instances can be difficult. An example of this is E.D. Edwards 2 where, according to the utility, the 52-day low NOX period EPA had selected for the proposed rule analysis was atypical because it represents ``a period of testing in a low NOX mode when the boiler was not optimized.'' Shortly thereafter, the utility re- tuned the boiler for improved efficiency, to reduce loss on ignition (LOI), and to maintain full compliance with particulate and opacity emissions standards. (See docket item IV-D-073, pp. 3-4.) Another commenter suggested possible adverse plant impacts may have occurred during the low NOX period for a few other boilers in the LNB Application Database (see docket item IV-D-65, Enclosures 7 and 14); EPA's analysis of the specific impacts and remedial actions cited indicates that these possible issues are adequately addressed by extending the low NOX period into the longer post-optimization period. Therefore, to maximize the likelihood that the performance evaluation period is representative and to assure observations over the broadest possible range of boiler operating variables and electric power generation demand scenarios, EPA is using the longer post- optimization period as the basis for assessing the performance of LNBs applied to Group 1 boilers for the final rule. [[Page 67127]] EPA's decision to use the post-optimization period is also based, in part, on the comments utilities have submitted regarding their actions to operate installed LNBs in a compliance mode during 1995, prior to the effective date of the Acid Rain Phase I NOX Emission Reduction Program. EPA believes that there were reasons for utilities to operate installed LNBs as if the emission standards were in effect, even though such operation could increase utility O & M costs. EPA has rejected the concept of using a ``post-retrofit minus 30 (or 60 or 90) days period'' approach because utilities submitted significant evidence documenting that the time required for LNB optimization is highly variable and can be much longer than any of the fixed shakedown periods under consideration (see, for example, docket items IV-D-023, IV-D-073, and IV-G-04). Nonetheless, for comparison purposes, EPA has computed average NOX emission rates based on the post-retrofit minus 30 days period for boilers in the LNB Application Database (see docket item IV-A-6, Table 3-1). The addition of four more quarters of CEM data to the LNB Application Database substantially lengthens the post-optimization period for most boilers.7 The post-optimization period also includes six months of 1996 compliance data for each Phase I boiler in the database. Table 6 presents summary statistics on the amount of hourly CEM data and calendar months encompassed by the post- optimization periods. --------------------------------------------------------------------------- \7\ A notable exception is the post-optimization time period for E.D. Edwards 2, which has been lengthened by a lesser amount. In response to the utility's comments, EPA has selected another low NOX period, beginning after October 1, 1995, the date on which EPA believes corrections for adverse opacity and particulate emissions were substantially complete. Table 6.--LNB Application Database: Hours of CEM Data and Calendar Months in Post-Optimization Periods ------------------------------------------------------------------------ Hours of CEM Calendar Boiler types data months ------------------------------------------------------------------------ Wall-fired boilers: 85% have at least 11 months of CEM data in post-optimization period: Range.................................... 3,877-15,829 6-30 Average.................................. 9,547 16 Total.................................... 372,324 610 Tangentially fired boilers: 79% have at least 11 months of CEM data in post-optimization period: Range.................................... 1,280-12,327 4-18 Average.................................. 7,537 14 Total.................................. 105,523 190 ------------------------------------------------------------------------ iii. NOX vs. Boiler Load Relationship Comment/Analyses: EPA received approximately 23 comment letters (from 21 utilities and 2 utility associations) criticizing EPA's decision in the proposed rule to base revised Group 1 emission limitations on a time period and averaging method which do not explicitly recognize the existence of a NOX vs. load relationship. As mentioned previously under section III.A.2.i. of this preamble, EPA found no strong correlation between boiler operating loads and hourly average NOX emission rates for either wall-fired boilers or tangentially fired boilers in the LNB Application Database when analyzing long-term post-retrofit CEM data for the proposed rule. Nevertheless, to test the potential impact of a NOX/load relationship, in the analysis accompanying the proposed rule EPA developed a methodology that assumed the existence of a functional relationship between NOX and boiler load. EPA then used this methodology to estimate ``load-weighted annual average NOX emission rates'' for each boiler or common stack in the LNB Application Database (see docket item II-A-9, pp. 9-10). The load-weighting methodology produced a weighted average based on the frequency of various operating load intervals (or ``bins'') during calendar year 1994 as reported in the CEM data set and the mean hourly NOX emission rates for each load bin observed during the low NOX period. (The computational procedures EPA used to estimate load-weighted annual average NOX emission rates for the proposed rule are described under preamble section III.A.2.i.) Finding that the load-weighted annual average NOX emission rates for these boilers were essentially the same as or lower than the average NOX emission rates for the low NOX period without the assumption of a NOX/load relationship (see 61 FR 1446 (Tables 5 and 6)), EPA believed it was not necessary to investigate the NOX vs. load relationship further and selected the more conservative (i.e., higher) of the two sets of estimates for modeling annual average emission rates that could be sustained by LNBs installed on Phase II, Group 1 boilers. The commenters who criticized EPA's treatment of the NOX/load relationship raised the following main issues: Lack of statistical measures to quantify the extent of the NOX/load relationship: Several commenters indicated that a critical missing link in EPA's analysis of this issue for the proposed rule was the failure to develop any statistical measures describing the strength of the association, if any, between NOX and boiler load. As one utility said, EPA concluded ``through observance of the data'' that the relationship between NOX and load is not strong for wall- fired boilers (see docket item IV-D-023, p. 5) Inconsistency with earlier EPA studies: Some commenters claimed that earlier EPA studies and utility emission rulemakings supported the existence of the NOX/load relationship. Examples to show presence of a NOX/load relationship: Many of the commenters on this issue included site-specific data intended to document the presence of a well-correlated NOX/load relationship. On the other hand, some commenters who supported EPA's use of the low NOX period for evaluating the performance of LNBs also said EPA's comparison of load-weighted annual average NOX emission rates vs. average NOX emission rates without the assumption of a NOX/load relationship satisfactorily addresses this issue (see, for example, docket items IV-D-46, p. 5 and IV-D-56, p. 1). According to a state agency, the ``52-day time frame is representative of a wide range of operations in a facility'' because the load variations over a seven-day week are likely to be more significant than seasonal variations. This agency said that, for most load-following units, load changes are likely to be more significant between weekends and weekdays than between seasons. Only the highest base-loaded units do not exhibit this load cycle and such units are ``likely not affected by seasonal changes'' (see docket item IV-D-27, p. 9). Response: After further extensive boiler-by-boiler analysis of NOX and boiler load, using both data provided by commenters and reported independently under 40 CFR part 75 requirements, EPA has determined that the installation of LNBs dampens any NOX/load correlation that may have [[Page 67128]] existed at uncontrolled boilers and, in many instances, virtually eliminates any long-term relationship. A NOX vs. load relationship appears to have persisted for none of the tangentially fired boilers and for only a few of the wall-fired boilers (Colbert 5, E.D. Edwards 2, Quindaro 2, and Jack Watson 5) in the LNB Application Database (see docket item IV-A-6, pp. 4-2 through 4-7). However, despite these findings, in response to commenters' insistence that a definite functional relationship exists between NOX and boiler load, EPA has employed a NOX/load weighting scheme in establishing NOX emission limits in this final rule. This load-weighting method incorporates at least two distinct improvements over the method used for the proposed rule analysis. First, following commenters' recommendation, the load weighting method employs ten load bins consistent with the convention specified in 40 CFR part 75, rather than the 25-MW increments used in the proposal. Second, the method uses post-retrofit CEM data over the longer post-optimization period, rather than the 52-day low NOX period, to estimate mean hourly NOX emission rates for each load bin, thus making it unnecessary to combine load bins due to sparse data. (Commenters had also said the combining of load bins with little or no data tended to mask the NOX/load relationship. See docket item, IV-D-65, p. 35.) The load weighting method uses hourly boiler or common stack load as reported in the CEM data set for 1995 to establish the frequency of operation in different load bins over a year. EPA has rigorously investigated the relationship of individual load patterns of boilers sharing a common stack to the combined load patterns over a year and, thus, to the annual average NOX emissions for the common stack (see discussion of common stack issues in section III.A.3.v of this preamble). Finally, EPA has compared, where data are available, boiler or common stack load patterns for 1994 and 1995 to assess inter-year variations in dispatch and demand for electrical power generation (see docket item IV-A-6). This improved load weighting scheme accounts for any potential impact that annual load dispatch patterns may have on NOX emissions. Its use should allay concerns raised by commenters on how the presence of a NOX/load relationship might impede accurate assessment of long-term LNB performance. In addition, EPA's specific responses to the main NOX/load issues are presented below: Lack of statistical measures to quantify the extent of the NOX/load relationship: Even among those commenters who most strongly assert the presence of a NOX/load correlation, there is little consistency from boiler to boiler in either the functional form or the direction of the NOX/load relationship. For example, of the three commenters submitting regression equations as evidence of a NOX/load relationship, one was based on a cubic model (see docket item IV-D-20, Figure 3), another was based on a logarithmic model (see docket item IV-G-14, p. 3), and a third was based on a quadratic model (see docket item IV-G-16). A fourth commenter, represented the NOX/load relationship from one-third to full load for eight boilers as straight line plots with slopes varying from approximately 15 deg. to 45 deg. (see docket item IV-D-72, Attachment 1). Although no supporting documentation was provided explaining how these plots were derived, they would imply a linear model was appropriate. The situation is further complicated when a NOX/load relationship is discernible over only a portion of the load range. This is particularly an issue for wall-fired boilers retrofit with LNBs. EPA's plots of data from post-retrofit wall-fired boilers show that if a NOX/load relationship is discernible at all, it occurs almost entirely in the upper 10-20% of the boiler load range. The absence of a consistent functional form for the NOX/load relationship and a failure to persist across the full load range makes application of a statistical measure to quantify the extent of the NOX/load correlation difficult. Nonetheless, assuming a linear relationship between NOX and boiler load, EPA estimated the strength of correlation as indexed by R2 during post-retrofit period for 30 wall-fired and 11 tangentially fired boilers or common stacks in the LNB Application Database and, during the pre-retrofit period, for 13 wall-fired and 6 tangentially fired boilers or common stacks (see docket item IV-A-6, Cadmus Group 1 technical report, Table 4-1). The R2 statistic measures the fraction of the variability in the dependent variable, hourly average NOX emission rate, explained by the model. EPA chose an R2 of 40% as a threshold for detection of the possible existence of a predictable correlation. For the post-retrofit hourly average NOX emission rate measurements, only 13% of the wall-fired and none of the tangentially fired boilers or common stacks had an R2 of 40% or higher (suggesting no predictable correlation). EPA compared the load dispatch pattern during the post-optimization period for each boiler or common stack crossing the R2 threshold to its annual dispatch pattern in 1995 and concluded the patterns were similar enough that the improved load- weighting methodology would mitigate the effects of any NOX/load correlation on estimated controlled annual average emission rates. Inconsistency with earlier EPA studies: Earlier technical analyses performed for EPA in conjunction with other utility NOX emission rulemakings generally adopted the industry accepted presumption of a NOX vs. boiler load relationship. However, this was almost exclusively for uncontrolled Group 1 boilers, not boilers retrofit with LNBs. Prior studies also showed the direction, magnitude, and form of this correlation to be both highly boiler-specific and difficult to predict. (See, for example, docket item IV-J-20). Thus, for example, in these earlier studies, some uncontrolled tangentially fired boilers exhibit increasing NOX emission rates with decreasing boiler loads, others show precisely the reverse correlation, and still others have U-shaped curves. Uncontrolled wall-fired boilers typically exhibit increasing NOX emission rates with increasing boiler loads. However, this relationship was not found to be universally valid either, and the strength of the correlation, when present, varies considerably from one boiler to another. For this final rule, EPA's analysis is more exhaustive than these earlier studies. It encompassed more boilers, longer data streams, and better quality data. Separate graphs were generated for every boiler or common stack in the LNB Application Database, plotting NOX hourly emission rates as a function of hourly load, using long-term quality assured CEM data. To allow comparison of uncontrolled and controlled emissions, wherever available, pre- and post-retrofit hourly data were plotted on the same graph, differentiated by distinct symbols. A comparison of the pre-retrofit and post-retrofit plots shows that, with one exception, for both wall-fired boilers and tangentially fired boilers, if any NOX vs. load relationship existed for uncontrolled emissions, the installation of LNBs both reduced the magnitude and shortened the effective range of that relationship. As discussed above, EPA also developed a statistical measure (R2) of the strength of the correlation between NOX and boiler load, assuming a linear relationship. This statistical analysis corroborates the visual assessment of the data plots. For the post- retrofit hourly average NOX emission rate measurements, only 13% of the wall- [[Page 67129]] fired and none of the tangentially fired boilers or common stacks had an R2 of 40% or higher, suggesting possible presence of a predictable correlation. Even though this analysis confirms that the occurrence of a NOX-load relationship is generally slight and for only some boilers, to eliminate all concerns in this regard, EPA has based the final rule on load-weighted annual average NOX emission rates (instead of a straight average emission rates) observed over the post-optimization period (instead of the 52-day low NOX period). Examples to show presence of a NOX/load relationship: A number of commenters provided data intended to demonstrate the presence of a NOX/load relationship. The submissions either had drawbacks which rendered their conclusions questionable or corroborate EPA's finding that the installation and operation of LNBs generally dampen any pre- retrofit correlation of NOX and boiler load and, in many instances, virtually eliminate any long-term relationship. The salient aspects of each submission and EPA's responses are summarized below: Docket item IV-D-020, Figure 20: Using CEM data for the period 06/ 30/95 through 07/18/95, this submission included a regression analysis for a 550 MW wall-fired boiler retrofit with LNBs. The regression model fit NOX emissions to boiler load during the period analyzed. The R2 statistic, which captures the explanatory power of the regression model, was 77.3%, indicative of a good fit with the data. There were a number of drawbacks, however, with the analysis. First, the period analyzed represents only 19 calendar days. This is too short a period to adequately represent long-term performance or to distinguish a strong, but transitory, NOX/load correlation from a persistent NOX/load correlation. Second, the data plot shows a wide range of NOX emission rate points at zero load. These appear to be spurious measurements which improperly dominated the regression results. Docket item IV-G-14, Tables 1-4 and Figures 1 and 2: This submission included ``before LNB'' and ``after LNB'' regression analyses for a 80 MW tangentially fired boiler. The ``before LNB'' regression is based on five-and-a-half months of CEM data and the ``after LNB'' regression is based on eight months of CEM data. During the ``after LNB'' period, this boiler had to comply with a state- mandated NOX RACT limit of 0.42 lb/mmBtu on a 24-hr average basis. The commenter rightly excludes NOX emission data points for periods when load is zero, which is consistent with EPA's DQO 3D.\8\ In both the ``before LNB'' and ``after LNB'' case, the highest NOX emission rate is at minimum load. The R2 statistic in the ``before LNB'' regression was 57.8%, indicating that the model had moderate explanatory power, whereas the R2 value in the ``after LNB'' regression was only 29.1%, indicating poor explanatory power.\9\ EPA believes that this ``before LNB'' and ``after LNB'' comparative regression analysis illustrates how the installation and operation of LNBs can dampen any NOX vs. load relationship which may be observed at uncontrolled boilers. --------------------------------------------------------------------------- \8\ The commenter applies a cutoff at 5 MW, to exclude periods when a small positive heat input may be recorded, but boiler load is actually zero. \9\ The commenter concludes that the relationship between NOX and boiler load is much less well-defined after LNB retrofit, but maintains the relationship still exists based on an analysis of variance which produces a correlation coefficient of -0.54. --------------------------------------------------------------------------- Docket items IV-D-65, Enclosure 8; IV-D-23, Attachment 1; IV-D-73, Attachment A: Several commenters submitted line plots or histograms of average and/or maximum NOX emission rates recorded for different load intervals or ``bins''. There were several problems with these submissions. First, although they criticize EPA in this regard, the commenters themselves do not develop any statistical measures of the association between NOX and load for the data they submit (perhaps because it, too, fails to demonstrate the presumed relationship). Nor do they suggest functional representations for their plots. A second drawback of these submissions is that some of the plots represent boilers retrofit with LNBs plus separated overfire air. As noted previously, such applications cannot be considered in this rulemaking. Third, while the submitted graphs appear to support the commenters' statements about the existence of a NOX vs. load relationship for the boilers analyzed, the use of a single value (whether the average or maximum) to represent all values in a load range bin is misleading. It hides the variability within the bin, thereby avoiding the issue of whether the range of values in one bin are distinguishable from those in another bin. To address this issue EPA generated NOX/load box-and-whisker plots for each boiler or common stack in the LNB Application Database. The box-and-whisker representation not only shows a mid-point value (the median), but it also characterizes the range of values found in each bin by displaying the minimum, maximum, and first and third quartile values. Where sufficient data were available, separate graphs were created for NOX/load correlation before and after LNB retrofits. In response to the commenter's criticism that EPA's earlier analysis for the proposed rule had used too few load bins, ten load bins (in 10 percent increments from zero to maximum gross unit load) were used in all the NOX/load analyses for the final rule. The box-and-whisker plots reveal so much overlap in NOX values from bin to bin that drawing conclusions about a NOX/load relationship is technically inappropriate. This is particularly true for the post-retrofit situation. Docket items IV-D-73, p. 5 and Attachment A; IV-D-65, p. 32: One utility reported that the NOX emission rate guarantee, in its contract for LNBs on a 375 MW wall-fired boiler (E.D. Edwards 3), ``[is] designed specifically to achieve specific NOX rates at specific loads.'' The annual NOX emission rate is guaranteed to meet 0.50 lb/mmBtu based on a specified capacity. The NOX emission rate guarantees for particular loads range from 0.28 lb/mmBtu at 40% of MCR (150 MW) to 0.63 lb/mmBtu at 100% of MCR (375 MW). The commenter also submitted graphs depicting the ``remarkable NOX vs. load relationship'' for another wall-fired boiler (E.D. Edwards 2). The graphs plotted the average, maximum, and minimum hourly NOX emission rates recorded in each of ten load bins for the four quarters of 1995 as well as the entire year. EPA has analyzed all the post-retrofit CEM data for E.D. Edwards 2 to evaluate the extent of a discernible NOX/load relationship. The analysis confirmed the existence of a well-defined NOX vs. load relationship for this boiler, but only in the upper 20% of the load range (see docket item IV-A-6, Appendix D). Another commenter noted that Babcock & Wilcox (B&W), a primary designer of wall-fired boilers and a major LNB vendor in the U.S., attests to the existence of a NOX/load correlation. This commenter said EPA did not find a strong NOX vs. load relationship because EPA did not examine closely the post-retrofit CEM data for wall-fired boilers designed by B&W. B&W has stated, ``a definite correlation [exists] between NOX emissions and boiler load'' (see docket item IV-D-65, p. 32). The LNB Application Database contains 18 wall-fired boilers designed by B&W. Five of these boilers, EPA believes, have also been retrofit with LNBs manufactured by B&W (Model DRB-XCL). Only one B&W boiler and none of the B&W LNB retrofits appeared among the wall-fired boilers or common [[Page 67130]] stacks that had an R\2\ of 40% or higher for the correlation of post- retrofit hourly average NOX emission rate measurements with boiler load. 3. Analysis Method Used to Establish Reasonably Achievable Emission Limitations for Phase II, Group 1 Boilers i. Background For the proposed rule, EPA used a three-step analytical procedure for establishing reasonably achievable annual emission limitations for the populations of wall-fired boilers and tangentially-fired boilers, retrofit with LNBs, that would be subject to any revised emission limitations (i.e., those units subject to NOX emission limitations only in Phase II). The first step (Model Building) consisted of deriving linear regression equations, one for wall-fired boilers and another for tangentially fired boilers, that captured the percent reduction in post-retrofit load-weighted annual average NOX emission rate as a function of the uncontrolled emission rate for boilers in the LNB Application Database. The second step (Calculation of Achievable Emission Rates) was to enter the uncontrolled emission rates of the Phase II boilers into the regression equations in order to derive the controlled NOX emission rate that each boiler could be expected to achieve by LNB retrofit. Using the resulting set of achievable emission rates, the third step was to identify the annual emission limitation that a specified percentage (i.e., 85 to 90%) of the Phase II boilers could achieve. Separate limits were identified for wall-fired boilers and for tangentially fired boilers. This three-step procedure afforded several advantages. First, by using regression equations, the estimates of achievable emission rates were not rough extrapolations from average Phase I post-retrofit experience but were estimates specifically tailored to the pre-retrofit NOX emission rates actually observed at the Phase II units. As shown in Table 12 in the preamble to the proposed rule (61 FR 1452), Phase II units typically operate at lower uncontrolled emission rates than Phase I units (i.e., 23% lower for wall-fired boilers and 18% lower for tangentially fired boilers) so a simple extrapolation of the experience of the mostly Phase I units in the LNB Application Database would significantly underestimate the number of boilers that would be expected to achieve a given emission limitation. Second, using regression models also allowed for quantitative, statistical evaluation of the explanatory power implicit in the resulting estimates and enabled objective comparison of different analytical approaches. Incorporating load-weighted annual averaging into Step 1 of the procedure meant that any NOX/load effects would be factored into the model. Furthermore, responding to comments criticizing the proposed rule for basing the regression model on 52 days of [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A96-31839. Public record. Not legal advice.