VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00035 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1694 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules   When appropriate, use data from non U. S. studies to broaden age ranges to which current estimates apply and to include more types of relevant health outcomes; and   Begin to move the assessment of uncertainties from its ancillary analyses into its primary analyses by conducting probabilistic, multiplesource uncertainty analyses. This assessment should be based on available data and expert judgment. Although the NAS made a number of recommendations for improvement in EPA's approach, it found that the studies selected by EPA for use in its benefits analysis were generally reasonable choices. In particular, the NAS agreed with EPA's decision to use cohort studies to derive benefits estimates. It also concluded that the Agency's selection of the American Cancer Society ( ACS) study for the evaluation of PM related premature mortality was reasonable, although it noted the publication of new cohort studies that should be evaluated by the Agency. Several of the NAS recommendations addressed the issue of uncertainty and how the Agency can better analyze and communicate the uncertainties associated with its benefits assessments. In particular, the Committee expressed concern about the Agency's reliance on a single value from its analysis and suggested that EPA develop a probabilistic approach for analyzing the health benefits of proposed regulatory actions. The Agency agrees with this suggestion and is working to develop such an approach for use in future rulemakings. In this benefits analysis for the proposed rule, the Agency has used an interim approach that shows the impact of several important alternative assumptions about the estimation and valuation of reductions in premature mortality and chronic bronchitis. This approach, which was developed in the context of the Agency's Clear Skies analysis, provides an alternative estimate of health benefits using the time series studies in place of cohort studies, as well as alternative valuation methods for mortality and chronic bronchitis risk reductions. For the proposed rule, we conducted an air quality assessment to determine the change in ambient concentrations of PM10 and PM2.5 that result from reductions of PM and SO2 at existing affected facilities. Our air quality analysis was conducted using the source receptor ( S   R) matrix model, a model that provides changes in PM10 and PM2.5 concentrations based on changes in PM and/ or PM precursor emissions. Unfortunately, our data is not able to define the exact location of the reductions for every affected boiler and process heater. The air quality analysis was conducted for emissions reductions from those emissions sources that have a known link to a specific control device, which represents approximately 50 percent of the total emissions reductions mentioned above. Using this subset of information, we utilized the S   R matrix to determined the air quality change nationwide. The results of the air quality assessment served as input to a model that estimates the total monetary value of benefits of the health effects listed above. Total benefits associated with this portion of the analysis are $ 8.2 billion in the year 2005 ( presented in 1999 dollars). For those emissions reductions from affected sources that do not have a known link to a specific control device, the results of the air quality analysis serve as a reasonable approximation of air quality changes to transfer to the remaining emissions reductions of the proposed rule. Because there is not a reasonable way to apportion the total benefits of the combined impact of the PM and SO2 reductions from the air quality and benefit analyses completed above, we performed two additional S   R matrix analyses. One analysis was performed to evaluate the impact on air quality of the PM reductions alone ( holding SO2 unchanged), and one to evaluate the impact on air quality from the SO2 reductions alone ( holding PM unchanged). With independent PM and SO2 air quality assessments, we can determine the total benefit associated with each component of total pollutant reductions. The total benefit associated with the PM and SO2 reductions with unspecified location are $ 7.9 billion. Every benefit cost analysis examining the potential effects of a change in environmental protection requirements is limited to some extent by data gaps, limitations in model capabilities ( such as geographic coverage), and uncertainties in the underlying scientific and economic studies used to configure the benefit and cost models. Deficiencies in the scientific literature often result in the inability to estimate changes in health and environmental effects, such as potential increases in premature mortality associated with increased exposure to carbon monoxide. Deficiencies in the economics literature often result in the inability to assign economic values even to those health and environmental outcomes which can be quantified. While these general uncertainties in the underlying scientific and economics literatures are discussed in detail in the RIA and its supporting documents and references, the key uncertainties which have a bearing on the results of the benefit cost analysis of today's action are the following: 1. The exclusion of potentially significant benefit categories ( e. g., health and ecological benefits of reduction in hazardous air pollutants emissions); 2. Errors in measurement and projection for variables such as population growth; 3. Uncertainties in the estimation of future year emissions inventories and air quality; 4. Uncertainties associated with the extrapolation of air quality monitoring data to some unmonitored areas required to better capture the effects of the standards on the affected population; 5. Variability in the estimated relationships of health and welfare effects to changes in pollutant concentrations; and 6. Uncertainties associated with the benefit transfer approach. Despite these uncertainties, we believe the benefit cost analysis provides a reasonable indication of the expected economic benefits of the industrial boilers and process heaters MACT under two different sets of assumptions. We have used two approaches ( base and alternative estimates) to provide benefits in health effects and in monetary terms. They differ in the method used to estimate and value reduced incidences of mortality and chronic bronchitis, which is explained in detail in the RIA. While there is a substantial difference in the specific estimates, both approaches show that the industrial boilers and process heaters MACT may provide benefits to public health, whether expressed as health improvements or as economic benefits. These include prolonging lives, reducing cases of chronic bronchitis and hospital admissions, and reducing thousands of cases in other indicators of adverse health effects, such as work loss days, restricted activity days, and days with asthma attacks. In addition, there are a number of health and environmental effects which we were unable to quantify or monetize. These effects, denoted by `` B'' are additive to the both the base and alternative estimates of benefits. Results also reflect the use of two different discount rates for the valuation of reduced incidences of mortality; a 3 percent rate which is recommended by EPA's Guidelines for Preparing Economic Analyses ( U. S.

VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00036 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1695 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules EPA, 2000a), and 7 percent which is recommended by OMB Circular A   94 ( OMB, 1992). More specifically, the base estimate of benefits reflects the use of peerreviewed methodologies developed for earlier risk and benefit cost assessments related to the Clean Air Act, such as the regulatory assessments of the Heavy Duty Diesel and Tier II rules and the section 812 Report to Congress. The alternative estimate explores important aspects of the key elements underlying estimates of the benefits of reducing PM and SO2 emissions, specifically focusing on estimation and valuation of mortality risk reduction and valuation of chronic bronchitis. The alternative estimate of mortality reduction relies on recent scientific studies finding an association between increased mortality and shortterm exposure to particulate matter over days to weeks, while the base estimate relies on a recent reanalysis of earlier studies that associate long term exposure to fine particles with increased mortality. The alternative estimate differs in the following ways: it explicitly omits any impact of long term exposure on premature mortality, it uses different data on valuation and makes adjustments relating to the health status and potential longevity of the populations most likely affected by PM, it also uses a cost of illness method to value reductions in cases of chronic bronchitis while the base estimate is based on individual's willingness to pay ( WTP) to avoid a case of chronic bronchitis. In addition, one key area of uncertainty is the value of a statistical life ( VSL) for risk reductions in mortality, which is also the category of benefits that accounts for a large portion of the total benefit estimate. The adoption of a value for the projected reduction in the risk of premature mortality is the subject of continuing discussion within the economic and public policy analysis community. There is general agreement that the value to an individual of a reduction in mortality risk can vary based on several factors, including the age of the individual, the type of risk, the level of control the individual has over the risk, the individual's attitude toward risk, and the health status of the individual. The Environmental Economics Advisory Committee ( EEAC) of the EPA Science Advisory Board ( SAB) recently issued an advisory report which states that `` the theoretically appropriate method is to calculate willingness to pay for individuals whose ages correspond to those of the affected population, and that it is preferable to base these calculations on empirical estimates of WTP by age.'' ( EPA   SAB   EEAC   00   013). In developing our base estimate of the benefits of premature mortality reductions, we have appropriately discounted over the lag period between exposure and premature mortality. However, the empirical basis for adjusting the current $ 6 million VSL for other factors does not yet justify including these in our base estimate. A discussion of these factors is contained in the RIA and supporting documents. The EPA recognizes the need for additional research by the scientific community to develop additional empirical support for adjustments to VSL for the factors mentioned above. Furthermore, EPA prefers not to draw distinctions in the monetary value assigned to the lives saved even if they differ in age, health status, socioeconomic status, gender or other characteristic of the adult population. Given the advice from the SAB, we employed the suggested approach for the benefit analysis of the Heavy Duty Engine/ Diesel Fuel standards conducted in 2000 to the Industrial, Commercial, and Institutional Boiler and Process Heater MACT discussed in this preamble. A full discussion of considerations made in our presentation of benefits is summarized in the preamble of the Final Heavy Duty Diesel Program issued in December 2000, and in all supporting documentation and analyses of the Heavy Duty Diesel Program, and in the RIA for the proposed rulemaking. In addition to the presentation of mortality valuation, our estimate also includes a `` B'' to represent those additional health and environmental benefits which could not be expressed in quantitative incidence and/ or economic value terms. A full listing of the benefit categories that could not be quantified or monetized in our estimate are provided in the RIA for the proposed rule. A full appreciation of the overall economic consequences of the proposed industrial boiler and process heater standards requires consideration of all benefits and costs expected to result from today's proposed rule, not just those benefits and costs which could be expressed here in dollar terms. A full listing of the benefit categories that could not be quantified or monetized in our estimate are provided in Table 5 of this preamble.

TABLE 5.   UNQUANTIFIED BENEFIT CATEGORIES Unquantified benefit categories associated with HAP Unquantified benefit categories associated with PM Health Categories .............................................. Airway responsiveness Pulmonary inflammation Increased susceptibility to respiratory infection Acute inflammation and respiratory cell damage Chronic respiratory damage/ Premature aging of lungs Emergency room visits for asthma Changes in pulmonary function. Morphological changes. Altered host defense mechanisms. Cancer. Other chronic respiratory disease. Emergency room visits for asthma. Emergency room visits for non asthma respiratory and cardiovascular causes. Lower and upper respiratory symptoms. Acute bronchitis. Shortness of breath. Increased school absence rates. Welfare Categories ............................................ Ecosystem and vegetation effects Damage to urban ornamentals ( e. g., grass, flowers, shrubs, and trees in urban areas) Commercial field crops Fruit and vegetable crops Reduced yields of tree seedlings, commercial and non commercial forests Damage to ecosystems Materials damage Materials damage. Damage to ecosystems ( e. g., acid sulfate deposition). Nitrates in drinking water. Visibility in recreational and residential areas.

VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00037 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1696 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules In summary, the base estimate using the VSL approach yields a total monetized benefit estimate of $ 16.1 billion + B ( 1999 dollars) in 2005 when using a 3 percent interest rate ( or approximately $ 15.4 billion + B when using a 7 percent interest rate). The alternative estimate totals approximately $ 2.4 billion + B when using a 3 percent interest rate ( or approximately $ 2.6 billion + B when using a 7 percent interest rate). Using the results of the benefit analysis, we can use benefit cost comparison ( or net benefits) as another tool to evaluate the reallocation of society's resources needed to address the pollution externality created by the operation of industrial boilers and process heaters. The additional costs of internalizing the pollution produced at major sources of emissions from industrial boilers and process heaters are compared to the improvement in society's well being from a cleaner and healthier environment. Comparing benefits of the proposed rule to the costs imposed by alternative ways to control emissions optimally identifies a strategy that results in the highest net benefit to society. In the case of the proposed rule, we are proposing only one option, the minimal level of control mandated by the CAA, or the MACT floor. Other alternatives that lead to higher levels of control ( or beyond the floor alternatives) lead to higher estimates of benefits net of costs, but also lead to additional economic impacts including more substantial impacts to small entities. For more details, please refer to the RIA for the proposed rule. Table 6 of this preamble presents a summary of costs, benefits, and net benefits ( i. e., benefits minus costs). Based on estimated compliance costs associated with the proposed rule and the predicted change in prices and production in the affected industries, the estimated social costs of the proposed rule are $ 780 million ( 1999 dollars). Social costs are different from compliance costs in that social costs take into account the interactions between affected producers and the consumers of affected products in response to the imposition of the compliance costs. Therefore, the Agency's base estimate of monetized benefits net of costs is $ 15.2 billion + B ( 1999 dollars) in 2005 when using a 3 percent discount rate ( or approximately $ 15 billion + B when using a 7 percent discount rate). However, using the more conservative alternative estimate of benefits, net benefits are $ 1.5 billion + B ( 1999 dollars) under a 3 percent discount rate ( or approximately $ 1.7 billion + B when using a 7 percent discount rate). In both cases, net benefits would be greater if all the benefits of the HAP and other pollutant reductions could be quantified. Notable omissions to the net benefits include all benefits of HAP reductions, including reduced cancer incidences, toxic morbidity effects, and cardiovascular and CNS effects. It is also important to note that not all benefits of SO2 and PM reductions have been monetized.

TABLE 6.   ANNUAL NET BENEFITS OF THE INDUSTRIAL BOILERS AND PROCESS HEATERS NESHAP IN 2005 A MACT floor ( million 1999$) Beyond the MACT floor ( million 1999$)

Social Costs B ............................................................................................................... $ 837 .......................................................... $ 1,923 Social Benefits: B, C, D HAP related health and welfare benefits ............................................................... Not monetized ........................................... Not monetized PM related welfare benefits ................................................................................... Not monetized ........................................... Not monetized SO2 ¥ and PM related health benefits: Primary Estimate   Using 3% Discount Rate .................................................................................... $ 16,300 + B .............................................. $ 17,230 + B. Using 7% Discount Rate ....................................................................................... $ 15,430 + B .............................................. $ 16,310 + B. Alternative Estimate   Using 3% Discount Rate .................................................................................... $ 2,350 + B ................................................ $ 2,380 + B.   Using 7% Discount Rate .................................................................................... $ 2,585 + B ................................................ $ 2,620 + B. Net Benefits ( Benefits ¥ Costs): C, D Primary Estimate   Using 3% Discount Rate .................................................................................... $ 15,465 ..................................................... $ 15,305 + B.   Using 7% Discount Rate .................................................................................... $ 14,595 ..................................................... $ 14,385 + B. Alternative Estimate   Using 3% Discount Rate .................................................................................... $ 1,515 ....................................................... $ 455 + B.   Using 7% Discount Rate .................................................................................... $ 1,750 ....................................................... $ 700 + B.

A All costs and benefits are rounded to the nearest $ 5 million. Thus, figures presented in this table may not exactly equal benefit and cost numbers presented in earlier sections of the chapter. B Note that costs are the total costs of reducing all pollutants, including HAP as well as SO2 and PM10. Benefits in this table are associated only with PM and SO2 reductions. C Not all possible benefits or disbenefits are quantified and monetized in this analysis. Potential benefit categories that have not been quantified and monetized are listed in Table 8   13. B is the sum of all unquantified benefits and disbenefits. D Monetized benefits are presented using two different discount rates. Results calculated using 3 percent discount rate are recommended by EPA's Guidelines for Preparing Economic Analyses ( U. S. EPA, 2000a). Results calculated using 7 percent discount rate are recommended by OMB Circular A   94 ( OMB, 1992).

V. Public Participation and Requests for Comment The ICCR Federal Advisory Committee ( i. e., the Coordinating Committee), which is discussed previously in this preamble, was designed and created to foster active participation from stakeholders, including environmental groups, regulated industries, local governments, Federal agencies, and State and local regulatory agencies. The stakeholders were able to participate in the development of FACA committee recommendations on many regulatory issues. The ICCR Coordinating Committee also encouraged the public to provide VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00038 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1697 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules input on its data and recommendations throughout the 2 year charter. To enhance the public's ability to participate, EPA maintained a bulletin board on the Technology Transfer Network to disseminate information on the ICCR Coordinating Committee and Work Group meeting schedules and minutes, works in progress, and final recommendations. The public could submit comments on any information posted on the bulletin board to members of the ICCR Coordinating Committee or Work Group. Individuals could also attend the ICCR Coordinating Committee and Work Group meetings and comment on the information being presented and discussed. After the FACA charter expired, individual stakeholders and members of the public were encourage to submit individual comments and information to EPA staff. On several occasions after the FACA charter expired, EPA met with individual stakeholder groups to discuss the status of the proposed rulemaking and to hear their concerns and comments regarding the proposed rulemaking. To continue participation of stakeholders in the rulemaking process, EPA is requesting comments and data to support the proposed rule. The EPA requests comments on all aspects of the proposed rule from all interested parties.

VI. Administrative Requirements A. Executive Order 12866, Regulatory Planning and Review Under Executive Order 12866 ( 58 FR 51735, October 4, 1993), the Agency must determine whether a regulatory action is `` significant'' and, therefore, subject to review by the Office of Management and Budget ( OMB) and the requirements of the Executive Order. The Executive Order defines `` significant regulatory action'' as one that is likely to result in a rule that may: ( 1) Have an annual effect on the economy of $ 100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities; ( 2) Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency; ( 3) Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs, or the rights and obligation of recipients thereof; or ( 4) Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order. Pursuant to the terms of Executive Order 12866, the Agency has determined that the proposed rule is a `` significant regulatory action'' because it has an annual effect on the economy of over $ 100 million. As such, this proposed action was submitted to OMB for review.

B. Executive Order 13132, Federalism Executive Order 13132 ( 64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure `` meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.'' `` Policies that have federalism implications'' is defined in the Executive Order to include regulations that have `` substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. The proposed rule does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. The agency is required by section 112 of the CAA, to establish the standards in the proposed rule. The proposed rule primarily affects private industry, and does not impose significant economic costs on State or local governments. The proposed rule does not include an express provision preempting State or local regulations. Thus, the requirements of section 6 of the Executive Order do not apply to the proposed rule. Although section 6 of Executive Order 13132 does not apply to the proposed rule, we consulted with representatives of State and local governments to enable them to provide meaningful and timely input into the development of the proposed rule. This consultation took place during the ICCR FACA committee meetings where members representing State and local governments participated in developing recommendations for EPA's combustion related rulemakings, including the proposed rule. The concerns raised by representatives of State and local governments were considered during the development of the proposed rule. In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicits comment on the proposed rule from State and local officials.

C. Executive Order 13175, Consultation and Coordination With Indian Tribal Governments Executive Order 13175 ( 65 FR 67249, November 9, 2000), requires EPA to develop an accountable process to ensure `` meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.'' The proposed rule does not have tribal implications, as specified in Executive Order 13175. The proposed rule does not significantly or uniquely affect the communities of Indian tribal governments. We do not know of any industrial commercial institutional boilers or process heaters owned or operated by Indian tribal governments. However, if there are any, the effect of the proposed rule on communities of tribal governments would not be unique or disproportionate to the effect on other communities. Thus, Executive Order 13175 does not apply to the proposed rule. The EPA specifically solicits additional comment on the proposed rule from tribal officials.

D. Executive Order 13045, Protection of Children From Environmental Health Risks and Safety Risks Executive Order 13045 ( 62 FR 19885, April 23, 1997) applies to any rule that: ( 1) Is determined to be `` economically significant'' as defined under Executive Order 12866, and ( 2) concerns an environmental health or safety risk that we have reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of the proposed rule on children, and explain why the proposed rule is preferable to other potentially effective and reasonably feasible alternatives. The EPA interprets Executive Order 13045 as applying only to those regulatory actions that are based on health or safety risks, such that the analysis required under section 5   501 of the Executive Order has the potential to influence the regulation. The proposed rule is not subject to Executive Order 13045 because it is based on technology performance and not on health or safety risks.

E. Unfunded Mandates Reform Act of 1995 Title II of the Unfunded Mandates Reform Act of 1995 ( UMRA), Pub. L.

VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00039 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1698 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules 104   4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, we generally must prepare a written statement, including a cost benefit analysis, for proposed and final rules with `` Federal mandates'' that may result in expenditures to State, local, and tribal governments, in the aggregate, or to the private sector, of $ 100 million or more in any 1 year. Before promulgating a rule for which a written statement is needed, section 205 of the UMRA generally requires us to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows us to adopt an alternative other than the least costly, most cost effective or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before we establish any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, we must develop a small government agency plan under section 203 of the UMRA. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements. We have determined that the proposed rule contains a Federal mandate that may result in expenditures of $ 100 million or more for State, local, and Tribal governments, in the aggregate, or the private sector in any 1 year. Accordingly, we have prepared a written statement entitled `` Unfunded Mandates Reform Act Analysis for the Proposed Industrial Boilers and Process Heaters NESHAP'' under section 202 of the UMRA which is summarized below.

1. Statutory Authority As discussed in section I of this preamble, the statutory authority for the proposed rulemaking is section 112 of the CAA. Title III of the CAA Amendments was enacted to reduce nationwide air toxic emissions. Section 112( b) of the CAA lists the 188 chemicals, compounds, or groups of chemicals deemed by Congress to be HAP. These toxic air pollutants are to be regulated by NESHAP. Section 112( d) of the CAA directs us to develop NESHAP which require existing and new major sources to control emissions of HAP using MACT based standards. This NESHAP applies to all industrial, commercial, and institutional boilers and process heaters located at major sources of HAP emissions. In compliance with section 205( a) of the UMRA, we identified and considered a reasonable number of regulatory alternatives. Additional information on the costs and environmental impacts of these regulatory alternatives is presented in the docket. The regulatory alternative upon which the proposed rule is based represents the MACT floor for industrial boilers and process heaters and, as a result, it is the least costly and least burdensome alternative.

2. Social Costs and Benefits The regulatory impact analysis prepared for the proposed rule including the Agency's assessment of costs and benefits, is detailed in the `` Regulatory Impact Analysis for the Proposed Industrial Boilers and Process Heaters MACT'' in the docket. Based on estimated compliance costs associated with the proposed rule and the predicted change in prices and production in the affected industries, the estimated social costs of the proposed rule are $ 780 million ( 1999 dollars). It is estimated that 5 years after implementation of the proposed rule, HAP will be reduced by 58,500 tons per year due to reductions in arsenic, beryllium, dioxin, hydrochloric acid, and several other HAP from industrial boilers and process heaters. Studies have determined a relationship between exposure to these HAP and the onset of cancer, however, there are some questions remaining on how cancers that may result from exposure to these HAP can be quantified in terms of dollars. Therefore, the Agency is unable to provide a monetized estimate of the benefits of the HAP reduced by the proposed rule at this time. However, there are significant reductions in PM and in SO2 that occur. Reductions of 560,000 tons of PM with a diameter of less than or equal to 10 micrometers ( PM10), 159,000 tons of PM with a diameter of less than or equal to 2.5 micrometers ( PM10), and 112,000 tons of SO2 are expected to occur. These reductions occur from existing sources in operation 5 years after the implementation of the regulation and are expected to continue throughout the life of the affected sources. The major health effect that results from these PM and SO2 emissions reductions is a reduction in premature mortality. Other health effects that occur are reductions in chronic bronchitis, asthma attacks, and work lost days ( i. e., days when employees are unable to work). While we are unable to monetize the benefits associated with the HAP emissions reductions, we are able to monetize the benefits associated with the PM and SO2 emissions reductions. For SO2 and PM, we estimated the benefits associated with health effects of PM but were unable to quantify all categories of benefits ( particularly those associated with ecosystem and environmental effects). Unquantified benefits are noted with `` B'' in the estimates presented below. Our base estimate of the monetized benefits in 2005 associated with the implementation of the proposed alternative is $ 16.1 billion ( 1999 dollars) when using a 3 percent discount rate ( or approximately $ 15.4 billion + B when using a 7 percent discount rate). This estimate, at a 3 percent discount rate, is about $ 15 billion ( 1999 dollars) higher than the estimated social costs shown earlier in this section. The alternative estimate of benefits is $ 2.4 billion ( 1999 dollars) when using a 3 percent discount rate ( or approximately $ 2.6 billion + B when using a 7 percent discount rate). This estimate, at a 3 percent discount rate, is about $ 1.5 billion higher than the estimated social costs. The general approach to value benefits is discussed in more detail earlier in this preamble. For more detailed information on the benefits estimated for the proposed rulemaking, refer to the RIA in the docket.

3. Future and Disproportionate Costs The Unfunded Mandates Act requires that we estimate, where accurate estimation is reasonably feasible, future compliance costs imposed by the proposed rule and any disproportionate budgetary effects. Our estimates of the future compliance costs of the proposed rule are discussed previously in this preamble. We do not believe that there will be any disproportionate budgetary effects of the proposed rule on any particular areas of the country, State or local governments, types of communities ( e. g., urban, rural), or particular industry segments. This is true for the 257 facilities owned by 54 different government bodies and is borne out by the results of the `` Economic Impact Analysis of the Proposed Industrial Boilers and Process Heaters NESHAP,''

VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00040 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1699 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules the results of which are discussed previously in this preamble.

4. Effects on the National Economy The Unfunded Mandates Act requires that we estimate the effect of the proposed rule on the national economy. To the extent feasible, we must estimate the effect on productivity, economic growth, full employment, creation of productive jobs, and international competitiveness of the U. S. goods and services, if we determine that accurate estimates are reasonably feasible and that such effect is relevant and material. The nationwide economic impact of the proposed rule is presented in the `` Economic Impact Analysis for the Industrial Boilers and Process Heaters MACT'' in the docket. This analysis provides estimates of the effect of the proposed rule on some of the categories mentioned above. The results of the economic impact analysis are summarized previously in this preamble. The results show that there will be little impact on prices and output from the affected industries, and little impact on communities that may be affected by the proposed rule. In addition, there should be little impact on energy markets ( in this case, coal, natural gas, petroleum products, and electricity). Hence, the potential impacts on the categories mentioned above should be minimal.

5. Consultation with Government Officials The Unfunded Mandates Act requires that we describe the extent of the Agency's prior consultation with affected State, local, and tribal officials, summarize the officials' comments or concerns, and summarize our response to those comments or concerns. In addition, section 203 of the UMRA requires that we develop a plan for informing and advising small governments that may be significantly or uniquely impacted by a proposal. Although the proposed rule does not affect any State, local, or Tribal governments, we have consulted with State and local air pollution control officials. We also have held meetings on the proposed rule with many of the stakeholders from numerous individual companies, environmental groups, consultants and vendors, labor unions, and other interested parties. We have added materials to the Air Docket to document these meetings. In addition, we have determined that the proposed rule contains no regulatory requirements that might significantly or uniquely affect small governments. While some small governments may have some sources affected by the proposed rule, the impacts are not expected to be significant. Therefore, today's proposed rule is not subject to the requirements of section 203 of the UMRA.

F. Regulatory Flexibility Act ( RFA), as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996 ( SBREFA), 5 U. S. C. 601 et seq.

The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions. For purposes of assessing the impacts of today's proposed rule on small entities, small entity is defined as: ( 1) A small business according to Small Business Administration ( SBA) size standards by the North American Industry Classification System category of the owning entity. The range of small business size standards for the 40 affected industries ranges from 500 to 1,000 employees, except for petroleum refining and electric utilities. In these latter two industries, the size standard is 1,500 employees and a mass throughput of 75,000 barrels/ day or less, and 4 million kilowatt hours of production or less, respectively; ( 2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and ( 3) a small organization that is any not forprofit enterprise which is independently owned and operated and is not dominant in its field. After considering the economic impact of the proposed rule on small entities, EPA certifies that this action will not have a significant impact on a substantial number of small entities. Based on SBA size definitions for the affected industries and reported sales and employment data, the Agency identified 185 of the 576 companies, or 32 percent, owning affected facilities as small businesses. Although small businesses represent 32 percent of the companies within the source category, they are expected to incur 4 percent of the total compliance costs of $ 862.7 million ( 1998 dollars). There are only ten small firms with compliance costs equal to or greater than 3 percent of their sales. In addition, there are 24 small firms with cost to sales ratios between 1 and 3 percent. An economic impact analysis was performed to estimate the changes in product price and production quantities for the proposed rule. As mentioned in the summary of economic impacts, the estimated changes in prices and output for affected firms is no more than 0.05 percent. This analysis indicates that the proposed rule should not generate a significant impact on a substantial number of small entities for following reasons. First, there are 34 small firms ( or 18 percent of all affected small firms) with compliance costs equal to or greater than 1 percent of their sales. Of these, ten small firms ( or 5 percent of all affected small firms) with compliance costs equal to or greater than 3 percent of their sales. Second, the results of the economic impact analysis show minimal impacts on prices and output from affected firms, including small entities, due to the implementation of the proposed rule. For more information, consult the docket for the proposed rule. The proposed rule will not have a significant economic impact on a substantial number of small entities as a result of several decisions EPA made regarding the development of the rule which resulted in limiting the impact of the rule on small entities. First, as mentioned earlier in this preamble, EPA identified small units ( heat input of 10 MMBtu/ hr or less) and limited use boilers ( operate less than 10 percent of the time) as separate subcategories different from large units. Many small and limited use units are located at small entities. As also discussed earlier, the results of the MACT floor analysis for these subcategories of existing sources was that no MACT floor could be identified except for the limited use solid fuel subcategory which is less stringent than the MACT floor for large units. Furthermore, the results of the beyond the floor analysis for these subcategories indicated that the costs would be too high to consider them feasible options. Consequently, the proposed rule contains no emission limitations for any of the existing small and limited use subcategories except the existing limited use solid fuel subcategory. In addition, the proposed alternative metals emission limit resulted in minimizing the impacts on small entities since some of the potential entities burning a fuel containing very little metals are small entities. We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such impacts.

VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00041 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1700 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules G. Paperwork Reduction Act The information collection requirements in the proposed rule will be submitted for approval to the Office of Management and Budget under the Paperwork Reduction Act, 44 U. S. C. 3501 et seq. An Information Collection Request ( ICR) document has been prepared by EPA ( ICR No. 2028.01) and a copy may be obtained from Susan Auby by mail at the Collection Strategies Division, U. S. Environmental Protection Agency ( 2822), 1200 Pennsylvania Avenue NW., Washington, DC 20460, by e mail at auby. susan@ epa. gov, or by calling ( 202) 566   1672. A copy may also be downloaded off the Internet at http:// www. epa. gov/ icr. The information requirements are based on notification, recordkeeping, and reporting requirements in the NESHAP General Provisions ( 40 CFR part 63, subpart A), which are mandatory for all operators subject to national emission standards. These recordkeeping and reporting requirements are specifically authorized by section 114 of the CAA ( 42 U. S. C. 7414). All information submitted to EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. The proposed rule would require maintenance inspections of the control devices but would not require any notifications or reports beyond those required by the General Provisions. The recordkeeping requirements require only the specific information needed to determine compliance. The annual monitoring, reporting, and recordkeeping burden for this collection ( averaged over the first 3 years after the effective date of the standards) is estimated to be $ 165 million. This includes 2.7 million labor hours per year at a total labor cost of $ 142 million per year, and total non labor capital costs of $ 24 million per year. This estimate includes a one time performance test, semiannual excess emission reports, maintenance inspections, notifications, and recordkeeping. Monitoring costs were also included in the cost estimates presented in the control costs impacts estimates in section IV. D of this preamble. The total burden for the Federal government ( averaged over the first 3 years after the effective date of the standard) is estimated to be 346,000 hours per year at a total labor cost of $ 14 million per year. Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information. An Agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for our regulations are listed in 40 CFR part 9 and 48 CFR chapter 15. Comments are requested on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including through the use of automated collection techniques. Send comments on the ICR to the Director, Collection Strategies Division, U. S. Environmental Protection Agency ( 2822), 1200 Pennsylvania Ave., NW., Washington, DC 20460; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th St., NW., Washington, DC 20503, marked `` Attention: Desk Officer for EPA.'' Include the ICR number in any correspondence. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after January 13, 2003, a comment to OMB is best assured of having its full effect if OMB receives it by February 12, 2003. The final rule will respond to any OMB or public comments on the information collection requirements contained in the proposed rule.

H. National Technology Transfer and Advancement Act Section 12( d) of the National Technology Transfer and Advancement Act ( NTTAA) of 1995 ( Public Law 104   113; 15 U. S. C. 272 note) directs the EPA to use voluntary consensus standards in their regulatory and procurement activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards ( e. g., materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA directs EPA to provide Congress, through annual reports to the Office of Management and Budget, with explanations when an agency does not use available and applicable voluntary consensus standards. This rulemaking involves technical standards. The EPA cites the following standards in the proposed rule: EPA Methods 1, 2, 2F, 2G, 3A, 3B, 4, 5, 5D, 17, 19, 26, 26A, 29 of 40 CFR part 60. Consistent with the NTTAA, EPA conducted searches to identify voluntary consensus standards in addition to these EPA methods. No applicable voluntary consensus standards were identified for EPA Methods 2F, 2G, 5D, and 19. The search and review results have been documented and are placed in the docket for the proposed rule. The three voluntary consensus standards described below were identified as acceptable alternatives to EPA test methods for the purposes of the proposed rule. The voluntary consensus standard ASME PTC 19   10   1981   Part 10, `` Flue and Exhaust Gas Analyses,'' is cited in the proposed rule for its manual method for measuring the oxygen, carbon dioxide, and carbon monoxide content of exhaust gas. This part of ASME PTC 19   10   1981   Part 10 is an acceptable alternative to Method 3B. The voluntary consensus standard ASTM D6522   00, `` Standard Test Method for the Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas Fired Reciprocating Engines, Combustion Turbines, Boilers and Process Heaters Using Portable Analyzers'' is an acceptable alternative to EPA Method 3A for identifying carbon monoxide and oxygen concentrations for the proposed rule when the fuel is natural gas. The voluntary consensus standard ASTM Z65907, `` Standard Method for Both Speciated and Elemental Mercury Determination,'' is an acceptable alternative to EPA Method 29 ( portion for mercury only) for the purpose of the proposed rule. This standard can be used in the proposed rule to determine the mercury concentration in stack gases for boilers with rated heat input capacities of greater than 250 MMBtu per hour. In addition to the voluntary consensus standards EPA uses in the proposed rule, the search for emissions measurement procedures identified 15 other voluntary consensus standards.

VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00042 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1701 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules The EPA determined that 13 of these 15 standards identified for measuring emissions of the HAP or surrogates subject to emission standards in the proposed rule were impractical alternatives to EPA test methods for the purposes of the rule. Therefore, EPA does not intend to adopt these standards for this purpose. The reasons for this determination for the 13 methods are discussed below. The voluntary consensus standard ASTM D3154   00, `` Standard Method for Average Velocity in a Duct ( Pitot Tube Method),'' is impractical as an alternative to EPA Methods 1, 2, 3B, and 4 for the purposes of the proposed rulemaking since the standard appears to lack in quality control and quality assurance requirements. Specifically, ASTM D3154   00 does not include the following: ( 1) Proof that openings of standard pitot tube have not plugged during the test; ( 2) if differential pressure gauges other than inclined manometers ( e. g., magnehelic gauges) are used, their calibration must be checked after each test series; and ( 3) the frequency and validity range for calibration of the temperature sensors. The voluntary consensus standard ASTM D3464   96 ( 2001), `` Standard Test Method Average Velocity in a Duct Using a Thermal Anemometer,'' is impractical as an alternative to EPA Method 2 for the purposes of the proposed rule primarily because applicability specifications are not clearly defined, e. g., range of gas composition, temperature limits. Also, the lack of supporting quality assurance data for the calibration procedures and specifications, and certain variability issues that are not adequately addressed by the standard limit EPA's ability to make a definitive comparison of the method in these areas. The voluntary consensus standard ISO 10780: 1994, `` Stationary Source Emissions Measurement of Velocity and Volume Flow Rate of Gas Streams in Ducts,'' is impractical as an alternative to EPA Method 2 in the proposed rule. The standard recommends the use of an L shaped pitot, which historically has not been recommended by EPA. The EPA specifies the S type design which has large openings that are less likely to plug up with dust. The voluntary consensus standard, CAN/ CSA Z223.2   M86 ( 1999), `` Method for the Continuous Measurement of Oxygen, Carbon Dioxide, Carbon Monoxide, Sulphur Dioxide, and Oxides of Nitrogen in Enclosed Combustion Flue Gas Streams,'' is unacceptable as a substitute for EPA Method 3A since it does not include quantitative specifications for measurement system performance, most notably the calibration procedures and instrument performance characteristics. The instrument performance characteristics that are provided are nonmandatory and also do not provide the same level of quality assurance as the EPA methods. For example, the zero and span/ calibration drift is only checked weekly, whereas the EPA methods requires drift checks after each run. Two very similar voluntary consensus standards, ASTM D5835   95 ( 2001), `` Standard Practice for Sampling Stationary Source Emissions for Automated Determination of Gas Concentration,'' and ISO 10396: 1993, `` Stationary Source Emissions: Sampling for the Automated Determination of Gas Concentrations,'' are impractical alternatives to EPA Method 3A for the purposes of the proposed rule because they lack in detail and quality assurance/ quality control requirements. Specifically, these two standards do not include the following: ( 1) Sensitivity of the method; ( 2) acceptable levels of analyzer calibration error; ( 3) acceptable levels of sampling system bias; ( 4) zero drift and calibration drift limits, time span, and required testing frequency; ( 5) a method to test the interference response of the analyzer; ( 6) procedures to determine the minimum sampling time per run and minimum measurement time; and ( 7) specifications for data recorders, in terms of resolution ( all types) and recording intervals ( digital and analog recorders, only). The voluntary consensus standard ISO 12039: 2001, `` Stationary Source Emissions   Determination of Carbon Monoxide, Carbon Dioxide, and Oxygen   Automated Methods,'' is not acceptable as an alternative to EPA Method 3A. This ISO standard is similar to EPA Method 3A, but is missing some key features. In terms of sampling, the hardware required by ISO 12039: 2001 does not include a 3 way calibration valve assembly or equivalent to block the sample gas flow while calibration gases are introduced. In its calibration procedures, ISO 12039: 2001 only specifies a two point calibration while EPA Method 3A specifies a three point calibration. Also, ISO 12039: 2001 does not specify performance criteria for calibration error, calibration drift, or sampling system bias tests as in the EPA method, although checks of these quality control features are required by the ISO standard. The voluntary consensus standard ASME PTC   38   80 R85 ( 1985), `` Determination of the Concentration of Particulate Matter in Gas Streams,'' is not acceptable as an alternative for EPA Method 5 because ASTM PTC   38   80 is not specific about equipment requirements, and instead presents the options available and the pro's and con's of each option. The key specific differences between ASME PTC   38   80 and the EPA methods are that the ASME standard: ( 1) Allows in stack filter placement as compared to the out ofstack filter placement in EPA Methods 5 and 17; ( 2) allows many different types of nozzles, pitots, and filtering equipment; ( 3) does not specify a filter weighing protocol or a minimum allowable filter weight fluctuation as in the EPA methods; and ( 4) allows filter paper to be only 99 percent efficient, as compared to the 99.95 percent efficiency required by the EPA methods. The voluntary consensus standard ASTM D3685/ D3685M   98, `` Test Methods for Sampling and Determination of Particulate Matter in Stack Gases,'' is similar to EPA Methods 5 and 17, but is lacking in the following areas that are needed to produce quality, representative particulate data: ( 1) Requirement that the filter holder temperature should be between 120 ° C and 134 ° C, and not just `` above the acid dew point;'' ( 2) detailed specifications for measuring and monitoring the filter holder temperature during sampling; ( 3) procedures similar to EPA Methods 1, 2, 3, and 4, that are required by EPA Method 5; ( 4) technical guidance for performing the Method 5 sampling procedures, e. g., maintaining and monitoring sampling train operating temperatures, specific leak check guidelines and procedures, and use of reagent blanks for determining and subtracting background contamination; and ( 5) detailed equipment and/ or operational requirements, e. g., component exchange leak checks, use of glass cyclones for heavy particulate loading and/ or water droplets, operating under a negative stack pressure, exchanging particulate loaded filters, sampling preparation and implementation guidance, sample recovery guidance, data reduction guidance, and particulate sample calculations input. The voluntary consensus standard ISO 9096: 1992, `` Determination of Concentration and Mass Flow Rate of Particulate Matter in Gas Carrying Ducts   Manual Gravimetric Method,'' is not acceptable as an alternative for EPA Method 5. Although sections of ISO 9096 incorporate EPA Methods 1, 2, and 5 to some degree, this ISO standard is not equivalent to EPA Method 5 for collection of particulate matter. The standard ISO 9096 does not provide applicable technical guidance for performing many of the integral VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00043 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1702 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules procedures specified in Methods 1, 2, and 5. Major performance and operational details are lacking or nonexistent, and detailed quality assurance/ quality control guidance for the sampling operations required to produce quality, representative particulate data ( e. g., guidance for maintaining and monitoring train operating temperatures, specific leak check guidelines and procedures, and sample preparation and recovery procedures) are not provided by the standard, as in EPA Method 5. Also, details of equipment and/ or operational requirements, such as those specified in EPA Method 5, are not included in the ISO standard, e. g., stack gas moisture measurements, data reduction guidance, and particulate sample calculations. The voluntary consensus standard CAN/ CSA Z223.1   M1977, `` Method for the Determination of Particulate Mass Flows in Enclosed Gas Streams,'' is not acceptable as an alternative for EPA Method 5. Detailed technical procedures and quality control measures that are required in EPA Methods 1, 2, 3, and 4 are not included in CAN/ CSA Z223.1. Second, CAN/ CSA Z223.1 does not include the EPA Method 5 filter weighing requirement to repeat weighing every 6 hours until a constant weight is achieved. Third, EPA Method 5 requires the filter weight to be reported to the nearest 0.1 mg, while CAN/ CSA Z223.1 requires only to the nearest 0.5 mg. Also, CAN/ CSA Z223.1 allows the use of a standard pitot for velocity measurement when plugging of the tube opening is not expected to be a problem. Whereas, EPA Method 5 requires an S shaped pitot. The voluntary consensus standard EN 1911   1,2,3 ( 1998), `` Stationary Source Emissions   Manual Method of Determination of HCl   Part 1: Sampling of Gases Ratified European Text   Part 2: Gaseous Compounds Absorption Ratified European Text   Part 3: Adsorption Solutions Analysis and Calculation Ratified European Text,'' is impractical as an alternative to EPA Methods 26 and 26A. Part 3 of this standard cannot be considered equivalent to EPA Method 26 or 26A because the sample absorbing solution ( water) would be expected to capture both HCl and chlorine gas, if present, without the ability to distinguish between the two. The EPA Methods 26 and 26A use an acidified absorbing solution to first separate HCl and chlorine gas so that they can be selectively absorbed, analyzed, and reported separately. In addition, in EN 1911 the absorption efficiency for chlorine gas would be expected to vary as the pH of the water changed during sampling. The voluntary consensus standard EN 13211 ( 1998), is not acceptable as an alternative to the mercury portion of EPA Method 29 primarily because it is not validated for use with impingers, as in the EPA method, although the method describes procedures for the use of impingers. This European standard is validated for the use of fritted bubblers only and requires the use of a side ( split) stream arrangement for isokinetic sampling because of the low sampling rate of the bubblers ( up to 3 liters per minute, maximum). Also, only two bubblers ( or impingers) are required by EN 13211, whereas EPA Method 29 require the use of six impingers. In addition, EN 13211 does not include many of the quality control procedures of EPA Method 29, especially for the use and calibration of temperature sensors and controllers, sampling train assembly and disassembly, and filter weighing. Two of the 15 voluntary consensus standards identified in this search were not available at the time the review was conducted for the purposes of the proposed rule because they are under development by a voluntary consensus body: ASME/ BSR MFC 13M, `` Flow Measurement by Velocity Traverse,'' for EPA Method 2 ( and possibly 1); and ASME/ BSR MFC 12M, `` Flow in Closed Conduits Using Multiport Averaging Pitot Primary Flowmeters,'' for EPA Method 2. Section 63.7520 and Tables 4A through 4D to subpart DDDDD, 40 CFR part 63, list the EPA testing methods included in the proposed rule. Under § 63.7( f) and § 63.8( f) of subpart A of the General Provisions, a source may apply to EPA for permission to use alternative test methods or alternative monitoring requirements in place of any of the EPA testing methods, performance specifications, or procedures.

I. Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use Executive Order 13211, ( 66 FR 28355, May 22, 2001), provides that agencies shall prepare and submit to the Administrator of the Office of Information and Regulatory Affairs, Office of Management and Budget, a Statement of Energy Effects for certain actions identified as significant energy actions. Section 4( b) of Executive Order 13211 defines `` significant energy actions'' as `` any action by an agency ( normally published in the Federal Register) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: ( 1)( i) that is a significant regulatory action under Executive Order 12866 or any successor order, and ( ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or ( 2) that is designated by the Administrator of the Office of Information and Regulatory Affairs as a significant energy action.'' The proposed rule is not a `` significant regulatory action'' because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. The basis for the determination is as follows. The reduction in petroleum product output, which includes reductions in fuel production, is estimated at only 0.001 percent, or about 68 barrels per day based on 2000 U. S. fuel production nationwide. That is a minimal reduction in nationwide petroleum product output. The reduction in coal production is estimated at only 0.014 percent, or about 3.5 million tons per year ( or less than 1,000 tons per day) based on 2000 U. S. coal production nationwide. The combination of the increase in electricity usage estimated in section IV. C of this preamble with the effect of the increased price of affected output yields an increase in electricity output estimated at only 0.012 percent, or about 0.72 billion kilowatt hours per year based on 2000 U. S. electricity production nationwide. All energy price changes estimated show no increase in price more than 0.05 percent nationwide, and a similar result occurs for energy distribution costs. We also expect that there will be no discernable impact on the import of foreign energy supplies, and no other adverse outcomes are expected to occur with regards to energy supplies. All of the results presented above account for the pass through of costs to consumers, as well as the cost impact to producers. For more information on the estimated energy effects, please refer to the economic impact analysis for the proposed rule. The analysis is available in the public docket. Therefore, we conclude that the proposed rule when implemented is not likely to have a significant adverse effect on the supply, distribution, or use of energy.

List of Subjects in 40 CFR Part 63 Environmental protection, Administrative practice and procedure, Air pollution control, Hazardous substances, Intergovernmental relations, Reporting and recordkeeping requirements.

VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00044 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1703 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules Dated: November 26, 2002. Christine Todd Whitman, Administrator.

For the reasons stated in the preamble, title 40, chapter I, part 63 of the Code of the Federal Regulations is proposed to be amended as follows:

PART 63   [ AMENDED]

1. The authority citation for part 63 continues to read as follows:

Authority: 42 U. S. C. 7401, et seq.

2. Part 63 is amended by adding subpart DDDDD to read as follows:

Subpart DDDDD   National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters What This Subpart Covers Sec. 63.7480 What is the purpose of this subpart? 63.7485 Am I subject to this subpart? 63.7490 What parts of my facility does this subpart cover? 63.7495 When do I have to comply with this subpart?

Emission Limitations and Work Practice Standards 63.7500 What emission limitations and work practice standards must I meet?

General Compliance Requirements 63.7505 What are my general requirements for complying with this subpart?

Testing and Initial Compliance Requirements 63.7510 By what date must I conduct performance tests or other initial compliance demonstrations? 63.7515 When must I conduct subsequent performance tests? 63.7520 What performance tests, design evaluations, and other procedures must I use? 63.7525 What are my monitoring, installation, operation, and maintenance requirements? 63.7530 How do I demonstrate initial compliance with the emission limitations and work practice standards?

Continuous Compliance Requirements 63.7535 How do I monitor and collect data to demonstrate continuous compliance? 63.7540 How do I demonstrate continuous compliance with the emission limitations and work practice standards?

Notifications, Reports, and Records 63.7545 What notifications must I submit and when? 63.7550 What reports must I submit and when? 63.7555 What records must I keep? 63.7560 In what form and how long must I keep my records?

Other Requirements and Information 63.7565 What parts of the General Provisions apply to me? 63.7570 Who implements and enforces this subpart? 63.7575 What definitions apply to this subpart?

Tables to Subpart DDDDD of Part 63 Table 1 to Subpart DDDDD of Part 63   Emission Limits Table 2. A to Subpart DDDDD of Part 63   Operating Limits for Boilers and Process Heaters in the Large, Limited Use, or Small Solid Fuel Subcategories Table 2. B to Subpart DDDDD of Part 63   Operating Limits for Boilers and Process Heaters in the Large, Limited Use, or Small Liquid Fuel Subcategories Table 3 to Subpart DDDDD of Part 63   Work Practice Standards Table 4. A to Subpart DDDDD of Part 63   Requirements for Performance Tests for Particulate Matter Emissions or Total Selected Metals Emissions from Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel Subcategories Table 4. B to Subpart DDDDD of Part 63   Requirements for Performance Tests for Particulate Matter Emissions from Boilers or Process Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories Table 4. C to Subpart DDDDD of Part 63   Requirements for Performance Tests for Hydrogen Chloride Emissions from Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel Subcategories Table 4. D to Subpart DDDDD of Part 63   Requirements for Performance Tests for Hydrogen Chloride Emissions from Boilers or Process Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories Table 4. E to Subpart DDDDD of Part 63   Requirements for Performance Tests for Mercury Emissions from Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel Subcategories Table 5. A to Subpart DDDDD of Part 63   Initial Compliance With Emission Limitations for Particulate Matter or Total Selected Metals for Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel Subcategories Table 5. B to Subpart DDDDD of Part 63   Initial Compliance With Emission Limitations for Particulate Matter for Boilers or Process Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories Table 5. C to Subpart DDDDD of Part 63   Initial Compliance With Emission Limitations for Hydrogen Chloride for Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel Subcategories Table 5. D to Subpart DDDDD of Part 63   Initial Compliance With Emission Limitations for Hydrogen Chloride for Boilers or Process Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories Table 5. E to Subpart DDDDD of Part 63   Initial Compliance With Emission Limitations for Mercury for Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel, Subcategories Table 6 to Subpart DDDDD of Part 63   Initial Compliance with Work Practice Standards Table 7. A to Subpart DDDDD of Part 63   Continuous Compliance with Emission Limitations for Boilers or Process Heaters in Large, Limited Use, or Small Solid Fuel Subcategories Table 7. B to Subpart DDDDD of Part 63   Continuous Compliance with Emission Limitations for Boilers or Process Heaters in Large, Limited Use, or Small Liquid Fuel Subcategories Table 8 to Subpart DDDDD of Part 63   Continuous Compliance with Work Practice Standards Table 9 to Subpart DDDDD of Part 63   Requirements for Reports Table 10 to Subpart DDDDD of Part 63   Applicability of General Provisions to Subpart DDDDD Subpart DDDDD   National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters What This Subpart Covers § 63.7480 What is the purpose of this subpart?

This subpart establishes national emission limitations and work practice standards for hazardous air pollutants emitted from industrial, commercial, and institutional boilers and process heaters. This subpart also establishes requirements to demonstrate initial and continuous compliance with the emission limitations and work practice standards.

§ 63.7485 Am I subject to this subpart?

You are subject to this subpart if you own or operate an industrial, commercial, or institutional boiler or process heater that is located at, or is part of, a major source of hazardous air pollutants ( HAP) emissions, except as specifically exempted in § 63.7490. ( a) An industrial, commercial, or institutional boiler is an enclosed device using controlled flame combustion and having the primary purpose of recovering thermal energy in the form of steam or hot water. Waste heat boilers are excluded. A process heater is an enclosed device using controlled flame with the unit's primary purpose being to transfer heat indirectly to process streams ( liquids, gases, or solids) instead of generating steam. ( b) A major source of HAP emissions is any stationary source or group of stationary sources located within a contiguous area and under common control that emits or has the potential to emit any single HAP at a rate of 9.07 megagrams ( 10 tons) or more per year or any combination of HAP at a rate of VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00045 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1704 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules 22.68 megagrams ( 25 tons) or more per year.

§ 63.7490 What parts of my facility does this subpart cover?

( a) This subpart applies to each new, reconstructed, or existing affected source. ( b) The affected source is each industrial, commercial, or institutional boiler or process heater, as defined in § 63.7485 that is not one of the types of combustion units listed in § 63.7490( b)( 1) through ( 10). ( 1) A municipal waste combustor covered by 40 CFR part 60, subpart AAAA, subpart BBBB, subpart Eb or subpart Cb. ( 2) A hospital/ medical/ infectious waste incinerator covered by 40 CFR part 60, subpart Ce or subpart Ec. ( 3) An electric utility steam generating unit that is a fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale is considered an electric utility steam generating unit. ( 4) A boiler or process heater required to have a permit under section 3005 of the Solid Waste Disposal Act or covered by 40 CFR part 63, subpart EEE ( e. g., hazardous waste combustors). ( 5) A commercial and industrial solid waste incineration unit covered by 40 CFR part 60, subpart CCCC or subpart DDDD. ( 6) A recovery boiler or furnace covered by 40 CFR part 63, subpart MM. ( 7) A boiler or process heater that is used specifically for research and development. This does not include units that only provide steam to a process at a research and development facility. ( 8) A hot water heater as defined in this subpart. ( 9) A refining kettle covered by 40 CFR part 63, subpart X. ( 10) An ethylene cracking furnace covered by 40 CFR part 63, subpart YY. ( c) An affected source is a new affected source if you commenced construction of the affected source after January 13, 2003 and you meet the applicability criteria at the time you commenced construction. ( d) An affected source is reconstructed if you meet the criteria as defined in § 63.2. ( e) An affected source is existing if it is not new or reconstructed. § 63.7495 When do I have to comply with this subpart?

( a) If you have a new or reconstructed affected source, you must comply with this subpart according to paragraph ( a)( 1) or ( 2) of this section. ( 1) If you start up your affected source before [ DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER], then you must comply with the emission limitations and work practice standards for new and reconstructed sources in this subpart no later than [ DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER]. ( 2) If you startup your affected source after [ DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER], then you must comply with the emission limitations and work practice standards for new and reconstructed sources in this subpart upon startup of your affected source. ( b) If you have an existing affected source, you must comply with the emission limitations for existing sources no later than 3 years after [ DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER]. ( c) If you have an area source that increases its emissions or its potential to emit such that it becomes a major source of HAP, paragraphs ( c)( 1) and ( 2) of this section apply to you. ( 1) Any new or reconstructed boiler or process heater at the existing facility must be in compliance with this subpart upon startup. ( 2) Any existing boiler or process heater at the existing facility must be in compliance with this subpart within 3 years after the facility becomes a major source. ( d) You must meet the notification requirements in § 63.7545 according to the schedule in § 63.7545 and in subpart A of this part. Some of the notifications must be submitted before you are required to comply with the emission limitations and work practice standards in this subpart.

Emission Limitations and Work Practice Standards § 63.7500 What emission limitations and work practice standards must I meet?

( a) You must meet the requirements in paragraphs ( a)( 1) through ( 3) of this section. ( 1) You must meet each emission limit in Table 1 to this subpart that applies to you. ( 2) You must meet each operating limit in Tables 2. A and 2. B to this subpart that applies to you. If you use a control device or combination of control devices not covered in Tables 2. A or 2. B to this subpart, or you wish to establish and monitor an alternative operating limit and alternative monitoring parameters, you must apply to the Administrator for approval of alternative monitoring under § 63.8( f). ( 3) You must meet each work practice standard in Table 3 to this subpart that applies to you. ( b) If your new or reconstructed boiler or process heater is in one of the liquid fuel subcategories ( the large liquid fuel subcategory, the limited use liquid fuel subcategory, or the small liquid fuel subcategory) and burns only fossil fuels and other gases and does not burn any residual oil, you are subject to the emission limits in Table 1 to this subpart, but you are not required to conduct a performance test to demonstrate compliance with the emission limits. However, you must meet all applicable requirements in § § 63.7530 and 63.7535. ( c) As provided in § 63.6( g), the Environmental Protection Agency ( EPA) may choose to grant you permission to use an alternative to the work practice standards in this section.

General Compliance Requirements § 63.7505 What are my general requirements for complying with this subpart? ( a) You must be in compliance with the emission limitations ( including operating limits) and the work practice standards in this subpart at all times, except during periods of startup, shutdown, and malfunction. ( b) You must always operate and maintain your affected source, including air pollution control and monitoring equipment, according to the provisions in § 63.6( e)( 1)( i). ( c) You must develop a site specific monitoring plan according to the requirements in paragraphs ( c)( 1) through ( 4) of this section. ( 1) For each monitoring system required in this section, you must develop and submit for approval a sitespecific monitoring plan that addresses paragraphs ( c)( 1)( i) through ( iii) of this section. ( i) Installation of the continuous monitoring system ( CMS) sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement is representative of control of the exhaust emissions ( e. g., on or downstream of the last control device); ( ii) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems; and VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00046 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1705 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules ( iii) Performance evaluation procedures and acceptance criteria ( e. g., calibrations). ( 2) In your site specific monitoring plan, you must also address paragraphs ( c)( 2)( i) through ( iii) of this section. ( i) Ongoing operation and maintenance procedures in accordance with the general requirements of § 63.8( c)( 1), ( c)( 3), and ( c)( 4)( ii); ( ii) Ongoing data quality assurance procedures in accordance with the general requirements of § 63.8( d); and ( iii) Ongoing recordkeeping and reporting procedures in accordance with the general requirements of § 63.10( c), ( e)( 1) and ( e)( 2)( i). ( 3) You must conduct a performance evaluation of each CMS in accordance with your site specific monitoring plan. ( 4) You must operate and maintain the CMS in continuous operation according to the site specific monitoring plan. ( d) You must develop and implement a written startup, shutdown, and malfunction plan ( SSMP) according to the provisions in § 63.6( e)( 3).

Testing and Initial Compliance Requirements § 63.7510 By what date must I conduct performance tests or other initial compliance demonstrations?

( a) For each existing affected source, you must conduct performance tests, set operating limits, and conduct monitoring equipment performance evaluations by the compliance date that is specified for your source in § 63.7495 and according to the applicable provisions in § 63.7( a)( 2) as cited in Table 10 to this subpart. ( b) For each new or reconstructed affected source, you must conduct performance tests, set operating limits, and conduct monitoring equipment performance evaluations within 180 calendar days after the compliance date that is specified for your source in § 63.7495 and according to the provisions in § 63.7( a)( 2) as cited in Table 10 to this subpart.

§ 63.7515 When must I conduct subsequent performance tests?

( a) You must conduct all applicable performance tests according to the procedures in § 63.7520 on an annual basis unless you follow the requirements listed in paragraphs ( b) through ( h) of this section. The first subsequent performance tests must be completed within 12 months of the initial performance test but no earlier than 10 months after the initial performance test and every 12 months thereafter, unless you follow the requirements listed in paragraphs ( b) through ( h) of this section. ( b) You can conduct performance tests less often for a given pollutant if you have test data for at least 3 years, and all stack tests for the pollutant ( particulate matter, hydrogen chloride, mercury, or total selected metals) for over 3 consecutive years show that you comply with the emission limit. In this case, you do not have to conduct a stack test for that pollutant for the next 2 years. You must do a stack test during the third year and no more than 36 months following the previous stack test. ( c) If your boiler or process heater continues to meet the emission limit for particulate matter, hydrogen chloride, mercury, or total selected metals, you may choose to conduct stack tests for these pollutants every third year, but each such test must be within 36 months of the previous stack test. ( d) If a stack test shows noncompliance with an emission limit for particulate matter, hydrogen chloride, mercury, or total selected metals, you must conduct annual stack tests for that pollutant until all stack tests over a 3 year period show compliance. ( e) You are not required to conduct a performance test for total selected metals annually if you choose to comply with the alternative total selected metals emission limit instead of particulate matter, and your operating limit is the total selected metals fuel input. You must still meet all applicable continuous compliance requirements in § 63.7540. ( f) You are not required to conduct a performance test for hydrogen chloride annually if your operating limit for hydrogen chloride is chlorine fuel input. You must still meet all applicable continuous compliance requirements in § 63.7540. ( g) You are not required to conduct a performance test for mercury annually if your operating limit for mercury is mercury fuel input. You must still meet all applicable continuous compliance requirements in § 63.7540. ( h) You must report the results of annual performance tests within 60 days after the completion of the tests. This report should also verify that the operating limits for your affected source have not changed or provide documentation of revised operating parameters established as specified in Tables 4. A through 4. E to this subpart. The reports for all subsequent performance tests should include all applicable information required in § 63.7550. § 63.7520 What performance tests, design evaluations, and other procedures must I use?

( a) You must conduct all performance tests according to § 63.7( c), ( d), ( f), and ( h). You must also develop a sitespecific test plan according to the requirements in § 63.7( c). ( b) You must conduct each performance test in Tables 4. A through 4. E to this subpart that applies to you. ( c) For boilers or process heaters in one of the liquid fuel subcategories that burn only fossil fuels and other gases and do not burn any residual oil, you are not required to conduct a performance test to demonstrate compliance with the emission limits. ( d) You must conduct each performance test under the specific conditions listed in Tables 4. A through 4. E to this subpart. You must conduct performance tests at the representative process operating conditions that are expected to result in the highest emissions of hydrogen chloride, particulate matter, and mercury, and you must demonstrate initial compliance and establish your operating limits based on this test. This requirement could result in the need to conduct more than one performance test. If you choose to comply with the alternative total selected metals emission limit instead of particulate matter, you must conduct all performance tests at the representative process operating conditions that are expected to result in the highest emissions of hydrogen chloride, total selected metals and mercury. ( e) You may not conduct performance tests during periods of startup, shutdown, or malfunction. ( f) You must conduct three separate test runs for each performance test required in this section, as specified in § 63.7( e)( 3). Each test run must last at least 1 hour. ( g) To determine compliance with the emission limits, you must use the FFactor methodology and equations in sections 12.2 and 12.3 of EPA Method 19 of appendix A of this part to convert the measured particulate matter concentrations, the measured hydrogen chloride concentrations, the measured total selected metals concentrations, and the measured mercury concentrations that result from the initial performance test to pound per million British thermal unit ( MMBtu) heat input emission rates. Method 26A of appendix A of this part must be used for the hydrogen chloride performance test for those boilers and process heaters with wet scrubbers. All other boilers and process heaters must use Method 26 of VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00047 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1706 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules appendix A of this part for the hydrogen chloride performance test. ( h) For performance tests using Method 5, Method 29, Method 26A and Method 17 of appendix A of this part, use Method 1 of appendix A of this part to select the sampling location and number of traverse points. For Method 26 of appendix A of this part, you must use a minimum of three traverse points. ( i) If you use a control device or combination of control devices not covered in Tables 4. A through 4. E to this subpart, or you wish to establish and monitor an alternative operating limit, you must apply to the Administrator for approval of alternative monitoring under § 63.8( f).

§ 63.7525 What are my monitoring, installation, operation, and maintenance requirements?

( a) Each continuous emissions monitoring system ( CEMS) for carbon monoxide must be installed, operated, and maintained according to the procedures in paragraphs ( a)( 1) through ( 4) of this section by the compliance date. ( 1) Each CEMS must be installed, operated, and maintained according to Performance Specification ( PS) 4A of 40 CFR part 60, appendix B, and according to the site specific monitoring plan developed according to § 63.7505( c). ( 2) You must conduct a performance evaluation of each CEMS according to the requirements in § 63.8 and according to PS 4A of 40 CFR part 60, appendix B. ( 3) Each CEMS must complete a minimum of one cycle of operation ( sampling, analyzing, and data recording) for each successive 15 minute period. ( 4) The CEMS data must be reduced as specified in § 63.8( g)( 2). ( b) Each continuous opacity monitoring system ( COMS) must be installed, operated, certified and maintained according to the procedures in paragraphs ( b)( 1) through ( 7) of this section by the compliance date. ( 1) Each COMS must be installed, operated, and maintained according to PS 1 of 40 CFR part 60, appendix B. ( 2) You must conduct a performance evaluation of each COMS according to the requirements in § 63.8 and according to PS 1 of 40 CFR part 60, appendix B. ( 3) As specified in § 63.8( c)( 4)( i), each COMS must complete a minimum of one cycle of sampling and analyzing for each successive 10 second period and one cycle of data recording for each successive 6 minute period. ( 4) The COMS data must be reduced as specified in § 63.8( g)( 2). ( 5) You must include in your sitespecific monitoring plan procedures and acceptance criteria for operating and maintaining each COMS according to the requirements in § 63.8( d). At a minimum, the monitoring plan must include a daily calibration drift assessment, a quarterly performance audit, and an annual zero alignment audit of each COMS. ( 6) You must operate and maintain each COMS according to the requirements in the monitoring plan and the requirements of § 63.8( e). Identify periods the COMS is out ofcontrol including any periods that the COMS fails to pass a daily calibration drift assessment, a quarterly performance audit, or an annual zero alignment audit. ( 7) You must determine and record all the 6 minute averages and 3 hour block averages collected for periods during which the COMS is not out of control. ( c) You must install, operate, and maintain each continuous parameter monitoring system ( CPMS) according to the requirements in § 63.8 and the procedures in paragraphs ( c)( 1) through ( 5) of this section by the compliance date specified in § 63.7495. ( 1) The CPMS must complete a minimum of one cycle of operation for each successive 15 minute period. You must have a minimum of four successive cycles of operation to have a valid hour of data. ( 2) Except for, monitoring malfunctions, associated repairs and required quality assurance or control activities ( including, as applicable, calibration checks and required zero and span adjustments), you must conduct all monitoring in continuous operation at all times that the unit is operating. A monitoring malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring failures that are caused in part by poor maintenance or careless operation are not malfunctions. ( 3) For purposes of calculating data averages, you must not use data recorded during monitoring malfunctions, associated repairs, out ofcontrol periods, or required quality assurance or control activities. You must use all the data collected during all other periods in assessing compliance. Any period for which the monitoring system is out of control and data are not available for required calculations constitutes a deviation from the monitoring requirements. ( 4) Determine the 3 hour block average of all recorded readings, except as provided in paragraph ( c)( 3) of this section. ( 5) Record the results of each inspection, calibration, and validation check. ( d) For the equipment to monitor voltage and secondary current ( or total power input) of the electrostatic precipitator ( ESP), you must meet the requirements in paragraphs ( c) and ( d)( 1) and ( 2) of this section. ( 1) Use the ESP manufacturer's installed voltage and secondary current monitoring equipment to measure voltage and secondary current to the ESP. ( 2) At least monthly, inspect all components of the CPMS for integrity and all electrical connections for continuity. ( e) For the equipment to monitor sorbent injection rate ( e. g., weigh belt, weigh hopper, or hopper flow measurement device), you must meet the requirements in paragraphs ( c) and ( e)( 1) through ( 4) of this section. ( 1) Locate the device in a position( s) that provides a representative measurement of the total sorbent injection rate. ( 2) Install and calibrate the device in accordance with manufacturer's procedures and specifications. ( 3) At least monthly, inspect all components for integrity and all electrical connections for continuity. ( 4) At least annually, calibrate the device in accordance with the manufacturer's procedures and specifications. ( f) If you use a fabric filter to comply with the requirements of this subpart, you must install, calibrate, maintain, and continuously operate a bag leak detection system as specified in paragraphs ( f)( 1) through ( 8) of this section. ( 1) You must install and operate a bag leak detection system for each exhaust stack of the fabric filter. ( 2) Each bag leak detection system must be installed, operated, calibrated, and maintained in a manner consistent with the manufacturer's written specifications and recommendations and in accordance with the guidance provided in `` Fabric Filter Bag Leak Detection Guidance,'' EPA   454/ R   98   015, September 1997. ( 3) The bag leak detection system must be certified by the manufacturer to be capable of detecting particulate matter emissions at concentrations of 10 milligrams per actual cubic meter or less. ( 4) The bag leak detection system sensor must provide output of relative or absolute particulate matter loadings. ( 5) The bag leak detection system must be equipped with a device to VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00048 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 1707 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules continuously record the output signal from the sensor. ( 6) The bag leak detection system must be equipped with an alarm system that will sound automatically when an increase in relative particulate matter emissions over a preset level is detected. The alarm must be located where it is easily heard by plant operating personnel. ( 7) For positive pressure fabric filter systems, a bag leak detection system must be installed in each baghouse compartment or cell. For negative pressure or induced air fabric filters, the bag leak detector must be installed downstream of the fabric filter. ( 8) Where multiple detectors are required, the system's instrumentation and alarm may be shared among detectors.

§ 63.7530 How do I demonstrate initial compliance with the emission limitations and work practice standards?

( a) You must demonstrate initial compliance with each emission limitation and work practice standard that applies to you according to Tables 5. A through 5. E and 6 to this subpart. ( b) For new or reconstructed boilers or process heaters in one of the liquid fuel subcategories that burn only fossil fuels and other gases and do not burn any residual oil, you are not required to conduct a performance test to demonstrate compliance with the emission limits. ( 1) To demonstrate initial compliance, you must include a signed statement in the Notification of Compliance Status report required in § 63.7545( e) that indicates you burn only liquid fossil fuels other than residual oils either alone or in combination with gaseous fuels. ( 2) You must also keep records, as required in § 63.7555, that demonstrate that you burn only liquid fossil fuels other than residual oils either alone or in combination with gaseous fuels. ( c) You must establish each sitespecific operating limit in Tables 2. A and 2. B to this subpart that applies to you according to the requirements in § 63.7520, Tables 4. A through 4. E to this subpart, and paragraphs ( c)( 1) through ( 6) of this section, as applicable. ( 1) If you do not use a wet or dry scrubber, you must set your operating limit for hydrogen chloride emissions based on the chlorine fuel input established during the initial performance test according to the procedures in paragraphs ( c)( 1)( i) and ( ii) of this section. ( i) During the initial performance test for hydrogen chloride, you must measure the average hourly fuel input, average chlorine concentration, and average heat input of each fuel burned during the 3 hour performance test. ( ii) You must set your operating limit for hydrogen chloride using Equation 1 of this section:

Cl C Q H ( Eq. 1) input i i v, i i= 1 n = ( )( )

Where: Clinput = Average amount of chlorine entering the boiler or process heater through fuels burned in units of pounds per Btu. This is the operating limit. Ci = Average concentration of chlorine in fuel, i, during each of the three 1 hour test periods as measured using the test methods specified in Tables 4. C and 4. D to this subpart, in units of pound per pound for solid fuels, pounds per gallon for liquid fuels, or pound per dry standard cubic foot for gaseous fuels. Qi = Average hourly input of fuel, i, during each of the three 1 hour test periods in units of pound per hour for solid fuels, gallons per hour for liquid fuels, or dry standard cubic feet per hour for gaseous fuels. If you do not burn multiple fuels during the performance test, it is not necessary to determine the value of this term. Insert a value of `` 1'' for Qi. Hv, i = Average heat input of fuel, i, during each of the three 1 hour test periods in units of Btu per hour as measured by the test methods indicated in Tables 4. C and 4. D to this subpart. n = Number of different fuel types in the worst case fuel input stream burned during each of the three 1 hour performance tests.

( 2) If you do not use a wet scrubber, you must establish an opacity operating limit during the initial performance test for particulate matter or total selected metals and mercury. This opacity level must not exceed 20 percent. ( 3) If you use a wet scrubber and you conduct separate performance tests for particulate matter, hydrogen chloride, and mercury emissions, you must establish one set of operating limits for pH, liquid flow rate, and pressure drop. The pH must be the level established during the hydrogen chloride performance test. The liquid flow rate and pressure drop operating limits must be the highest of the values established during the performance tests. ( 4) If you do not use a control device or do not want to take credit for the control device and you choose to comply with the alternative total selected metals emission limit instead of particulate matter, you must set your operating limit for total selected metals emissions based on the metals fuel input established during the initial performance test according to the procedures in paragraphs ( c)( 4)( i) and ( ii) of this section. ( i) During the initial performance test for total selected metals, you must measure the average hourly fuel input if you burn a combination of multiple fuels, average total selected metals concentration of the fuel input, and average heat input of each fuel burned during the 3 hour performance test. ( ii) You must set your operating limit for total selected metals using Equation 2 of this section:

Metals M Q H ( Eq. 2) input i i v, i i= 1 n = ( )( )

Where:

Metalsinput = Average amount of total selected metals entering the boiler or process heater through fuels burned in units of pounds per Btu. This is the operating limit. Mi = Average concentration of total selected metals in fuel, i, during each of the three 1 hour test periods as measured using the test methods specified in Table 4. E to this subpart, in units of pound per pound for solid fuels, pound per gallon for liquid fuels, or pound per dry standard cubic foot for gaseous fuels. Qi = Average hourly input of fuel, i, during each of the three 1 hour test periods in units of pounds per hour for solid fuels, gallons per hour for liquid fuels, or dry standard cubic feet per hour for gaseous fuels. If you do not burn multiple fuels during the performance test, it is VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00049 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 EP13JA03.000</ GPH> EP13JA03.001</ GPH> 1708 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules not necessary to determine the value of this term. Insert a value of `` 1'' for Qi. Hv, i = Average heat input of fuel, i, during each of the three 1 hour test periods in units of Btu per hour as measured by the test methods indicated in Table 4. E to this subpart. n = Number of different fuel types in the worst case fuel input stream burned during the 3 hour performance test. ( 5) If you do not use a control device or do not want to take credit for the control device, you must set your operating limit for mercury emissions based on the mercury fuel input established during the initial performance test according to the procedures in paragraphs ( c)( 5)( i) and ( ii) of this section. ( i) During the initial performance test for mercury, you must measure the average hourly fuel input if you burn a combination of multiple fuels, average mercury concentration of the fuel input, and average heat input of each fuel burned during the 3 hour performance test. ( ii) You must set your operating limit for mercury using Equation 3 of this section:

Mercury Q H Eq. 3) input i v, i = ( )( )                 =   HGi i n (

1 Where: Mercuryinput = Average amount of mercury entering the boiler or process heater through fuels burned in units of pounds per Btu. This is the operating limit. HGi = Average concentration of mercury in fuel, i, during each of the three 1 hour test periods as measured using the test methods specified in Table 4. E to this subpart, in units of pound per pound for solid fuels, pound per gallon for liquid fuels, or pound per dry standard cubic foot for gaseous fuels. Qi = Average hourly input of fuel, i, during each of the three 1 hour test periods in units of pounds per hour for solid fuels, gallons per hour for liquid fuels, or dry standard cubic feet per hour for gaseous fuels. If you do not burn multiple fuels during the performance test, it is not necessary to determine the value of this term. Insert a value of `` 1'' for Qi. Hv, i = Average heat input of fuel, i, during each of the three 1 hour test periods in units of Btu per hour as measured by the test methods indicated in Table 4. E to this subpart. n = Number of different fuel types in the worst case fuel input stream burned during the 3 hour performance test. ( 6) You must establish parameter operating limits according to paragraphs ( c)( 6)( i) through ( v) of this section. ( i) To establish an opacity operating limit, you must set the maximum opacity operating limit equal to the maximum 1 hour average opacity value measured during the three run performance test for particulate matter or total selected metals and mercury, or 20 percent, whichever is lower. ( ii) To establish operating limits for a wet scrubber, you must set the minimum operating limits for pH, liquid flow rate, and pressure drop equal to the minimum 1 hour average values measured during the three run performance test. ( iii) To establish operating limits for an electrostatic precipitator, you must set the minimum operating limits for voltage and secondary current ( or total power input) equal to the minimum 1 hour average values measured during the three run performance test. ( iv) To establish operating limits for a dry scrubber, you must set the minimum sorbent injection rate operating limit equal to the minimum 1 hour average value measured during the three run performance test. ( v) The operating limit for fabric filters requires that a bag leak detection system be installed according to the requirements in § 63.7525, and that each fabric filter must be operated such that the bag leak detection system alarm does not sound more than 5 percent of the operating time during a 6 month period. ( d) You must submit the Notification of Compliance Status report containing the results of the initial compliance demonstration according to the requirements in § 63.7545( e).

Continuous Compliance Requirements § 63.7535 How do I monitor and collect data to demonstrate continuous compliance? ( a) You must monitor and collect data according to this section. ( b) Except for monitor malfunctions, associated repairs, and required quality assurance or control activities ( including, as applicable, calibration checks and required zero and span adjustments), you must monitor continuously ( or collect data at all required intervals) at all times that the affected source is operating. ( c) You may not use data recorded during monitoring malfunctions, associated repairs, or required quality assurance or control activities, in data averages and calculations used to report emission or operating levels. You must use all the data collected during all other periods in assessing the operation of the control device and associated control system.

§ 63.7540 How do I demonstrate continuous compliance with the emission limitations and work practice standards?

( a) You must demonstrate continuous compliance with each emission limit, operating limit, and work practice standard in Tables 1 through 3 to this subpart that applies to you according to the methods specified in Tables 7. A, 7. B, and 8 to this subpart and paragraphs ( a)( 1) through ( 9) of this section. ( 1) For affected sources electing to comply with an emission limit based on fuel analysis, you must keep records of all fuels burned in each boiler or process heater during the reporting period to demonstrate that all fuels used would result in lower emissions of particulate matter or total selected metals, lower emissions of hydrogen chloride, and lower emissions of mercury than the emissions from the worst case fuel input that was burned during the initial performance test. You must also keep records that demonstrate that all fuels burned during the reporting period were obtained from the same suppliers as those fuels burned during the performance test. ( 2) For new or reconstructed boilers or process heaters in one of the liquid fuel subcategories that burn only fossil fuels and other gases and do not burn any residual oil, you are not required to set and maintain operating limits to demonstrate continuous compliance with the emission limits. To demonstrate continuous compliance with the emission limits, you must include a signed statement in each semiannual compliance report required in § 63.7550 that indicates you burned VerDate Dec< 13> 2002 19: 25 Jan 10, 2003 Jkt 200001 PO 00000 Frm 00050 Fmt 4701 Sfmt 4702 E:\ FR\ FM\ 13JAP2. SGM 13JAP2 EP13JA03.002</ GPH> 1709 Federal Register / Vol. 68, No. 8 / Monday, January 13, 2003 / Proposed Rules only liquid fossil fuels other than residual oils, either alone or in combination with gaseous fuels, during the reporting period; and you must also keep records, as required in paragraph ( a)( 1) of this section and § 63.7555, that demonstrate that you burn only liquid fossil fuels other than residual oils, either alone or in combination with gaseous fuels. ( 3) If you plan to burn a new type of fuel, a fuel from a new supplier, or a new mixture of fuels and your operating limit for hydrogen chloride is chlorine input, you must demonstrate continuous compliance by recalculating the chlorine input using Equation 1 of § 63.7530 according to the procedures specified in paragraphs ( a)( 3)( i) through ( iii) of this section. ( i) Determine for any new fuel the heating value and the chlorine concentration, based on supplier data or own fuel analysis, according to the provisions in the site specific test plan developed according to the requirements in § 63.7520( a). ( ii) Estimate the maximum hourly input at which each fuel will be burned. ( iii) Recalculate the amount of chlorine that would be put into the boiler or process heater during an hour under these new conditions using Equation 1 of § 63.7530. ( 4) If you plan to burn a new type of fuel, a fuel from a new supplier or a new mixture of fuels, your operating limit for hydrogen chloride is chlorine input, and the results of recalculating the chlorine input using Equation 1 of § 63.7530 are higher than the chlorine input operating limit established during the initial performance test, then you must conduct a new performance test according to the procedures in § 63.7520 to demonstrate that the hydrogen chloride emissions do not exceed the emission limitation. You must also establish a new operating limit based on this performance test according to the procedures in § 63.7530( c). ( 5) If you plan to burn a new type of fuel, a fuel from a new supplier, or a new mixture of fuels and you choose to comply with the alternative total selected metals emission limit instead of particulate matter and your operating limit is the total selected metals fuel content, you must demonstrate continuous compliance with your operating limit by recalculating the total selected metals input using Equation 2 of § 63.7530 according to the procedures specified in paragraphs ( a)( 5)( i) through ( iii) of this section. ( i) Determine for any new fuel the heating value and the total selected metals concentration, based on supplier data or own fuel analysis, according to the provisions in the site specific test plan developed according to the requirements in § 63.7520( a). ( ii) Estimate the maximum hourly input at which each fuel will be burned. ( iii) Recalculate the amount of total selected metals that would be put into the boiler or process heater during an hour under these new conditions using Equation 2 of § 63.7530. ( 6) If you plan to burn a new type of fuel, a fuel from a new supplier or a new mixture of fuels, you choose to comply with the alternative total selected metals emission limit instead of particulate matter, and the results of recalculating the total selected metals input using Equation 2 of § 63.7530 are higher than the total selected metals operating limit established during the initial performance test, then you must conduct a new performance test according to the procedures in § 63.7520 to demonstrate that the total selected metals emissions do not exceed the emission limit. You must also establish a new operating limit based on this performance test according to the procedures in § 63.7530( c). ( 7) If you plan to burn a new type of fuel, a fuel from a new supplier, or a new mixture of fuels and your operating limit for mercury emissions is the mercury fuel content, you must demonstrate continuous compliance with your operating limit by recalculating the mercury input using Equation 3 of § 63.7530 according to the procedures specified in paragraphs ( a)( 7)( i) through ( iii) of this section. ( i) Determine for any new fuel the heating value and the mercury concentration, based on supplier data or own fuel analysis, according to the provisions in the site specific test plan developed according to the requirements in § 63.7520( a). ( ii) Estimate the maximum hourly input at which each fuel will be burned. ( iii) Recalculate the amount of mercury that would be put into the boiler or process heater during an hour under these new conditions using Equation 3 of § 63.7530. ( 8) If you plan to burn a new type of fuel, a fuel from a new supplier or a new mixture of fuels, and the results of recalculating the mercury input using Equation 3 of § 63.7530 are higher than the mercury operating limit established during the initial performance test, then you must conduct a new performance test according to the procedures in § 63.7520 to demonstrate that the mercury emissions do not exceed the emission limit. You must also establish a new operating limit based on this performance test according to the procedures in § 63.7530( c). ( 9) If your unit is controlled with a fabric filter, you must demonstrate continuous compliance with the operating limits for fabric filters by operating each fabric filter system such that the bag leak detection system does not sound more than 5 percent of the operating time during a 6 month period and by keeping records of the date, time, and duration of each alarm, the time corrective action was initiated and completed, a brief description of the cause of the alarm and the corrective action taken. You must also record the percent of the operating time during each 6 month period that the alarm sounds. In calculating this operating time percentage, if inspection of the fabric filter demonstrates that no corrective action is required, no alarm time is counted. If corrective action is required, each alarm shall be counted as a minimum of 1 hour. If you take longer than 1 hour to initiate corrective action, the alarm time shall be counted as the actual amount of time taken to initiate corrective action. ( b) You must report each instance in which you did not meet each emission limit and each operating limit in Tables 7. A and 7. B to this subpart that apply to you. This includes periods of startup, shutdown, and malfunction. You must also report each instance in which you did not meet the work practice requirements in Table 8 to this subpart that apply to you. These instances are deviations from the emission limitations and work practice standards in this subpart. These deviations must be reported according to the requirements in § 63.7550. ( c) During periods of startup, shutdown, and malfunction, you must operate in accordance with the startup, shutdown, and malfunction plan as required in § 63.7505( d). ( d) Consistent with § § 63.6( e) and 63.7( e)( 1), deviations that occur during a period of startup, shutdown, or malfunction are not violations if you demonstrate to the Administrator's satisfaction that you were operating in accordance with the startup, shutdown, and malfunction plan. The Administrator will determine whether deviations that occur during a period of startup, shutdown, or malfunction are violations, according to the provisions in § 63.6( e).

Notifications, Reports, and Records § 63.7545 What notifications must I submit and when?