Revisions to the Continuous Emissions Monitoring Rule for the Acid Rain Program, NOX Budget Trading Program, the Clean Air Interstate Rule, and the Clean Air Mercury Rule

Federal RegisterAug 22, 2006

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 72 and 75

[OAR-2005-0132; FRL-8208-1]

Revisions to the Continuous Emissions Monitoring Rule for the Acid Rain Program, NO

Budget Trading Program, the Clean Air Interstate Rule, and the Clean Air Mercury Rule

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

SUMMARY:

EPA is proposing rule revisions that would modify existing requirements for sources affected by the federally administered emission trading programs including the NO

Budget Trading Program, the Acid Rain Program, the Clean Air Interstate Rule, and the Clean Air Mercury Rule.

The proposed revisions are prompted primarily by changes being implemented by EPA's Clean Air Markets Division in its data systems in order to utilize the latest modern technology for the submittal of data by affected sources. Other revisions address issues that have been raised during program implementation, fix specific inconsistencies in rule provisions, or update sources incorporated by reference. These revisions would not impose significant new requirements upon sources with regard to monitoring or quality assurance activities.

DATES:

All public comments must be received on or before October 23, 2006.

ADDRESSES:

Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2005-0132, by one of the following methods:

•

Federal eRulemaking Portal: http://www.regulations.gov.

Follow the on-line instructions for submitting comments.

•

E-mail: a-and-r-docket@epa.gov.

•

Fax:

(202) 566-1741.

•

Hand Delivery:

Air and Radiation Docket, Environmental Protection Agency, 1301 Constitution Avenue, NW., Room B-108, Washington, DC 20014. Such deliveries are accepted only during the Docket's normal hours of operation and special arrangements should be made for deliveries of boxed information.

•

Mail:

EPA Docket Center (EPA/DC), Environmental Protection Agency, Mailcode 6102T, 1200 Pennsylvania Avenue, NW., Washington, DC 20460. Please include a total of two copies. We request that a separate copy also be sent to the contact person identified below (see

FOR FURTHER INFORMATION CONTACT

Instructions:

Direct your comments to Docket ID No. EPA-HQ-OAR-2005-0132. EPA's policy is that all comments received will be included in the public docket without change and may be made available online at

http://www.regulations.gov

including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through

http://www.regulations.gov

or e-mail. The

http://www.regulations.gov

Web site is an “anonymous access” system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e-mail comment directly to EPA without going through

http://www.regulations.gov,

your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your comment with a disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses.

Docket:

All documents in the docket are listed in the

http://www.regulations.gov

index. Although listed in the index, some information is not publicly available,

e.g.

, CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in

http://www.regulations.gov

or in hard copy at the Air and Radiation Docket, EPA/DC, EPA West, Room B102, 1301 Constitution Ave., NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the Air and Radiation Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT:

Matthew Boze, Clean Air Markets Division, U.S. Environmental Protection Agency, Clean Air Markets Division, MC 6204J, Ariel Rios Building, 1200 Pennsylvania Ave., NW., Washington, DC 20460, telephone (202) 343-9211, e-mail at

boze.matthew@epa.gov.

Electronic copies of this document can be accessed through the EPA Web site at:

http://www.epa.gov/airmarkets.

SUPPLEMENTARY INFORMATION:

Regulated Entities.

Entities regulated by this action primarily are fossil fuel-fired boilers, turbines, and combined cycle units that serve generators that produce electricity, generate steam, or cogenerate electricity and steam. Some trading programs include process sources, such as process heaters or cement kilns. Although Part 75 primarily regulates the electric utility industry, certain State and Federal NO

mass emission trading programs rely on subpart H of Part 75, and those programs may include boilers, turbines, combined cycle, and certain process units from other industries. Regulated categories and entities include:

Category

NAICS code

Examples of potentially regulated industries

Industry

221112 and others

Electric service providers Process sources with large boilers, turbines, combined cycle units, process heaters, or cement kilns where emissions exhaust through a stack.

This table is not intended to be exhaustive, but rather to provide a guide for readers regarding entities likely to be regulated by this action. This table lists the types of entities which EPA is now aware could potentially be regulated by this action. Other types of entities not listed in this table could also be regulated. To determine whether your facility, company, business, organization, etc., is regulated by this action, you should carefully examine the applicability provisions in §§ 72.6, 72.7, and 72.8 of title 40 of the Code of Federal Regulations and in 40 CFR Parts 96 and 97. If you have questions regarding the applicability of this action to a particular entity, consult the person listed in the preceding

FOR FURTHER INFORMATION CONTACT

section.

Submitting CBI.

Do not submit this information to EPA through

http://www.regulations.gov

or e-mail. Clearly mark the part or all of the information that you claim to be CBI. For CBI information on a disk or CD-ROM that you mail to EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2.

World Wide Web (WWW).

In addition to being available in the docket, an electronic copy of the proposed rule is also available on the WWW through the Technology Transfer Network Web site (TTN Web). Following signature, a copy of the proposed rule will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at

http://www.epa.gov/ttn/oarpg.

The TTN provides information and technology exchange in various areas of air pollution control.

Outline:

I. Detailed Discussion of Proposed Rule Revisions

A. Rule Definitions

B. General Monitoring Provisions

C. Certification Requirements

D. Missing Data Substitution

E. Recordkeeping and Reporting

F. Subpart H (NO

Mass Emissions)

G. Subpart I (Hg Mass Emissions)

H. Appendix A

I. Appendix B

J. Appendix D

K. Appendix E

L. Appendix F

M. Appendix G

N. Appendix K

II. Administrative Requirements

A. Executive Order 12866—Regulatory Planning and Review

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

D. Unfunded Mandates Reform Act

E. Executive Order 13132—Federalism

F. Executive Order 13175—Consultation and Coordination With Indian Tribal Governments

G. Executive Order 13045—Protection of Children From Environmental Health and Safety Risks

H. Executive Order 13211—Actions That Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act

I. Detailed Discussion of Proposed Rule Revisions

EPA is in the process of re-engineering the data systems associated with the collection and processing of emissions, monitoring plan, quality assurance, and certification data. The re-engineering project includes the creation of a client tool, provided by EPA that sources will use to evaluate and submit their Part 75 monitoring data. This process change will enable sources to assess the quality of their data prior to submitting the data using EPA established checking criteria. The process will also allow sources to report their data directly to a database. Having the data in a true database will allow the Agency to implement and assess the program more efficiently and will streamline access to the data. Also, this database structure will enable EPA to implement process changes that will reduce the redundant reporting of certain types of data. The re-engineered systems will be supported by a new extensible markup language (XML) data format that will replace the record type/column format currently used by EPA to collect electronic data. EPA intends to transition existing sources to the new XML electronic data report (XML-EDR) format during the 2008 reporting year. For sources reporting in 2008 for the first time, the new XML-EDR format should be used. All sources will be required to use the new process beginning 2009.

A. Rule Definitions

The proposed changes to Part 72 include adding a definition for “long-term cold storage” to mean “the complete shutdown of a unit intended to last for an extended period of time (at least two calendar years) where notice for long-term cold storage is provided under § 75.61(a)(7).

See

Section II.E.4 of this preamble for further discussion.

EPA also proposes to modify the definition of “capacity factor” so that the Agency can use the reported maximum hourly gross load, as currently reported in the electronic monitoring plan, to determine whether a unit qualifies for peaking unit status, by recalculating the capacity factor. This is important because the maximum hourly gross load can be greater than the nameplate capacity. Also, when using heat input to define capacity factor, the definition would be revised to refer to maximum rated hourly heat input rate, which is defined in § 72.2.

The proposed changes to § 72.2 would also modify the definition of “EPA Protocol Gas,” and add a definition of “EPA Protocol Gas Verification Program”, to support the proposed calibration gas audit program. EPA is also proposing to expand the definition of “excepted monitoring system” to include the sorbent trap and low mass emissions (LME) excepted methodologies for Hg. Finally, today's proposed rule would add definitions of “Air Emission Testing Body (AETB)” and “Qualified Individual”, to support the proposed stack tester accreditation program. See Sections II.H.2 and II.H.3 of this preamble for a discussion of these proposed programs.

B. General Monitoring Provisions

1. Update of Incorporation by Reference (§ 75.6)

Section 75.6 identifies a number of methods and other standards that are incorporated by reference into Part 75. This section includes standards published by the American Society for Testing and Materials (ASTM), the American Society of Mechanical Engineers (ASME), the American National Standards Institute (ANSI), the Gas Processors Association (GPA), and the American Petroleum Institute (API). Changes in § 75.6 would reflect the need to incorporate recent updates for many of the referenced standards. The proposed revisions would recognize or adhere to these newer standards by updating references for the standards listed in §§ 75.6(a) through 75.6(f). Additionally, new §§ 75.6(a)(45) through 75.6(a)(48) and 75.6(f)(4) would incorporate by reference additional ASTM and API standards that are relevant to Part 75 implementation.

2. Default Emission Rates for Low Mass Emissions (LME) Units

Today's proposed rule revisions would allow LME units to use site-specific default SO

emission rates for fuel oil combustion, in lieu of using the “generic” default SO

emission rates specified in Table LM-1 of § 75.19. To use this option, a federally enforceable permit condition would have to be in place for the unit, limiting the sulfur content of the oil. This revision would allow more representative, yet still conservatively high, SO

emissions data to be reported from oil-burning LME units. The site-specific default SO

emission rate would be calculated using an equation from EPA publication AP-42. The sulfur content used in the calculations would be the maximum weight percent sulfur allowed by the federally-enforceable permit. Sources choosing to implement this option would be required to perform periodic oil sampling using one of the four methodologies described in Section 2.2

of Appendix D to Part 75, and would be required to keep records documenting the sulfur content of the fuel.

Today's proposed rule would also revise § 75.19(c)(1)(iv)(G) to clarify that fuel-and-unit-specific default NO

emission rates for LME units may be determined using data from a Continuous Emissions Monitoring System (CEMS) that has been quality-assured according to either Appendix B of Part 75 or Appendix F of Part 60, or comparably quality-assured under a State CEMS program. The current rule simply states that 3 years (or 3 ozone seasons, if applicable) of quality-assured CEMS data may be used for this purpose, but it does not specify the acceptable level of QA required.

3. Default Moisture Value for Natural Gas

EPA is proposing to allow gas-fired boilers equipped with CEMS to use default moisture values in lieu of continuously monitoring the stack gas moisture content. Two default values are proposed: 14.0% H

O under § 75.11(b), and 18.0% H

O under § 75.12(b). The higher default value would apply only when Equation 19-3, 19-4, or 19-8 (from Method 19 in appendix A of Part 60) is used to determine the NO

emission rate. These proposed default values are based on supplemental moisture data provided to the Agency in a December 13, 2004 petition from a gas-fired industrial source and moisture data collected during EPA's development of flow rate reference Methods 2F and 2G at two gas-fired facilities. (

See

Docket A-99-14; Items II-A-1 and II-A-7).

EPA selected the 10th and 90th percentile values from these data, rounded to the nearest whole number, as the proposed natural gas default moisture values. The selection of conservative 90th or 10th percentile values from representative moisture data sets is consistent with the approach that the Agency has approved in response to past petition under § 75.66 requesting to use site-specific default moisture values.

4. Expanded Use of Equation F-23

Today's proposed rule would revise § 75.11(e)(1) to remove the current restrictions on the use of Equation F-23 to determine the SO

mass emission rate. The current rule restricts the use of this equation to units equipped with SO

monitors and to hours when only fuel that meets the Part 72 definition of “pipeline natural gas” or “natural gas” is being combusted. EPA proposes to allow Equation F-23 to be used whether or not the unit has an SO

monitor and to expand its use to fuels other than natural gas.

Section 75.11(e) would be re-titled as “Special considerations during the combustion of gaseous fuels”, and the introductory text of the section would be revised, so that the section would no longer apply exclusively to units with SO

monitors. Rather, it would apply to units that use certified flow rate and diluent gas monitors to quantify heat input. Such units would be required to implement the provisions of either revised § 75.11(e)(1) or revised § 75.11(e)(3) when gaseous fuel is the only fuel combusted in the unit. Section 75.11(e)(2) would be removed and reserved, as the use of Appendix D methodology during gaseous fuel combustion is not appropriate for a unit that uses flow and diluent monitors to measure heat input. This is because only one heat input methodology is allowed for each unit.

Revised § 75.11(e)(1) would expand the use of Equation F-23 beyond natural gas combustion to include the combustion of any gaseous fuel that qualifies for a default SO

emission rate under Section 2.3.6(b) of Appendix D. The proposed revisions to § 75.11(e)(3) would be relatively minor. The option to use a certified SO

monitor during hours of gaseous fuel combustion would be retained.

A new paragraph (e)(4) would also be added to § 75.11(e). This new provision would allow Equation F-23 to be used for the combustion of liquid and solid fuels that meet the definition of “very low sulfur fuel” in § 72.2, if a petition for a fuel-specific default SO

emission rate is submitted to the Administrator under § 75.66 and the Administrator approves the petition. Similar petitions would also be accepted for the combustion of mixtures of these fuels and for the co-firing of these fuels with gaseous fuel.

EPA believes that expanding the use of Equation F-23 will benefit certain units that are subject to the Acid Rain Program or to the SO

provisions of the Clean Air Interstate Rule (CAIR). In particular, the requirement to operate and maintain an SO

CEMS could be waived for units that burn low-sulfur solid fuels such as wood waste. Also, for units that combust non-traditional gaseous fuels, Equation F-23 would provide an alternative way of quantifying SO

mass emissions that does not require either an SO

CEMS or a certified fuel flowmeter.

5. Calculation of NO

Emission Rate—LME Units

According to §§ 75.58(f), 75.64(a)(4), and 75.64(a)(9), oil and gas-fired units in the Acid Rain Program that qualify to use the low mass emissions (LME) methodology in § 75.19 are required to report both NO

mass emissions (lb or tons, as applicable) and NO

emission rate (lb/mmBtu) on an hourly, quarterly and annual basis. However, the mathematics in § 75.19(c)(4)(ii) pertains only to NO

mass emissions, not NO

emission rate. This is most likely because the criterion for initial and on-going LME qualification is based on the total tons of NO

emitted the calendar year, rather than on the NO

emission rate.

Today's rule would re-title § 75.19(c)(4)(ii) as “NO

mass emissions and NO

emission rate”, and would add a new subparagraph (D) to § 75.19 (c)(4)(ii), providing instructions for determining quarterly and cumulative NO

emission rates for an LME unit. The NO

emission rate for each hour (lb/mmBtu) would simply be the appropriate generic or unit-specific default NO

emission rate defined in the monitoring plan for the type of fuel being combusted and (if applicable) the NO

emission control status. The quarterly NO

emission rate would be determined by averaging all of the hourly NO

emission rates and the cumulative (year-to-date) NO

emission rate would be the arithmetic average of the quarterly values.

6. LME Units—Scope of Applicability

Today's rule would revise § 75.19(a)(1) to clarify that the low mass emissions (LME) methodology is a stand-alone alternative to a CEMS and/or the “excepted” monitoring methodologies in Appendices D, E, and G. In other words, if a unit qualifies for LME status, the owner or operator would be required either to use the LME methodology for all parameters or not to use the method at all. No mixing-and-matching of other monitoring methodologies with LME would be permitted. For example, the owner or operator of a qualifying LME unit in the Acid Rain Program would either be required to follow the provisions of § 75.19 for all parameters (

i.e.

, SO

and CO

mass emissions, NO

emission rate, and unit heat input) or to monitor these parameters using a CEMS, Appendices D, E, and G, or a combination of these other methods. EPA has always intended for the LME methodology to be applied this way, but this was not explicitly stated in § 75.19 and in other sections of the rule. In fact, §§ 75.11(d)(3), 75.12(e)(3), and 75.13(d)(3)) suggest that mixing other monitoring methodologies with LME might not be prohibited. Today's rule would also make parallel revisions to

these other sections, consistent with the changes to § 75.19(a)(1), to clarify the Agency's intent.

7. Use of maximum controlled NO

emission rate when using bypass stacks

Today's proposed rule would revise § 75.17(d)(2) to allow for the calculation and use of a maximum controlled NO

emission rate (MCR) instead of the maximum potential NO

emission rate (MER) whenever an unmonitored bypass stack is used, provided that the add-on controls are not bypassed and are documented to be operating properly. Documentation of proper add-on control operation for such hours of operation would be required as described in § 75.34(d). The MCR would be calculated in a manner similar to the calculation of the MER, except that the maximum expected NO

concentration (MEC) would be used instead of the maximum potential NO

concentration (MPC). EPA believes that this proposal would more fairly account for controlled emissions when unmonitored bypass stacks are used. The rule currently requires the use of the MER regardless of the operation and usage of add-on controls. When § 75.17(d)(2) was originally promulgated, EPA assumed that the add-on controls would be bypassed whenever a bypass stack is used. EPA is now aware that there are situations where this is not the case. An example would be a coal-fired unit equipped with FGD and SCR add-on emission controls. If the SCR is documented to be working during an FGD malfunction and the effluent gases are routed through an unmonitored bypass stack after passing through the SCR, then the MEC, rather than the MER, would be the more appropriate NO

emission rate to report for the bypass hour(s).

C. Certification Requirements

1. Alternative Monitoring System Certification

The proposed rule would delete §§ 75.20(f)(1) and (2) from the rule, thereby removing the requirement for the Administrator to publish each request for certification of an alternative monitoring system in the

Federal Register

, with an associated 60-day public comment period. This rule provision is considered unnecessary, in view of the Agency's authority under Subpart E to approve alternative monitoring systems and the rigorous requirements that alternative monitoring systems must meet in order to be certified.

2. Part 60 Reference Test Methods

On May 15, 2006, EPA promulgated final revisions to EPA reference test methods 6C, 7E, and 3A, which are found in Appendix A of 40 CFR Part 60. (

See

71 FR 28082, May 15, 2006). Today's proposed rule would update, (as necessary), various section references to these reference methods, as well as specify certain options that are not to be applied to RATA testing under Part 75. Specifically, the following provisions are not permitted unless specific approval is granted by the Administrator of Part 75:

(1) § 7.1 of the revised EPA Method 7E allowing for use of prepared calibration gas mixtures that are produced in accordance with Method 205 in Appendix M of 40 CFR Part 51. EPA maintains that for RATA testing under Part 75, that reference gases be selected in accordance with § 5.1 of Appendix A of 40 CFR Part 75.

(2) § 8.4 of the revised EPA Method 7E allowing for the use of a multi-hole probe to satisfy the multipoint traverse requirement of the method.

(3) § 8.6 of the revised EPA Method 7E allowing for the use of “Dynamic Spiking” as an alternative to the interference and system bias checks of the method. This proposed rule would allow for dynamic spiking to be conducted (optionally) as an additional quality assurance check for Part 75 applications.

3. Mercury Reference Methods

Today's proposed rule would add an alternative acceptance criterion for the results of mercury (Hg) emission data collected with the Ontario Hydro (OH) reference method and would allow the use of alternative reference methods for RATAs and for the low mass Hg emission testing described in § 75.81(c).

On May 18, 2005, EPA published the Clean Air Mercury Rule (CAMR). That rule requires coal-fired electric generating units (EGUs) to reduce Hg emissions, starting in 2010, and to continuously monitor Hg mass emissions according to Subpart I of Part 75, beginning in 2009.

Relative accuracy test audits (RATAs) of all continuous Hg monitoring systems are required under CAMR, and Hg emission testing is required for units seeking to qualify as low mass emitters under § 75.81(c). The principal reference method specified for the RATAs and the emission testing is the OH method. Alternatively, an instrumental method approved by the Administrator may be used. When the OH method is performed, § 75.22(a)(7) requires paired sampling trains for each test run, and the relative deviation (RD) of the results from the two trains must not exceed 10 percent.

As part of the May 18, 2005 rulemaking, EPA also promulgated revisions to Subpart Da of the New Source Performance Standards (NSPS) regulations, requiring continuous Hg emission monitoring for new coal-fired electric utility units constructed after January 1, 2004. Along with the Subpart Da revisions, a performance specification, PS-12A, for certifying the required continuous Hg monitors was published. PS-12A, like Part 75, requires RATA testing of all Hg monitoring systems, using paired reference method sampling trains; however, note that PS 12-A allows EPA Method 29 (from Appendix A-8 of 40 CFR Part 60) to be used as an alternative to the OH method, whereas Part 75 does not.

The principal acceptance criterion in Section 8.6.6.2 of PS 12-A for the data from the paired reference method trains (10 percent RD) is the same as in § 75.22(a)(7). However, PS 12-A includes an alternative acceptance criterion for sources with low Hg emissions. If the average Hg concentration during the RATA is 1.0 μg/m

or less, the RD specification is 20 percent. In view of this, today's proposed rule would revise § 75.22(a)(7), to include this same 20 percent alternative RD specification for low-emitters. This would harmonize the Part 60 and Part 75 RATA provisions for Hg monitors, thereby facilitating compliance for sources subject to both sets of regulations.

EPA is also proposing revisions to §§ 75.22(a)(7) and 75.81(c)(1) which would allow EPA Method 29 to be used as an alternative to the OH method, both for RATA testing and for periodic emission testing of units with low Hg mass emissions (≤ 29 lb/yr). Method 29 is an established test procedure that uses atomic absorption spectroscopy to determine the concentration of various metals, including Hg, in the stack gas. This method is more familiar to emission testers than the OH method, and Method 29 data have been accepted for compliance purposes by the State. Method 29 and the OH method both measure the total vapor phase Hg in the effluent. The main difference between the two methods is that the OH method performs “speciation” of the vapor phase Hg,

i.e.

, it quantifies the elemental and ionic portions of the vapor phase Hg separately, whereas Method 29 does not. However, the CAMR rule does not require speciation of the vapor phase Hg. Therefore, Method 29 could be used instead of the OH method.

There would be two caveats on the use of Method 29. First, sources electing to use Method 29 would be required to use paired sampling trains (

i.e.

, two trains sampling the source effluent simultaneously), and the relative deviation specification in § 75.22(a)(7) would have to be met for each run. The test results for each valid run would be based on the Hg collected in the back half of each sampling train (

i.e.

, the impinger catch), and the results from the two trains would be averaged arithmetically.

Second, certain analytical and QA procedures in the OH method (ASTM D6784-02) would be followed instead of the corresponding procedures in Method 29. Specifically, testers would be required to replace the procedures in sections 7.5.33 and 11.1.3 of Method 29 with the corresponding procedures in sections 13.4.1.1 through 13.4.1.3 of ASTM D6784-02, and to perform the QA/QC procedures in section 13.4.2 of the OH method instead of the procedures in section 9.2.3 of Method 29. EPA believes that implementing these sections of the OH method in lieu of the corresponding Method 29 provisions will improve the quality of the data, because the analytical and QA/QC requirements of the OH method are more detailed and rigorous than those in Method 29.

EPA is also proposing to allow several of the sample recovery and preparation procedures in the OH method to be followed instead of the Method 29 procedures. In particular: (a) Sections 13.2.9.1 through 13.2.9.3 of the OH method could be followed instead of sections 8.2.8 and 8.2.9.1 of RM 29; (b) sections 13.2.10.1 through 13.2.10.4 of the OH method could be followed instead of sections 8.2.9.2 and 8.2.9.3 of RM 29; (c) section 8.3.4 of RM 29 could be replaced with section 13.3.4 or 13.3.6 of the OH method (as appropriate); and (d) section 8.3.5 of RM 29 could be replaced with section 13.3.5 or 13.3.6 of the OH method (as appropriate). Use of these alternative procedures would increase the accuracy of moisture content determinations (by using a gravimetric rather than a volumetric technique), and would eliminate of the need for two separate analyses of the KMnO

fraction.

Revisions to § 75.59 and to Sections 6.5.10 and 7.6.1 of Appendix A to Part 75 are also being proposed, for purposes of consistency with the proposed changes to §§ 75.22(a)(7) and 75.81(c)(1).

Finally, the Agency is soliciting comment on the use of sorbent traps for reference method testing. At the 2006 Electric Utility Environmental Conference (EUEC) in Tucson, Arizona, a stakeholder meeting was held to discuss mercury monitoring issues. Many of the participants expressed an interest in using portable sorbent trap monitoring systems for Hg reference method testing, as an alternative to the OH method. After much internal discussion, EPA believes that a sorbent trap system could potentially serve as an alternative reference method for Hg emission testing and RATA applications, if it can be adequately demonstrated that the method does not have an inherent measurement bias when compared to the OH method, and if sufficiently rigorous quality-assurance (QA) procedures are developed and followed when the system is used in the field. In view of this, EPA requests comment on how such a demonstration might be made and what QA procedures would be appropriate. In anticipation that a viable reference method using sorbent trap technology may be developed in the near future, the Agency is also proposing to add language to § 75.22(a)(7), which would allow an “other suitable” reference method approved by the Administrator to be used for Hg emission testing and RATAs.

D. Missing Data Substitution

1. Block Versus Step-Wise Approach

During periods of missing CEMS data, Part 75 requires substitute data to be reported. Special mathematical algorithms are used to determine the appropriate substitute data values. As the length of a missing data period increases, the percent monitor data availability (PMA) decreases, and the required substitute data values become increasingly conservative each time that a particular PMA “cut point” is reached. The cut points are 95%, 90%, and 80% PMA for all parameters except Hg. For Hg, the cut points are slightly lower,

i.e.

, at 90%, 80% and 70% PMA.

Historically, EPA's policy has required sources to use a “block” approach for missing data substitution. The PMA at the end of the missing data period has been used to determine which mathematical algorithm applies, and the substitute data value or values prescribed by that one algorithm have been reported for each hour of the missing data period.

However, EPA has recently revised its missing substitution data policy. The revised policy guidance (

see

“Part 75 Emission Monitoring Policy Manual”, Question 15.5) allows sources to apply the missing data algorithms in a stepwise manner instead of using the block approach. Under the stepwise methodology, the various missing data algorithms are applied sequentially. That is, the least conservative algorithm is applied to the missing data hours until the PMA drops below 95%. Then, the next algorithm is applied until the PMA has dropped below 90%, and so on.

Part 75 is not clear about which of the two methods should be used for missing data substitution. Today's proposed rule would revise the text of certain paragraphs in §§ 75.33 and 75.32(b), to clarify that the stepwise, hour-by-hour method (which is the least stringent approach) is the preferred one. The Agency favors this approach because it prevents sources from being penalized by the retroactive application of more stringent missing data algorithms to hours where the hourly PMA merits the use of less conservative algorithms. EPA intends that only the new stepwise, hour-by-hour method be used after January 1, 2009, or whenever emissions data are to be submitted in XML-format. Until this time, either method will be accepted.

2. Substitute Data Values for Controlled Units

For units with add-on emission controls, § 75.34(a)(3) provides that the designated representative (DR) may petition the Administrator under § 75.66 to report alternative substitute data values in certain instances. Specifically, when the percent monitor data availability (PMA) for SO

or NO

is below 90.0 percent, the DR may petition to replace the maximum emission rate recorded in the last 720 quality-assured monitor operating hours with the maximum controlled emission rate recorded during that same lookback period, for each missing data hour in which the add-on controls are documented to be operating properly. Until recently, this petition provision applied only to units with add-on SO

or NO

emission controls. However, revisions to Part 75 on May 18, 2005, extended it to include units with add-on Hg controls (

see

§ 75.38(c)).

For several reasons, EPA believes it is appropriate to revise § 75.34(a)(3). First, the 720 hour lookback is only appropriate for SO

and Hg. For NO

, the lookback should be 2,160 hours and should also be load-based. Second, for SO

, Hg, and NO

concentration monitoring systems, the terms “maximum emission rate” and “maximum controlled emission rate” are not appropriate and should be replaced by “maximum concentration” and “maximum controlled concentration”, respectively. Third, the petition provision, as written, applies to

all PMA values below 90.0 percent (that was the intent when it was originally written), but in light of subsequent revisions to Part 75, it should be restricted to a narrower range of PMA values. Fourth, and most important, after more than ten years of implementing the Acid Rain Program, EPA no longer believes that special petitions are necessary to use maximum controlled values for missing data substitution, because sources with add-on controls are required to implement a quality assurance/quality control (QA/QC) program that includes the recording of parametric data to document the hourly operating status of the emission controls. This parametric information must be made available to inspectors and auditors upon request. Therefore, any claim that the emission controls were operating properly during a particular missing data period can be easily verified through the audit process.

At the time the petition provision in § 75.34(a)(3) was written, there were only three missing data tiers in existence,

i.e.

, for PMA values: (1) ≥ 95.0 percent; (2) ≥ 90.0 percent, but < 95.0 percent: and (3) < 90.0 percent. The provision was associated with the third tier (PMA < 90.0 percent), for which the required substitute data value is the maximum value recorded in a specified lookback period. However, on May 26, 1999, EPA added a fourth CEMS missing data tier to Part 75. The May 1999 rule revisions did not change the missing data algorithms for the third tier, but the PMA “cut off” point for the third tier was set at 80.0 percent, and below 80.0 percent PMA, reporting of the maximum potential concentration (MPC) or the maximum potential NO

emission rate (MER) was required for a missing data period of any length.

Today's proposed rule would remove from § 75.34(a)(3) and § 75.66(f) the requirement to petition the Administrator to use the maximum controlled SO

or NO

concentration (or maximum controlled NO

emission rate) from the applicable lookback period. The proposed revisions would simply allow the maximum controlled values to be reported whenever parametric data are available to document that the emission controls are operating properly. The proposed rule would further clarify that this reporting option applies only to the third missing data tier, when the PMA is greater than or equal to 80.0 percent, but less than 90.0 percent.

EPA is also proposing to add a new paragraph (a)(5) to § 75.34, which would allow units with add-on emission controls to report alternative substitute data values for missing data periods in the fourth tier, when the PMA is below 80.0 percent. Proposed § 75.34(a)(5) would allow the owner or operator to replace the maximum potential SO

or NO

concentration (MPC) or the maximum potential NO

emission rate (MER) with a less conservative substitute data value, for missing data hours where parametric data, (as described in §§ 75.34(d) and 75.58(b)) are available to verify proper operation of the add-on controls. Specifically, for SO

and NO

concentration, the replacement value for the MPC would be the greater of: (a) The maximum expected concentration (MEC); or (b) 1.25 times the maximum controlled value in the standard missing data lookback period. For NO

emission rate, the replacement value for the MER would be the greater of: (a) The maximum controlled NO

emission rate (MCR); or (b) 1.25 times the maximum controlled value in the standard missing data lookback period. The NO

MCR would be calculated in the same manner as the NO

MER (

see

Appendix A, section 2.1.2.1(b)), except that the MEC, rather than the MPC, would be used in the calculation.

Finally, today's proposed rule would revise § 75.38(c) to extend the alternative missing data options for the third and fourth tiers to mercury (Hg) concentration, and § 75.58(b)(3) would be revised to be consistent with the proposed revisions to §§ 75.34(a)(3), 75.34(a)(5), and 75.38(c).

EPA believes that for missing data hours in which the emission controls are working properly, these proposed rule revisions will prevent gross overestimation of emissions during hours when the source is operating its emission controls in a manner that is protective of the environment. When the emission controls are working properly, there can be as much as a tenfold difference between the MPC, MER, or maximum value in a lookback period and the actual source emissions. The proposed alternative substitute data values in §§ 75.34(a)(3) and (a)(5), though much closer to the actual emissions, would still be conservatively high and would provide the owner or operator with a strong incentive to keep the CEMS operational. The Agency also believes that the proposed alternative data substitution methodology in § 75.34(a)(5) ensures that the substitute data values for the fourth tier will always be higher than the corresponding substitute data values for the third tier.

3. Substitute Data Values for Hg

EPA is also proposing to revise the Hg missing data procedures. First, for Hg CEMS, the text of § 75.38(a) would be amended to make it consistent with Table 1 in § 75.33. Proposed § 75.38(a) clarifies that the percent monitor data availability (PMA) “trigger conditions” for Hg monitoring systems are different from the trigger conditions for all other parameters. For all parameters except Hg, the trigger points that define the boundaries of the four missing data tiers are 95 percent, 90 percent, and 80 percent PMA. However, for Hg the corresponding trigger points are 90 percent, 80 percent and 70 percent, respectively.

Second, EPA proposes to completely revise the missing data provisions in § 75.39 for sorbent trap monitoring systems. In the current rule, the missing data routines for sorbent trap systems are substantially different from those for Hg CEMS. At the time of publication of the Part 75 Hg monitoring provisions, the Agency believed that a different approach to missing data substitution was appropriate for sorbent traps, because unlike the Hg CEMS, a sorbent trap system does not provide real-time hourly average emissions data. Consequently, EPA prescribed a 12-month missing data “lookback” period for the sorbent trap systems. That is, the substitute data values are based on a lookback through the previous 12 months of sorbent trap sample results, instead of looking back through 720 quality-assured monitor operating hours, as is done for the Hg CEMS.

EPA has reconsidered the sorbent trap missing data methodology and has concluded that it is unnecessarily complex and will likely be difficult to implement and audit. In view of this, the Agency proposes to amend the missing data procedures for sorbent trap systems, to make them the same as for Hg CEMS. Section 75.39 would be revised to require that the initial missing data procedures of § 75.31(b) and the standard Hg missing data provisions of § 75.38 be followed for sorbent trap systems. EPA believes that this missing data approach can work because for the purposes of Part 75 reporting, the average Hg concentration measured by a sorbent trap system is “back-filled” into each hour of the data collection period to simulate hour-by-hour concentration measurements (

see

§ 75.57(j)(1)(iii)). Thus, the hourly Hg concentration data stream from a sorbent trap system will look essentially the same as the data stream from a CEMS, except that the Hg concentration will “flat-line” (

i.e.

, will not change) during each data collection period. Therefore, the required missing data lookbacks through 720 hours of quality-assured data could be done on the

sorbent trap data stream, although in some cases, because of the flat-line effect, when the 720 hours of data are arranged in rank order, the 90th percentile, 95th percentile, and maximum values in the lookback might be identical.

Finally, a new paragraph “(f)” would be added to § 75.39 to address the case in which the owner or operator elects to use a primary Hg CEMS and a redundant backup sorbent trap system (or vice-versa). In that case, separate Hg concentration data streams would be recorded and maintained for the two systems. For reporting purposes, data from the primary monitoring system would be reported whenever that system is able to provide quality-assured data (

see

§ 75.10(e)), and quality-assured data from the redundant backup system (if available) could be reported during primary monitoring system outages. However, when both the primary and redundant backup monitoring systems are down and quality-assured data from a reference method or approved alternative monitoring system are also unavailable, proposed § 75.39(f) would require the appropriate substitute data values to be derived from a lookback through the previous 720 hours of quality-assured data reported in the electronic quarterly report, irrespective of the source of those data,

i.e.

, whether they were from the primary system, the redundant backup system, a reference method, or an approved alternative monitoring system.

4. Correction of Cross-References

For sources in the NO

Budget Program that report emissions data only during the ozone season (

i.e.

, May through September), the quality assurance requirements for the continuous emission monitoring systems are found in § 75.74(c). In §§ 75.74(c)(3)(xi) and (c)(3)(xii), data validation rules are provided for situations in which required quality-assurance tests of the CEMS are due by the end of the second or third calendar quarter, but are not completed on time. In some cases, these rule provisions require the use of missing data substitution, and refer to the “appropriate missing data routine in § 75.31, § 75.33 or § 75.37”. These references to specific missing data sections are inadequate, because they only cover initial missing data (for all parameters) and the standard missing data procedures for NO

, flow rate, and moisture. Sections 75.34 through 75.36 are not referenced, which address missing data substitution for units with add-on emission controls and for diluent gas (O

or CO

) data used for heat input rate determination. Many NO

Budget Program units are equipped with add-on NO

emission controls, and a great number use data from a CO

or O

monitor to determine the hourly heat input rate. In view of this, today's rule would revise §§ 75.74(c)(3)(xi) and (c)(3)(xii) by replacing each of the cross-references to specific missing data sections with a more general reference to the entire block of CEMS missing data sections,

i.e.

, §§ 75.31 through 75.37.

E. Recordkeeping and Reporting

1. Revisions to the General Monitoring Plan Recordkeeping Requirements

EPA proposes to revise the monitoring plan recordkeeping requirements in § 75.53, to accommodate its new, re-engineered XML reporting format, which will replace the current electronic data reporting (EDR) format in 2009. The Subpart H monitoring plan record keeping provisions in § 75.73(c)(3) (for sources reporting NO

mass emissions) and the Subpart I monitoring plan record keeping provisions in § 75.84 (for sources reporting Hg mass emissions) would be similarly revised to reflect the transition to XML format.

EPA proposes to add two new paragraphs, (g) and (h), to § 75.53, which describe the required monitoring plan data elements in EPA's re-engineered XML data structure. Proposed § 75.53(a)(1) would require all affected units to follow the provisions of paragraphs (g) and (h) instead of the existing recordkeeping requirements of paragraphs (e) and (f), on and after January 1, 2009. However, early implementation of the XML format would be allowed or, in some cases, required. In 2008, existing sources would be allowed to choose between the EDR format and XML, and new sources reporting for the first time in 2008 would be required to use XML.

Table 1 summarizes the data elements or requirements in § 75.53 that would be removed, replaced or added as a result of transitioning from the current EDR to XML EDR format.

Table 1.—Monitoring Plan Changes Associated With XML Format

Data element(s) or requirement(s)

Proposed action(s)

Comments

• Facility short name

• Unit program classification

• Unit boiler type

• Date of commence operation (Subpart H units)

• Date of commence commercial operation (Acid Rain units)

• Unit retirement date

• Program code

• Reporting frequency

• Program participation date

• State regulation code

• State or local agency code

• EIA cross-reference information.

Remove

These data elements would be collected and maintained through the Certificate of Representation form, the CAMD Business System, or internally by EPA.

• Recording and reporting of information associated with monitoring system certification, recertification, and other events

Relocate

Relocate the requirement to record and report this information to § 75.59, the quality-assurance recordkeeping section.

• Fuel classification for boiler

• Primary/secondary control indicator

• Type of fuel associated with each monitoring methodology

• Primary/secondary methodology indicator

• Appendix E correlation curve segment data.

Remove

These data elements are deemed unnecessary for the new XML reporting format.

• Component status

• Formula status

• Submission status of fuel flowmeter data.

Replace

In § 75.53(g), use activation date/hour and deactivation date/hour instead of status codes to better track updates to monitoring components, formulas, and fuel flowmeter information.

• Indicator of exemption from multi-load flow RATAs

• Shape of stack or duct cross-section

• Stack/duct material of construction

• Flag to indicate that a monitored location is a duct

• Indicator of non-load based units.

Add

These new data elements are needed to properly assess specific Part 75 quality assurance/quality control (QA/QC) requirements and exemptions.

• Analyzer range code

• Moisture measurement basis.

Add

Provide the measurement range (high, low, dual) and moisture basis (wet or dry) for each CEMS component type (SO

, NO

, CO

, etc.)

• Provide the monitoring methodologies for each individual unit

• Represent bypass stack monitoring as a separate methodology.

Replace

For each parameter, associate the monitoring methodology with the monitored lcoation (unit, stack or duct). Integrate bypass stack monitoring with other methodologies. Only one monitoring methodology per paramter would be allowed.

• For dual-range applications, indicate the trigger point at which the component switches from the normal measurement scale to the secondary scale

Add

Many times data begin to be recorded on the high scale at a certain “trigger point”, before the full-scale of the low range is reached. EPA needs this information to determine when certain QA tests of the high-scale are required.

• Require operating range and normal load information to be reported for units with CEMS and units using optional fuel flow-to-load ratio test

Revise

In § 75.53(g), require operating range and maximum load information for all affected units. Require normal load determination for all except peaking units. Separate the date of historical load analysis from activation date of the operating range and load information.

• Duct width at test section

• Duct depth at test section

• WAF

• Method of determining WAF

• WAF effective date and hour

• WAF no longer effective date and hour

• WAF determination date

• Number of WAF test runs

• Number of Method 1 traverse points in WAF test

• Number of test ports in WAF test

• Number of Method 1 traverse points in reference flow RATA.

Add

Add data elements to § 75.53(e) and (g), describing monitoring plan requirements for units with rectangular ducts that apply a wall effects adjustment factor (WAF) to their flow rate data. (

See

Section II.E.2 for further discussion.)

2. Discussion of Wall Effects Adjustment Requirements for Rectangular Ducts

In 1999, EPA published a new reference method, Method 2H, in Appendix A of 40 CFR Part 60. Method 2H allows the owner or operator of a unit with an installed flow monitor to correct the measured gas flow rates for velocity decay near the stack wall (

i.e.,

“wall effects”). Applying Method 2H greatly reduces the possibility of over-reporting SO

and NO

mass emissions, which are directly proportional to the stack flow rate. However, Method 2H applies only to circular stacks. Consequently, Acid Rain and NO

Budget Program units with flow monitors installed on rectangular stacks or ducts (estimated at about 10 percent of the affected units with flow monitors) were unable to benefit from the use of a wall effects adjustment factor (WAF).

To remedy this situation, a wall effects correction method for rectangular stacks and ducts was developed. The method, known as CTM-041, has been adopted as a conditional test method by EPA. A conditional test method differs from a reference method in that it is not in the Code of Federal Regulations, but it is recognized as having technical merit. Sources interested in using a conditional method in a particular program must obtain permission from the regulatory agency administering the program.

Since 2004, when CTM-041 was adopted as a conditional EPA test method, many Acid Rain and NO

Budget Program sources have requested (and received) permission from EPA to use it for Part 75 monitoring. As a condition of these approvals, the sources were asked to report the essential wall effects information in their quarterly electronic data reports (EDRs). However, EPA had not developed the necessary electronic record types (RTs) to accommodate the rectangular duct WAF information. Therefore, the Agency issued guidance, instructing the sources to use existing EDR record type 910 to report the WAF data. But record 910, unlike the other EDR record types, has no fixed data elements or fields. This created problems when the WAF information began to be reported. Even though detailed examples were provided in the EPA guidance, a significant portion of the WAF data were being entered into the wrong columns of the 910 records, making it difficult to perform electronic audits of the information.

In view of this, EPA created two new EDR record types, RT 532 and RT 617, to handle the rectangular duct WAF data. Record type 532, which is a monitoring plan record, summarizes the results of each WAF determination. Record type 617 is a quality-assurance record and is submitted along with the results of each flow RATA performed at a rectangular stack or duct, when EPA Method 2 is used and a wall effects correction is applied.

The Agency provided a mechanism (the “Monitoring Data Checking” (MDC) Software) by which a source could

create the new EDR records and add them to the quarterly report, without having to upgrade the data acquisition and handling system (DAHS). To date, use of the new record types has been voluntary, and the affected sources have been cooperative. Nevertheless, today's rule would make mandatory the recording and reporting of the key rectangular duct WAF data elements using these record types. The proposed requirements to record and report the results of the WAF determinations in the monitoring plan are found in §§ 75.53(e) and (g) and in § 75.64. For a discussion of the proposed requirement to record and report the RATA support data, see Section II.E.5.k, below.

3. Revisions to General Recordkeeping Provisions for Specific Situations

Today's proposed rule would make a series of modifications to § 75.58 to support the new XML data structure. These are summarized in Table 2.

Table 2.—Proposed Changes to the General Recordkeeping Requirements in § 75.58

Data element(s) or requirement(s)

Proposed action(s)

Comments

• For Appendix D units, report ID numbers of formulas used to calculate SO

mass emissions and heat input rate

Add to § 75.58(c)

This would be required on and after January 1, 2009.

• For Appendix E units, report the heat input rate formula ID for each unit operating hour

Add to § 75.58(d)

This would be required on and after January 1, 2009.

• For LME units that combust more than one type of fuel, report the fuel type that produces the highest NO

emission rate

Revise § 75.58(f)

Report the fuel type that produces the highest emission rate for each parameter individually (

i.e.,

for SO

, NO

, and CO

as applicable).

• For LME units under § 75.19(c)(1)(iv)(C)(9), indicate whether unit is operating at base or peak load, each hour

Add to § 75.58(f)

This flag is needed to ensure that the proper NO

emission factor is being applied.

• For LME units, flag each hour in which multiple fuels are combusted

Add to § 75.58(f)

This flag is needed to ensure that the proper emission factors are used for multiple-fuel hours.

• For LME units using long-term fuel flow, report the component and system ID codes

Revise § 75.58(f)

Require only the system ID. Long-term fuel flow systems have only one component.

4. Proposed Revisions to the QA/QC Recordkeeping Provisions

EPA is proposing to make a series of revisions and additions to the quality assurance and quality control recordkeeping provisions in § 75.59, in support of the XML data format. These are summarized in Table 3.

Table 3.—Proposed Changes to the QA/QC Recordkeeping Provisions of § 75.59

Data element(s) or requirement(s)

Proposed action(s)

Comments

• Describe each recertification event, and the date and type of each recertification test

Revise § 75.59(a)(8)

Expand to include events that require certification and diagnostic testing. Add requirement to report conditional data validation begin date (if applicable). Corresponds to current EDR record type 556.

• Record component and system ID codes for daily calibrations, 7-day calibration error tests, cycle time tests, linearity checks, flow monitor leak checks and interference tests, and fuel flowmeter accuracy tests

Revise §§ 75.59(a) and (b)

Require only the component ID for these tests. This requirement would be effective on and after January 1, 2009. The cycle time test for NO

-diluent systems would be simplified.

• Record the test number and reason for test, for daily calibrations and 7-day calibration error tests

Revise § 75.59(a)(1)(viii)

Clarify that test number and reason for test code apply only to 7-day calibration error tests, not to daily calibrations.

• Report the span value with the results of each linearity check

Remove from § 75.59(a)(3)(ii)

The span value in the monitoring plan records will be used to evaluate the linearity checks.

• Provide an on-line or off-line indicator flag for all calibration error tests

Add to § 75.59(a)(1)

This flag is needed to properly assess the hour-by-hour quality-assurance status of CEMS following calibration error tests.

• For flow-to-load tests of multiple stack configurations, indicate whether separate reference ratios are calculated for each stack

Add, as § 75.59(a)(4)(vii)(M)

This addition is needed for consistency with the flow-to-load test reporting instructions (current EDR record type 605).

• Report sufficient information to validate all grace period claims

Remove and reserve § 75.59(a)(12)(iii)

EPA's checking software no longer needs this information to evaluate grace periods.

• Record the component and system ID codes for each fuel flow-to-load ratio test

Revise § 75.59(b)(4)(i)(A)

On and after January 1, 2009, record only the system ID for these tests.

• Report Appendix E correlation curve test data on a monitoring system basis

Revise § 75.59(b)(5)

On and after January 1, 2009, report this data on a component basis.

• Report the type(s) of fuel(s) combusted during each run of an Appendix E correlation curve test

Remove § 75.59(b)(5)(i)(H)

This information is not needed in the new XML format and would not be reported after December 31, 2008.

• Report the monitoring system ID code with reference fuel flow-to-load ratio test data

Add, as § 75.59(b)(4)(ii)(N)

This requirement is consistent with the reporting instructions for the reference fuel flow-to-load ratio (current EDR record type 629).

• For LME units, indicate which test runs are used to calculate fuel-and-unit-specific NO

emission rates

Add, as § 75.59(d)(1)(xiii)

This requirement is consistent with the reporting instructions for NO

emission testing of LME units (current EDR version 2.2, record type 650).

• For LME units, multiply the tested NO

emission rate by 1.15, if applicable

Revise § 75.59(d)(2)(iii) and add new §§ 75.59(d)(2)(vi) and (vii)

This requirement applies only to turbines that operate only at base or peak load. Consistent with the reporting instructions (current EDR version 2.2, record type 650), reporting of an hourly base or peak load indicator and the default NO

emission rate for peak load operation would be required.

• Record the date and hour of completion of all required DAHS verifications, whether for initial certification, recertification, or other events

Add § 75.59(f)

This requirement would be effective on and after January 1, 2009. EPA needs this information to properly establish provisional certification or recertification dates. Proposed changes to § 75.63(a)(2)(iii) would allow this information to be reported electronically as part of the certification or recertification application.

• Record the appropriate reference method data elements for Hg emission tests of low-emitting units

Add § 75.59(e)

For periodic testing of low mass emission units, recording of the reference method data elements in either § 75.59(a)(7)(vii), (viii), or (x) would be required, depending on which reference method is used for the testing.

• Monitoring system ID

• Test number

• Operating level

• RATA end date and time

• Number of Method 1 traverse points

• Wall effects adjustment factor

Add, as § 75.59(a)(7)(ix)

Recording of certain data elements and test results would be required for units with rectangular ducts/stacks that apply a wall effects adjustment factor (WAF) to correct their flow rate data. These data elements would be required for each flow RATA.

• Percent CO

and O

in the stack gas, dry basis

• Moisture content of the stack gas (percent H

• Average stack gas temperature (°F)

• Dry gas volume metered (dscm)

• Percent isokinetic

• Particulate Hg collected in the front half of the sampling train, corrected for the front-half blank value (μg)

• Total vapor phase Hg collected in the back half of the sampling train, corrected for the back-half blank value (μg)

Add, as § 75.59(a)(7)(x)

Recording of certain data elements would be required when using Method 29 for the RATA of a Hg monitoring system. These data elements would be required for each RATA run.

5. Other Reporting Issues

a. Long-Term Cold Storage and Deferred Units

The proposed changes to Part 75 would clarify the issue of “long-term cold storage (LTCS)”. First, as previously noted, a definition of “long-term cold storage” would be added to § 72.2. LTCS would mean that the unit has been completely shut down and placed in storage and that the shutdown is intended to last for an extended period of time (at least two calendar years). Second, a new paragraph, (a)(7), would be added to § 75.61. Proposed § 75.61(a)(7) would require the owner or operator to provide notifications when a unit is placed in LTCS and when the unit re-commences operation. Third, § 75.20(b) would be modified to require recertification of all monitoring systems when a unit re-commences operations after a period of long-term cold storage. If a source claiming LTCS status re-commenced operation sooner than two years after being placed in LTCS, the notification and recertification requirements would apply. Fourth, the proposed rule would exempt a unit in LTCS from quarterly emissions reporting under § 75.64 until the unit recommences operation. Parallel rule provisions and appropriate cross-references regarding quarterly reporting requirements for Subpart H and Subpart I units would be added to §§ 75.73(f)(1) and 75.84(f)(1), respectively. Finally, EPA notes that these proposed LTCS provisions are not intended to apply to periods of non-operation of units that are “on-call” and available for dispatch.

EPA also proposes to revise the provisions of §§ 75.4(d) and 75.61(a)(3) pertaining to “deferred” units,

i.e.

, units for which a planned or unplanned outage prevents the required continuous monitoring systems from being certified by the compliance date. The scope of § 75.4(d) would be broadened beyond the Acid Rain Program to include units in a State or Federal pollutant mass emissions reduction program that adopts the monitoring and reporting provisions of Part 75. Examples of such programs include the Clean Air Interstate Regulation (CAIR), which is scheduled to begin in 2008 and the Clean Air Mercury Regulation (CAMR), which goes into effect in 2009. The revisions to §§ 75.4(d) and 75.61(a)(3) are deemed necessary because the CAIR and CAMR rules do not address deferred units.

Revised § 75.4(d) would require the owner or operator of a deferred unit to provide notice of unit shutdown and recommencement of commercial operation, either according to § 75.61(a)(3) (for planned shutdowns such as scheduled maintenance outages and for unplanned, forced unit outages) or § 75.61(a)(7) (for units in long-term cold storage). For all of these circumstances involving deferred units, the Part 75 continuous monitoring systems would have to be certified within 90 unit operating days or 180

calendar days (whichever comes first) of the date that the unit recommences commercial operation. In the time interval between the unit re-start and the completion of the required certification tests, the owner or operator would be required to report emissions data, using either: (1) Maximum potential values; (2) the conditional data validation procedures of § 75.20(b)(3); (3) EPA reference methods; or (4) another procedure approved by petition to the Administrator under § 75.66.

Today's proposed rule would revise the notification requirements of § 75.61(a)(3) to be consistent with the changes to § 75.4(d). For planned unit outages, the owner or operator would be required to provide notice of shutdown at least 21 days prior to the compliance date. For unplanned outages, notice would be provided within 7 days after the shutdown. For both planned and unplanned outages, notice of the date on which the unit is expected to resume operation would be provided at least 21 days prior to that date. Proposed § 75.61(a)(3) also includes provisions to address situations in which there are changes to any of the planned or projected dates.

b. Notice of Initial Certification Deadline

EPA proposes to revise § 75.61(8) to require new and newly-affected sources to notify EPA when the monitoring system certification deadline is reached. Depending on the program(s) to which the unit is subject and whether the unit is new or newly-affected, this date will be the earlier of 90 unit operating days or 180 calendar days after the unit: (a) Commences commercial operation; (b) commences operation; or (c) becomes an affected unit. The Agency must know this date to correctly assess when to begin counting emissions against allowances pursuant to § 72.9. Knowing this date also confirms that the monitoring systems either have or have not been certified by the legal deadline.

c. Monitoring Plan Submittal Deadline

Today's proposed rule would change the submittal deadline for the initial monitoring plan for new and newly-affected units from 45 days to 21 days prior to the initial certification testing. This proposed revision would synchronize the initial monitoring plan submittal with the initial test notice (

see

proposed changes to §§ 75.62(a)(1) and (2), §§ 75.73(e)(1) and (2) for Subpart H units, and §§ 75.84(e)(1) and (e)(2) for Subpart I units).

EPA also proposes to remove the requirement in § 75.62(a)(1) that the monitoring plan must be submitted “in each electronic quarterly report”. Rather, inclusion of the monitoring plan in the report would be optional, and monitoring plan updates would be made either prior to or concurrent with (but not later than) the date of submission of the quarterly report. These proposed revisions would allow sources to maintain their monitoring plan information separate from the quarterly report. However, this flexibility would only be available to sources reporting in the new XML-EDR format under the re-engineered data submission process. Until re-engineering of the data systems is complete, EPA will continue to collect and process all electronic monitoring plan data submitted in quarterly reports in the current EDR format.

d. EPA Form 7610-14

For each certification and recertification application, §§ 75.63(a)(1) and (a)(2) require hardcopy EPA form 7610-14 to be submitted to the Administrator along with the certification or recertification test results in EDR format. However, significant upgrades to EPA's data systems have been made in recent years, and Form 7610-14 is no longer needed to process the applications. Therefore, §§ 75.63(a)(1)(i)(A) and (a)(2)(i) would be revised to remove the requirement to submit Form 7610-14 to the Administrator.

e. LME Applications

EPA is proposing to remove the requirement from § 75.63(a)(1)(ii)(A) for a hardcopy LME certification application to be submitted to the Administrator. Only the electronic portion of the application, including the monitoring plan and LME qualification records, would be sent to EPA. The hardcopy portion of the LME application would be sent to the State and to the EPA Regional Office.

f. Reporting Test Data for Diagnostic Events

EPA proposes to revise § 75.63(a)(2)(iii) to make the reporting of the results of diagnostic tests more flexible. Rather than requiring these test results to be reported in the electronic quarterly report for the quarter in which the tests are performed, they could either be submitted prior to or concurrent with that quarterly report. However, this flexibility in the reporting of diagnostic test results would only be available to sources reporting in the new XML-EDR format under the re-engineered data submission process. Until re-engineering of the data systems is complete, EPA will continue to collect and process all diagnostic test results submitted in quarterly reports in the current EDR format.

g. Modifications to § 75.64

As part of its data systems re-engineering effort, EPA proposes to revise § 75.64(a) to incorporate language describing the transition from the current reporting requirements of paragraphs (a)(1), (a)(2) and (a)(8) through (a)(15) to the new requirements of paragraphs (a)(3) through (a)(15). Note that only the requirements of paragraphs (a)(1) and (a)(2) of the current rule would be replaced, by the requirements of paragraphs (a)(3) through (a)(7). Proposed paragraphs (a)(3) through (a)(7) better describe the separation of the monitoring plan and quality assurance test information from the quarterly emissions report. Current paragraphs (a)(3) through (a)(7) and (a)(9) through (a)(11) would remain unchanged, but would be renumbered as paragraphs (a)(8) through (a)(15). Current paragraph (a)(8) would be removed.

h. Steam Load Reporting

Historically, Part 75 has required units that produce electrical or thermal output to report unit load either in megawatts or in thousands of pounds per hour of steam. Today's proposed rule would add a third option,

i.e.

, to report load in units of mmBtu/hr of steam thermal output. This option is needed to accommodate emissions trading programs in which allowance allocations are made on an electrical or thermal output basis, rather than a heat input basis. Certain units in these programs (

e.g.

, industrial boilers) do not produce electrical output and would have to report thermal output instead. In the current rule, steam load is expressed only in thousands of pounds per hour, which does not provide the necessary thermal output information. EPA therefore proposes to add text to the following sections of Part 75, describing the new thermal output reporting option: §§ 75.16(e)(3), 75.57(b)(3), 75.59(b)(4)(ii); Appendix A, Sections 7.7(a) and 7.7(c); Appendix B, Sections 2.2.5(a) and 2.2.5(a)(2); Appendix D, Sections 2.1.7.1(a), 2.1.7.1(c), 2.1.7.2(a), and 2.1.7.2(c); and Appendix E, Section 2.4.1.

i. Test Notification Requirements—Hg Low Mass Emission Units

Section 75.61(a)(5) of the current rule requires the owner or operator or the designated representative to provide 21-day advance notice for various periodic quality-assurance tests. In particular, this notice must be provided to the

Administrator, to the appropriate EPA Regional Office and to the State or local agency (unless a particular agency issues a waiver from the requirement) for the semiannual or annual relative accuracy tests of CEMS, and for re-tests of both Appendix E peaking units and low mass emissions (LME) units.

Under Subpart I of Part 75, certain low-emitting units covered by CAMR may qualify under §§ 75.81(b) through (d) to perform periodic (semiannual or annual) Hg emission testing in lieu of operating and maintaining continuous Hg monitoring systems. Today's proposed rule would expand § 75.61(a)(5) and add corresponding introductory text to § 75.61(a)(1) to require the owner or operator or the designated representative to provide 21 day notice of these periodic Hg emission tests to EPA and to the State.

j. Hardcopy Reports for Retests of Hg Low Mass Emission Units

Sections 75.60(b)(6) and (b)(7) of the current rule require the designated representative (DR) to submit the results of certain periodic quality-assurance tests to the appropriate EPA Regional Office or to the State or local agency, when the test results are requested in writing (or by electronic mail). In particular, the results of semiannual or annual RATAs of CEMS and the routine re-tests of Appendix E units may be requested. If requested, the test results must be submitted within 45 days after the test is completed or within 15 days of the request, whichever is later. Today's rule would add a new paragraph (b)(8) to § 75.60, requiring the DR to provide, upon request from EPA or the State, the results of the semiannual or annual mercury emission tests required under § 75.81(d)(4) for low-emitting units covered by CAMR. The time frame for submitting these Hg emission test results would be the same as for the RATAs and Appendix E re-tests.

k. Wall Effects Adjustment Factors

As previously discussed in Section II.E.2 of this preamble, today's rule would require sources with flow monitors installed on rectangular stacks or ducts to report the results of wall effects adjustment factor (WAF) determinations in the monitoring plan, whenever Conditional Method CTM-041 is used to adjust the measured stack gas flow rates for the effects of velocity decay near the stack wall.

For sources with flow monitors installed on circular stacks, reporting of wall effects information is currently required when Method 2H is used in conjunction with Method 2, 2F or 2G (

see

§§ 75.64(a)(2)(xiii), 75.73(f)(1)(ii)(K) and 75.84(f)(1)(ii)(I)). The wall effects data elements that must be reported are found in §§ 75.59(a)(7)(ii) and (a)(7)(iii). These data are not reported in the monitoring plan, but are submitted along with flow RATA results, as supplementary information.

For rectangular stacks and ducts, some of the same supporting data elements in §§ 75.59(a)(7)(ii) and (a)(7)(iii) are needed for flow RATAs performed using Method 2F or 2G, when wall effects corrections are applied. Additional supporting data elements, not in the current rule, are also needed for Method 2 flow RATAs when wall effects adjustments are made. In view of this, today's rule would revise the text of §§ 75.64(a)(2)(xiii), 75.73(f)(1)(ii)(K) and 75.84(f)(1)(ii)(I) and would add RATA support data elements to a new paragraph, (vii), in § 75.59(a)(7). EPA believes that these proposed changes will clarify which wall effects data elements must be reported for circular stacks, which ones are reported for rectangular stacks and ducts, and which data elements must be reported for both types of stacks.

F. Subpart H (NO

Mass Emissions)

1. Subpart H Diluent Monitoring Systems

For coal-fired Subpart H units that calculate NO

mass emissions as the product of NO

concentration and flow rate and are required to monitor and report the unit heat input, § 75.71(a)(2) requires the installation of an “O

or CO

diluent gas monitor”. Consistent with the definition of a CEMS in § 72.2, this diluent monitor, which is only used for the heat input determination, should be described as an “O

or CO

monitoring system”. Today's proposed rule would revise the text of § 75.71(a)(2) accordingly.

2. Identifying a NO

Mass Methodology

EPA is proposing to revise § 75.72 to clarify that only one NO

mass emissions methodology may be identified in the monitoring plan at any given time. Designation of primary and secondary NO

mass calculation methodologies would no longer be allowed. EPA believes that one methodology for NO

mass emissions is sufficient. If a source is subject to both Subpart H and to the Acid Rain Program (ARP) and is concerned about losing NO

data when the diluent component of the NO

emission rate system is out-of-control, that source should choose the NO

concentration times flow rate calculation method as the NO

mass calculation methodology. This would require a NO

concentration system to be identified in the monitoring plan, in addition to the NO

emission rate system. The NO

concentration system would be used only to determine NO

mass emissions, and the NO

emission rate system would be used only to meet the ARP requirement to report NO

in lb/mmBtu.

Although it is possible with the current EDR format to identify multiple methodologies for a parameter, this was intended for ARP applications, not for NO

mass emission measurement. Multiple methodology records for SO

are sometimes necessary when a bypass stack is used. However, as discussed in Section II.E.1 of this preamble, the reporting of monitoring methodologies is being restructured as part of EPA's re-engineering effort. Bypass stack methods are being integrated with other monitoring methods and will no longer be considered stand-alone methodologies.

3. Reporting of Subpart H Facility Information

Consistent with the proposed revisions to § 75.64, EPA proposes to revise § 75.73(f)(1), to phase out the requirement of § 75.73(f)(1)(i)(B) to include facility location information in each quarterly report.

4. Linearity Check Requirements for Ozone Season-Only Reporters

For Subpart H sources that report emissions data on an ozone season-only (OSO) basis, today's proposed rule would revise the linearity check provisions in §§ 75.74(c)(2), (c)(2)(i), (c)(2)(ii), (c)(3)(ii), (c)(3)(vi), and (c)(3)(viii). Currently, OSO reporters are required to do a pre-season linearity check, an in-season second quarter linearity check (in May or June, if the unit operates for ≥168 hours in May and June), and a third quarter linearity check, if the unit operates for ≥168 hours in that quarter. Many sources have misunderstood these rule provisions, particularly the requirement to perform an in-season linearity check in the second quarter.

Since the beginning of the NO

Budget Program, there have been a number of instances where sources have performed pre-season linearity checks in April, but have not done the required in-season linearity checks in May or June. In some cases, this has resulted in CEMS out-of-control periods and has required the use of missing data substitution. These sources apparently believed that the April tests were sufficient to satisfy both the pre-season and second quarter linearity check requirements because for year-round

reporters, linearity checks are required only once per quarter.

The current rule also requires OSO reporters to operate and maintain each CEMS and to perform daily calibration error tests, in the time period extending from the hour of completion of the pre-season linearity check through April 30. EPA has found that this rule provision is not well-understood by the affected sources. It is also difficult for the Agency to assess compliance with the provision, since sources are not required to report the results of any off-season calibration error tests done prior to April. Further, when pre-season linearity checks are done several months before the ozone season, the quality of the data at the start of the ozone season is somewhat questionable.

In view of these considerations, today's proposed rule would revise § 75.74(c)(2) to restrict the time period in which pre-season linearity checks may be conducted. EPA proposes to require the pre-season linearity checks to be done in the month of April. All references to performing the pre-season linearity checks at other times would be deleted, along with the requirement to keep the off-season daily calibration error tests in a format suitable for inspection.

Today's proposed rule would also revise § 75.74(c)(2)(i)(D) by removing the conditional grace period provision and adding a cross-reference to proposed § 75.74(c)(3)(ii)(E), which addresses data validation. If the April linearity check is not completed prior to the start of the ozone season, data from the monitor would be considered invalid as of May 1, unless the conditional data validation procedures of § 75.20(b)(3) are applied. Proposed § 75.74(c)(3)(ii)(E) would allow a probationary calibration error test to be done, to begin a period of conditional data validation. Then, the linearity check would be done “hands-off” within a 168 unit operating hour period following the calibration error test. If the linearity check is passed within the allotted time, the conditionally valid data would be considered quality-assured, back to the hour of the probationary calibration error test. If the linearity check is failed, all data from the monitor would be invalidated back to the beginning of the ozone season and would remain invalid until a linearity check is passed. If the linearity check is done after the 168-hour period expires, data validation would be done according to § 75.20(b)(3)(viii), subject to the restrictions of § 75.74(c)(3)(xii).

Today's proposed rule would add a new paragraph (F) to § 75.74(c)(3)(ii), stating that a pre-season linearity check done in April fulfills the second quarter linearity check requirement. Related Section 75.74(c)(3)(viii) would be removed and reserved. Further, proposed § 75.74(c)(3)(ii)(B) would require the third quarter linearity check to be conducted either by July 30 or within a 168 operating hour period of conditional data validation thereafter. Finally, proposed § 75.74(c)(3)(ii)(G) would address the case where a unit operates infrequently and the 168 operating hour conditional data validation period associated with the April linearity check extends through the second quarter, into the third quarter. In that case, if the linearity check is performed and passed in the third quarter, before the 168 operating hour window expires, then that one linearity check would satisfy all three of the ozone season linearity check requirements,

i.e.

, for the pre-season, for the second quarter, and for the third quarter.

EPA believes that the proposed linearity check schedule for OSO reporters would ensure that the gas monitors' response is linear throughout the ozone season and would simplify the regulation by reducing the number of required linearity checks from three to two (and in some cases, one) per season.

5. RATA Requirements for Ozone Season Only Reporters

For OSO reporters, Part 75 requires, for quality-assurance purposes, that at the start of each ozone season each required CEMS must be within the “window” of data validation of a current, non-expired RATA. Section 75.74(c)(2)(ii) states that this requirement can be met either by performing a RATA in the pre-season (between October 1 and April 30) or, in some instances, by relying on the results of a RATA done in the previous ozone season. For example, if a RATA was performed inside the ozone season, in the 3rd quarter of last year, the window of data validation for the test would extend through the 3rd quarter of this year, provided that the RATA results show that the CEMS qualifies for an “annual” RATA frequency. However, if a “semiannual” test frequency is obtained, the data validation window would expire at the end of the first quarter of this year, and the RATA could not be used to validate data in the current ozone season. Therefore, a pre-season RATA would be required.

The rule further requires each CEMS to be operated, calibrated and maintained in the time period extending from the completion of the RATA, through April 30. This means that if the RATA being used for data validation in the current ozone season was performed during the last ozone season, the CEMS would have to be operated, calibrated and maintained for the entire off-season from October 1 through April 30. Compliance with this type of requirement is difficult for EPA to assess, as previously explained in paragraph 4 of this section. Also, many sources choosing the OSO reporting option find this operation and maintenance (O&M) requirement to be counter-intuitive, because they expect to be required to meet Part 75 monitoring obligations only during the ozone season. If it were discovered during an audit that this O&M requirement had not been met, a facility could incur substantial data loss. Further, if a CEMS is not maintained in a manner consistent with normal operating practices for an extended period of time following a RATA that was done long before the ozone season, the results of that RATA may not be a true indicator of the CEMS data quality at the start of the ozone season.

In view of these considerations, EPA is proposing to restrict the window of time in which pre-season RATAs may be performed. Proposed § 75.74(c)(2)(ii) would require the RATAs to be done either in the first quarter of the year or in the month of April. This restriction would prohibit RATAs done in the previous year from being used to validate data in the current ozone season.

Section 75.74(c)(2)(ii)(F) would be revised to address data validation. The proposed data validation rules for RATAs would be similar to those proposed for linearity checks,

i.e.

, a period of conditional data validation (720 operating hours) would be allowed when the pre-season RATA is not completed by the April 30 deadline. Consistent with these revisions, today's proposed rule would delete the data validation and conditional grace period provisions in §§ 75.74(c)(2)(ii)(G) and (c)(2)(ii)(H) and would remove and reserve §§ 75.74(c)(3)(vi), (vii), and (viii).

Note that EPA is not modifying the provisions of § 75.74(c)(3)(xii), which allows the results of required quality assurance tests that are completed early in the fourth quarter, within a window of conditional data validation, to be submitted with the electronic data report for the third quarter. This provision provides sources with a “last chance” opportunity to complete the required quality assurance tests before the final ozone season reports for the NO

Budget program are due.

6. Determining Peaking Status for Ozone Season Only Reporters

EPA proposes to revise § 75.74(c)(11) to clarify that when peaking unit status for ozone season-only reporters is determined, 3,672 hours (

i.e.

, the number of hours in the ozone season) should be used instead of 8,760 hours in the capacity factor equation. This clarification is supported by Question 27.1 in the “Part 75 Emissions Monitoring Policy Manual”.

7. Calculation of Ozone Season NO

Mass Emissions—LME Units

Today's rule would correct an organizational error in Subpart H of Part 75. Section 75.72(f), which describes ozone season NO

mass calculations for units using the low mass emission (LME) methodology under § 75.19, would be removed, and its basic content would be relocated to § 75.71(e). The LME provision in § 75.72 appears to have been inadvertently placed in that section. The monitoring provisions of § 75.72 apply to common and multiple stack configurations, whereas § 75.71 addresses unit-level monitoring. LME is a unit-level monitoring methodology.

G. Subpart I (Hg Mass Emissions)

1. Heat Input Provisions for Common and Multiple Stacks

Subpart I of Part 75 provides the basic procedures for monitoring Hg mass emissions and heat input from affected units under CAMR. However, due to an apparent oversight, the heat input monitoring provisions for certain monitoring configurations were inadvertently omitted from the final rule. In particular, the heat input methodology for common stacks shared by affected and non-affected units, and the methodology for multiple stack or duct configurations are missing. Today's rule would add three new paragraphs, (b)(3), (c)(4) and (d)(3) to § 75.82 to correct this deficiency.

For the common stack shared by affected and non-affected units, proposed § 75.82(b)(3) would require the owner or operator to either measure the total heat input rate at the common stack and apportion it to the individual units by load, according to § 75.16(e)(3), or to determine the heat input rate at the individual units by installing a flow monitor and a diluent monitor on the duct leading from each unit to the common stack. For multiple stack configurations, proposed §§ 75.82(c)(4) and (d)(3) would require the owner or operator to determine the hourly unit heat input by measuring the hourly heat input rate (mmBtu/hr) at each stack, multiplying each stack heat input rate by the stack operating time (hr) to convert it to heat input (mmBtu), and then summing the hourly stack heat input values.

2. Low Mass Emission Alternative

Section 75.81(b) of Subpart I provides an alternative (“excepted”) monitoring methodology for units with low Hg mass emissions. To qualify to use this methodology, emission testing is required to demonstrate that the unit has the potential to emit no more than 29 lb (464 ounces) of Hg per year. Once a unit qualifies, periodic retesting (semiannual or annual, depending on the emission level) is required to demonstrate that the unit is actually emitting less than 29 lb/yr of Hg.

Section 75.81(e) allows the low mass emission alternative to be used for common stacks, provided that the units sharing the stack are tested individually and each one qualifies as a low-emitter. Though not explicitly stated in the rule, it is implied that the periodic retests for common stack configurations would also have to be done at the unit level. EPA is reconsidering this approach, for two reasons: (1) With respect to the initial certification testing, it appears to be overly restrictive for at least one particular configuration; and (2) the Agency believes that for the retests it may be unnecessarily difficult and costly to implement.

Therefore, with one exception (discussed below), EPA is proposing to revise § 75.81(e) to require Hg testing of the individual units that share the common stack only for the initial demonstration that the units individually qualify as low emitters. Once this has been satisfactorily demonstrated, the required semiannual or annual retests could then be done at the common stack, at a normal load level for the configuration.

The proposed revisions to § 75.81(e) would also allow the initial low mass emitter qualification for a group of identical units sharing a common stack to be based on emission testing of a subset of those units. To exercise this option, the units would first have to qualify as identical under § 75.19(c)(1)(iv)(B). Then, the number of units required to be tested would be determined from Table LM-4 in § 75.19.

The proposed rule would allow one exception to the requirement to test the individual units sharing a common stack, in order to demonstrate that the units qualify for low mass emitter status. In the case where the gas streams from the individual units are combined together and routed through emission controls that reduce the Hg concentration (

e.g.

, a wet scrubber) before entering the common stack, the only way to measure the controlled Hg concentration from the individual units would be to operate them one at a time rather than concurrently. EPA believes that for many such configurations, this manner of unit operation is abnormal and potentially problematic. Therefore, the revisions to § 75.81(e) would allow both the initial and ongoing low mass emission testing to be done at the common stack in cases where the individual unit effluent gas streams are combined together upstream of a control device that removes Hg before entering the common stack. Owners or operators electing to use this option would be required to perform the testing with all of the units that share the stack in operation, and the combined load during the testing would be “normal”, as defined in Section 6.5.2.1 of Appendix A.

Today's proposed rule would also revise § 75.81(c)(1), to clarify the time frame in which to perform the initial certification testing for the low mass emission option. The current rule simply states that this testing must be done “prior to the compliance date in § 75.80(b)”, but does not specify how far in advance of that date the testing may be done and still be considered acceptable. Further, § 75.81(d)(1) requires the test results to be submitted as a certification application, no later than 45 days after completing the testing. And § 75.81(d)(4) requires periodic Hg retesting to commence within two or four “QA operating quarters” after the quarter of the certification testing.

This approach to implementing the low mass emission alternative should work reasonably well, provided that the certification test date is close in time to the compliance date. However if there is too long a gap between the certification testing and the start of the program, it becomes problematic. For instance, if the testing is done too early, the requirement to submit a certification application within 45 days could result in applications being submitted long before the regulatory agencies are ready to receive and process them. Also, the periodic retesting requirements of § 75.81(d)(4), which become active on the certification test date, could result in several Hg retests being done before the program begins. This is clearly contrary to the purpose of the retests, which, like the periodic relative accuracy tests of CEMS, are intended to commence after the compliance date, when Hg emissions reporting has begun. It also raises questions about which default emission rate to use for the initial reporting. In view of these

considerations, EPA is proposing to revise § 75.81(c)(1), to require that the Hg testing for initial certification be done no more than 1 year before the compliance date. Sections 75.81(d)(2) and 75.81(d)(5) would also be revised, to address the case where a retest may be required before the compliance date (

e.g.

, when § 75.81(d)(4) requires a retest within two QA operating quarters, following a certification test that was done 9 to 12 months before the compliance date). In such cases, the default Hg emission rate used at the beginning of the program would be the value that was obtained in the retest.

Finally, EPA proposes to amend § 75.81(d)(4) to address the emission testing requirements when the fuel supply is changed. Revised § 75.81(d)(4) would require additional Hg retesting within 720 unit operating hours, following a change in the fuel supply. The results of this retest would be applied retrospectively, back to the time of the fuel switch. Section 75.81(c)(1) would also be revised to require that the fuel combusted during the initial certification testing be from the same source of supply as the fuel combusted when the program starts. The Agency believes these rule provisions are necessary to ensure that the default Hg concentration used for Part 75 reporting is representative of the fuel being combusted in the unit. However, note that the proposed revisions only address the emission testing and reporting requirements for one case,

i.e.

, where the source of supply for the primary fuel (assumed to be coal) changes. Cases where the coal supply does not change, but the unit sometimes burns other types of fuel besides coal or co-fires mixtures of coal and other fuels, are not addressed. In view of this, EPA also solicits comments and suggestions on how to apply the Hg low mass emitter option in these situations (

i.e.

, what emission testing and reporting requirements might be appropriate).

3. Harmonization of Subpart I With Other Proposed Rule Revisions

Subpart I of Part 75 also contains a recordkeeping and reporting section (§ 75.84). Section 75.84 contains a few stand-alone provisions, but for the most part, it cross-references the primary monitoring plan, recordkeeping, notification and reporting sections of the rule (

i.e.

, §§ 75.53, 75.57 through 75.59, 75.61, and 75.64) and other sections of Subpart I.

As discussed in detail in Section E of this preamble, today's rule would make substantial revisions to the monitoring plan, recordkeeping and reporting sections of Part 75, in support of EPA's data systems re-engineering effort. To make Subpart I consistent with these proposed revisions and with the other proposed changes in today's rule, a number of minor adjustments would also be made to the text of §§ 75.84(c)(3), (e)(1), (e)(2), and (f)(1).

H. Appendix A

1. CO

Span Values

EPA proposes to revise Section 2.1.3 of Appendix A, to allow the use of CO

spans less than 6.0 percent CO

if a technical justification is provided in the hardcopy monitoring plan. This added flexibility in the CO

span value mirrors a similar provision in Section 2.1.3 for O

span values.

2. Protocol Gas Audit Program

EPA is responsible for implementing air quality programs that rely on accurate calibration gases. Under these programs, calibration gases are used to calibrate EPA reference methods which, in turn, are used to perform stack tests or to calibrate installed pollutant continuous emissions monitoring systems (CEMs) that are used by regulated sources to report emissions to EPA. If the reference methods are low by 20%, then emissions may be underreported by 20%. Calibration gases are also used to ensure that ambient air quality analyzers provide accurate results. Accurate calibrations gases are critical in helping to ensure that the Clean Air Act-mandated emission reductions are achieved.

Section 2.1.10 of “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards” (Protocol Procedures), September 1997 (EPA-600/R-97/121) states that EPA will periodically assess the accuracy of calibration gases and publish the results. Between 1978 and 1996, EPA conducted several performance audits of calibration gases from various manufacturers. These audits had two goals, to provide a quality check for gas vendors and to connect users with gas vendors. One notable result in the most recent five consecutive years of audits is a steady, significant reduction in failure rate of the calibration gases, from about 27% in 1992 down to 5% in 1996. In 2003, EPA conducted a “surprise” audit of 14 national specialty gas producers and found that the failure rate had risen to 11%.

Today's proposed rule would require that EPA Protocol Gases being used for 40 CFR Part 75 purposes be obtained from those specialty gas producers who participate in the audit program. Under the proposed rule, only audit participants may market these gas standards as “EPA Protocol Gases”, although there will be no requirement for participants' audited standards to meet an accuracy acceptance criterion. The costs of the audits will be borne by the gas producers who elect to participate in the audits. Although it may take several years to revise all of the EPA monitoring regulations in 40 CFR Parts 58 and 60, today's proposed rule would ensure that under Part 75, any specialty gas producers who do not participate in the program will not have a price advantage (due to the lack of audit program costs) over those producers who do participate. An EPA-maintained web site will list the participants and the audit results, which will provide calibration gas users with detailed information about the quality of EPA Protocol Gases.

To clarify the calibration gas requirements in section 5.1 of appendix A to this part, a definition for “specialty gas producer” has been added to section 72.2. EPA believes that most of the gas standards and reference materials identified in section 5.1 of appendix A of this part are expensive and not used in practice by Part 75 affected units. Therefore, today's proposed rule also deletes several calibration gas options and definitions, and consolidates the remaining calibration gas descriptions under section 5.1 of appendix A to this part.

EPA is also requesting comment on the appropriate accuracy specification to apply to Hg cylinder gases and other Hg calibration standards (

e.g.

, gases from NIST-traceable generators). Currently, EPA requires that accuracy of EPA Protocol gases be within 2 percent of the certified tag values.

3. Requirements for Air Emission Testing Bodies

Since the inception of the Acid Rain Program, field audits of Part 75-affected facilities have brought to EPA's attention a number of improperly-performed RATAs and other QA/QC tests. When the proper test procedures are not followed, this can adversely affect the quality of the emissions data, and, in some cases, may call into question a unit's compliance with the requirement to hold allowances covering its emissions. In view of this, today's proposed rule would revise Section 6.1 of Appendix A to require all individuals who perform the emission tests and CEMS performance evaluations required by Part 75 to demonstrate conformance with ASTM D7036-04 “Standard Practice for Competence of Air Emission Testing Bodies”. ASTM D7036-04 specifies the general requirements for demonstrating

that an air emission testing body (AETB) is competent to perform emission tests of stationary sources. ASTM D7036-04 covers testing and calibration performed using standard methods, non-standard methods and methods developed by the AETB.

Proposed Section 6.1.2 of Appendix A and revisions to Section 2.1 of Appendix E and to Section 1 of Appendix B would make it clear that this requirement applies only to AETBs that perform RATAs, NO

emission tests of Appendix E and LME units, or Hg emission tests of low-emitting units. It would not be applicable to the daily operation, daily QA/QC (daily calibration error check, daily flow interference check, etc.), weekly QA/QC (

i.e.

, Hg system integrity checks), quarterly QA/QC (linearity checks, etc.), and routine maintenance of the CEMS.

ASTM D7036-04 would be incorporated by reference in § 75.6(a)(45), and a definition of “Air Emission Testing Body” would be added to § 72.2.

4. Linearity Requirements for Dual-Span Applications

Section 6.2 in Appendix A and Section 2.2 in Appendix B require the owner or operator of affected units with installed gas monitors to perform periodic linearity checks of the monitors. The basic linearity check requirements are to perform the test for initial certification and then, for ongoing quality assurance (QA), to repeat the test quarterly. In the original Part 75 regulations (published on January 11, 1993), there were no exceptions to these requirements.

However, in May 1999, EPA revised the linearity check provisions of Part 75 as follows. First, Section 6.2 of Appendix A was revised to exempt SO

and NO

span values of 30 ppm or less from performing linearity checks. Second, revisions to Section 2.2 of Appendix B reduced the ongoing linearity check requirement from once per calendar quarter to once every “QA operating quarter” (

i.e.

, a calendar quarter in which the unit operates for at least 168 hours).

Since the May 1999 revisions became effective, the regulated sources appear to have understood the “QA operating quarter” concept in Section 2.2 of Appendix B, but there has been some confusion about the meaning of the linearity exemption in Appendix A. Some have questioned whether the linearity exemption applies only to ongoing QA or whether it applies also to initial certification. Others have asked whether the exemption applies only to a particular measurement range or to all of the linearity check requirements for a monitoring system. The misunderstanding appears to center around two sentences in Section 6.2. The first sentence states that “Notwithstanding these requirements, if the SO

or NO

span value for a particular range is ≤ 30 ppm, that range is exempted from the linearity test requirements of this part.” Since the phrase “of this part” refers to Part 75, this seems to exempt ranges of 30 ppm or less from all Part 75 linearity requirements, including initial certification and ongoing QA. However, the second sentence states that “For units using emission controls and other units using both a high and a low span, perform a linearity check on both the low- and high-scales for initial certification.” Thus, for dual span applications, this statement appears to require linearity checks of both measurement scales for initial certification regardless of the span values, which does not harmonize with the 30 ppm exemption.

EPA believes that the key to understanding and reconciling these rule texts is the chronological order of the two sentences. The second sentence is from the original 1993 rule and the first sentence was added in 1999. Therefore, the 30 ppm linearity check exemption in the first sentence takes precedence over the low scale linearity check requirement of the second, and there is no actual contradiction. However, to eliminate any doubt as to the Agency's intended meaning, today's rule would revise Section 6.2 of Appendix A to make it clear that the 30 ppm linearity exemption: (1) Is range-specific; (2) covers both initial certification and ongoing QA; (3) does not remove the requirement to perform linearity checks of the high range (if > 30 ppm) for dual span applications; and (4) does not take away the linearity check requirements for the diluent monitor component of a NO

-diluent monitoring system.

5. Dual Span Applications—Data Validation

Today's proposed rule would revise Sections 2.1.1.5 (b)(2) and 2.1.2.5(b)(2) of Appendix A to clarify the relationship between the quality-assured (QA) status of the low and high ranges of a gas monitor in a dual-span application. The changes would be consistent with the proposed revisions to Appendix B (

see

Section II.I.3, below).

In the current rule, Sections 2.1.1.5(b)(2) and 2.1.2.5(b)(2) of Appendix A provide instructions for reporting SO

and NO

concentration data when the full-scale range of the monitor is exceeded. For single-range applications, a value of 200 percent of the maximum potential concentration (MPC) must be reported when a full-scale exceedance occurs. For dual range applications, if the low range is exceeded, no special reporting is necessary, provided that the high range is “available and not out-of-control or out-of-service for any reason”. However, if the high range is “not able to provide quality-assured data” during the low-range exceedance, then the MPC must be reported.

EPA believes that for dual range applications, the two phrases used to describe the QA status of the high range during low-scale exceedances,

i.e.

, “available and not out-of-control or out-of-service for any reason” and “not able to provide quality assured data”, are too general and do not adequately address the possible scenarios associated with dual range monitoring. Today's rule would revise these rule texts by defining the QA status of the high range in terms of its most recent calibration error and linearity checks. Provided that both of these QA tests are still “active”,

i.e.

, their windows of data validation have not expired, the high range would be considered in-control and able to provide quality-assured data. However if either of the tests has expired, data recorded on the high range would be considered invalid until the expired test was repeated and passed. The MPC would have to be reported until the expired high-range test is redone or until the data return to the low scale.

These revisions would clarify that when the low range is up-to-date on its QA tests but the high range is not, the QA statuses of the two ranges are evaluated separately and may be different. However, as explained in greater detail in Section II.I.3, below, the QA statuses of the low and high ranges are not necessarily independent when a calibration error test or a linearity check on one of the ranges is failed.

6. Cycle Time Test—Stability Criteria

The cycle time test described in Section 6.4 of Appendix A is required for the initial certification and recertification of gas monitoring systems, and occasionally as a diagnostic test. The “upscale” portion of the test consists of injecting a zero-level calibration gas, allowing the reading to stabilize, recording it, and then stopping the calibration gas flow, waiting until a stable reading of the source emissions is obtained, and recording it. The “downscale” portion of the test is performed in like manner, except that a

high-level calibration gas is used instead of the zero-level gas.

Section 6.4 currently specifies criteria for determining when a stable reading has been obtained. The reading is considered stable if it changes by less than 2.0 percent of the span value for 2 minutes or less than 6.0 percent from the average concentration over 6 minutes. These criteria are reasonable when the source effluent concentrations are moderate or high. However, when concentrations are very low, the criteria are quite stringent and can be very difficult to meet. For example, if the span value of a NO

analyzer is 10 ppm and the average measured source emissions are 3 ppm, the source emissions would have to remain constant within about 0.2 ppm for the specified amount of time to meet the stability criteria.

In recent years, hundreds of new combustion turbines (CTs) have been built. The vast majority are subject to Part 75, are equipped with NO

monitoring systems, and have NO

permit limits less than 10 ppm. Therefore, the 0.2 ppm cycle time stability criterion in the example above is realistic and applies to many of these new CTs. To provide a measure of relief for these low-emitting sources, today's rule would add alternative stability criteria to Section 6.4 of Appendix A. By the alternative criteria, an SO

or NO

reading would be considered stable if it changed by no more than 0.5 ppm for 2 minutes or, for a diluent monitor, if it changed by no more than 0.2% CO

or O

for 2 minutes. EPA believes these alternative stability criteria are needed to ensure that minor temporal variations in the concentration of the source effluent do not cause testers to overestimate the amount of time it takes to achieve stable readings, resulting in “false positive” failures of the cycle time test.

7. System Integrity and Linearity Checks of Hg CEMS

Subpart I of Part 75 includes certification test procedures and performance specifications for Hg CEMS. The required certification tests for a Hg CEMS include a 3-level system integrity check, using a NIST-traceable source of oxidized Hg and a 3-level linearity check, using elemental Hg standards. The performance specification for the system integrity check, which is found in paragraph (3)(iii) of Appendix A, Section 3.2, states that the system measurement error must not exceed 5.0 percent of the span value at any of the three calibration gas levels. However no explanation of how to calculate the measurement error is provided. Today's proposed rule would restructure paragraph (3) of Section 3.2 (as described in the next paragraph) and add the necessary mathematical procedure.

EPA is also proposing to make the linearity and system integrity check specifications for Hg monitors the same. The principal linearity error specification in Section 3.2(3)(i) is currently 10.0 percent of the reference gas tag value at each calibration concentration, when calculated according to Equation A-4. The alternative specification in Section 3.2(3)(ii) allows an absolute difference of up to 1.0 μg/m

between the average reference gas and monitor values at each calibration gas level. Today's proposed rule would replace the principal linearity error specification with a specification of 5.0 percent of the span value, and would lower the alternative specification to 0.6 μg/m

. Further, the same 0.6 μg/m

alternative specification would be added to the rule for the system integrity check.

The reason for making these changes is that nearly all Hg monitors are equipped with a converter and measure the total vapor phase Hg (

i.e.

, oxidized plus elemental) as elemental Hg. Therefore, the performance specification for the linearity check, which is done with elemental Hg, should be at least as stringent as the performance for the system integrity check, which is done with oxidized Hg. Because the current linearity specifications are less stringent than the specification for the system integrity check, EPA proposes to revise and restructure paragraph (3) in Section 3.2 of Appendix A, to make the performance specifications the same for linearity checks and system integrity checks of Part 75 Hg monitors (this includes both the 3-level and single-level system integrity checks). The alternative performance specification is deemed necessary for low (10 μg/m

Hg span values, where the principal specification of 5.0% of span may be overly stringent.

8. Correction of Hg Calibration Gas Concentrations for Moisture

When calibration error tests and linearity checks of SO

, NO

, and diluent gas monitors are performed, EPA protocol gases are used. The protocol gases are essentially moisture-free. However, when mercury monitors are calibrated, moisture may be added to the calibration gas. This creates a potential source of error in the calculations, if the Hg monitoring system measures on a dry basis. In view of this, EPA proposes to revise the calibration error procedures in section 6.3.1 of Appendix A, to require that when moisture is added to the Hg calibration gas, the moisture content of the gas must be accounted for if the Hg monitor measures on a dry basis. The proposed revisions would also require the calibration gas concentration to be converted to a dry basis for purposes of the calibration error calculations.

Parallel language would be added to Section 6.2 of Appendix A, in a new paragraph “(h)”, to address this issue for the linearity checks and system integrity checks of Hg monitors. The Agency believes that adoption of these proposed revisions will prevent many “false positive” failures of Hg monitor calibration error tests, linearity checks, and system integrity checks.

9. Correction of Cross-References

Today's proposed rule would correct a number of cross-references in Appendix A, Sections 6.2(g), 6.5.6(b)(3) and 6.5.6.3. Regarding the system integrity checks of Hg monitors, Section 6.2(g) of Appendix A incorrectly only refers to Section 2.6 of Appendix B, which only describes weekly, single-level system integrity checks. The proposed revisions would also refer to Sections 2.1.1 and 2.2.1 of Appendix B, which describe the 3-level system integrity checks. Also, the references in Sections 6.5.6(b)(3) and 6.5.6.3 of Appendix A to Section 3.2 of 40 CFR Part 60, Appendix B, Performance Specification No. 2 (PS2) are incorrect. The correct section number in PS2 is 8.1.3, not 3.2.

I. Appendix B

1. 3-Load Flow RATA Frequency and RATA Grace Period

On May 26, 1999, EPA revised Appendix B of Part 75, to reduce the required frequency of 3-load flow RATAs from annually to “at least once every 5 consecutive calendar years”. However, as written, the rule actually allows more than five years (20 calendar quarters) to elapse between 3-load flow RATAs. For instance, if a 3-load flow RATA was performed in the1st quarter of 2001 and the next one is done in the 4th quarter of 2006, the rule requirement would be met, but there would be 23 calendar quarters between the successive tests.

In light of this, EPA is proposing to revise Section 2.3.1.3(c)(4) of Appendix B, to require 3-load flow RATAs to be done at least once every 20 calendar quarters. This is consistent with the other 5-year testing requirements in Part 75,

i.e.

, for Appendix E and LME units. It is also consistent with the maximum

allowable interval between successive accuracy tests of Appendix D fuel flowmeters.

EPA is also proposing to revise the RATA grace period provisions in Section 2.3.3. In recent years many new combustion turbines have been built and most of them have NO

-diluent CEMS. A great number of these turbines have been operated infrequently due to the high price of natural gas. Because of this, a unit may go for a very long period of time without performing a RATA of the NO

monitoring system because the unit seldom, if ever, has a “QA operating quarter” (so the extended deadline for the next RATA is often 8 calendar quarters from the previous test), and then it may be several quarters or even years before the allowable 720 operating hour grace period expires.

The grace period provisions in Section 2.3.3 were proposed in 1998 and promulgated in May 1999, before the influx of new, infrequently-operated combustion turbines. Consequently, these rule provisions are often very difficult to track and apply to such units. Therefore, EPA proposes to modify the grace period methodology so that it is more understandable and user-friendly, particularly in cases where a unit seldom operates.

Today's proposal would move the requirements for determining the deadline for the next RATA after a grace period test from paragraph (c) of Section 2.3.3 to a new paragraph (d). Paragraph (c) currently addresses both RATA deadlines and the data validation requirements for the case where a RATA is not completed by the end of the 720 operating hour grace period. Creating a new paragraph (d) would make Section 2.3.3 clearer, by treating the RATA deadline requirement as a distinct and separate issue.

Proposed paragraph (d) would change the methodology for determining RATA deadlines without changing the end result. The intent of Section 2.3.3 has always been for the source to return to its original RATA schedule following a grace period test, in order to prevent the grace period provisions from being abused. For instance, if the source did not return to its original RATA schedule, the grace period could be used to extend the interval between successive annual RATAs from four QA operating quarters to five.

The current language in Section 2.3.3 works well enough for base load units that operate most of the time. For these units, the grace period almost invariably begins and ends within one calendar quarter of the RATA deadline, making it easy to return to the original RATA schedule. For instance, suppose that a base load unit is on a 2nd quarter RATA schedule and a grace period RATA is done in the 3rd quarter. If annual frequency is obtained, the deadline for the next RATA is reckoned from the 2nd quarter, when the RATA was due, rather than the 3rd quarter when the grace period test was actually done. Therefore, the next RATA would be required in the 2nd quarter of the following year,

i.e.,

“back on schedule”. However, for infrequently operated combustion turbines, the grace period sometimes spans across many calendar quarters, which effectively eliminates the possibility of establishing a meaningful relationship between the original RATA due date and the deadline for the next test.

In view of these considerations, EPA is proposing a simplified methodology for determining RATA deadlines that will work for both base load units and combustion turbines that seldom operate. The deadline for the next RATA following a grace period test would be expressed as a certain number of QA operating quarters after the quarter of the grace period RATA, rather than referring back to the quarter in which the RATA was originally due (which could have been several quarters in the past).

The deadline for the next RATA would be determined by first establishing whether the grace period RATA qualifies for the standard (semiannual) RATA frequency or the reduced (annual) frequency. If the grace period RATA does not qualify for the annual frequency, the deadline for the next RATA would be simply set at two QA operating quarters after the quarter of the grace period test. If the RATA qualifies for the annual frequency then the deadline for the next RATA would be set at three QA operating quarters after the quarter of the grace period test. There would be one exception to these rules. Regardless of the number of QA operating quarters that have elapsed following the grace period test, the interval between a grace period RATA and the deadline for the next required RATA could be no greater than eight calendar quarters. This provision is consistent with Section 2.3.1.1(a) of Appendix B.

Finally, EPA is proposing to amend paragraph (c) of Section 2.3.3, to clarify that when a RATA is performed after the expiration of a grace period, the “clock” is reset, and the next RATA would simply be due in two QA operating quarters (for semiannual frequency) or four QA operating quarters (for annual frequency), not to exceed eight calendar quarters.

EPA believes that the proposed revisions to Section 2.3.3 of Appendix B would greatly simplify implementation of the grace period provisions and would enhance the Agency's ability to track RATA deadlines and to provide meaningful feedback to the affected sources.

2. RATA Requirement for Shared Components

Today's proposed rule would amend paragraph (g) in section 2.3.2 of Appendix B to specify the consequences of a failed RATA, in the case where a particular NO

pollutant concentration monitor is a component of both a NO

concentration monitoring system and a NO

-diluent monitoring system. An example would be a coal-fired source that is subject to both the Acid Rain and NO

Budget Programs, for which the owner or operator elects to use a NO

concentration system to quantify NO

mass emissions, while using the NO

-diluent system to satisfy the Acid Rain Program requirement to monitor and report NO

emission rate in lb/mmBtu. In such cases, if the NO

concentration system RATA is failed, both the NO

concentration monitoring system and the associated NO

-diluent monitoring system would be considered out-of-control. Successful RATAs of both monitoring systems would be required to get them back in-control.

3. AETB Requirements

Appendix B would be further revised by adding a new Section, 1.1.4, to require that an Air Emissions Testing Body (AETB) that performs emission testing or RATAs for on-going quality-assurance under Part 75 must conform to ASTM D7036-04.

4. Calibration Error Tests and Linearity Checks—Dual Range Applications

Today's rule would revise Sections 2.1.1, 2.1.1.2, 2.1.5.1 and 2.2.3(e) of Appendix B, to clarify the data validation requirements for daily calibration error tests and linearity checks of gas monitors when two span values and two measurement ranges are required for a particular parameter (

e.g.

, SO

or NO

Section 2.1.1 of Appendix B would be revised to require that sufficient calibration error tests be performed on the low and high monitor ranges to validate the data recorded on each range. The provisions of Section 2.1.5 of Appendix B would be used to determine whether “sufficient” calibration error tests have been done. A new paragraph (3) would also be added to Section 2.1.5.1 of Appendix B to clarify how the QA status of the low and high ranges is

determined when: (a) A calibration error test on one of the ranges is failed; or (b) the most recent calibration error test of one of the ranges has expired. In the case where separate analyzers are used for the two ranges, a failed or expired calibration error test on one of the ranges would not affect the QA status of the other range. For a dual-range analyzer (

i.e.

, a single analyzer with two scales), a failed calibration error test on either range would result in an out-of-control period, and data from the monitor would remain invalid until corrective actions are taken, followed by successful “hands-off” calibrations of both ranges. However, if the most recent calibration error test on one range of a dual-range analyzer was successful, but its data validation window has expired, this would have no effect on the QA status of the other range.

In the current rule, Section 2.2.3(e) in Appendix B states that when linearity checks are performed on both scales of a dual-range analyzer, an out-of-control period occurs if either of the two linearity checks is failed or aborted due to a problem with the monitor. However, it is not clear whether only one range or both ranges must be retested to get back in-control. Today's rule would revise Section 2.2.3(e) to require “hands-off” linearity checks of both ranges of a dual-range analyzer whenever a linearity check on either range is failed or aborted (unless, of course, a particular range is exempted from linearity checks under Section 6.2 of Appendix A).

5. Off-Line Calibration Error Tests

Part 75 requires calibration error tests of all CEMS to be done while the unit is combusting fuel (

see

Appendix B, Section 2.1.1 and Appendix A, Sections 6.3.1 and 6.3.2). However, Section 2.1.1.2 of Appendix B allows the owner or operator to make limited use of off-line calibration error tests to validate data if an off-line calibration demonstration test is performed and passed. If the off-line calibration error demonstration is successful, then off-line calibrations may be used to validate up to 26 unit operating hours of data before an on-line calibration error test is required.

The off-line calibration provisions in Appendix B have not been well-understood by many affected sources. Through the years, EPA has received numerous requests for a more detailed explanation and/or examples of how to apply these rule provisions. Today's rule would revise Sections 2.1.1.2 and 2.1.5.1 of Appendix B to clarify the data validation rules for off-line calibration error tests.

The Agency believes that main reason why there have been so many questions about the use of off-line calibration error tests is that paragraph (2) of Section 2.1.1.2 is not clear. Paragraph (2) states that “a successful on-line calibration error test of the monitoring system must be completed no later than 26 unit operating hours after each off-line calibration error test used for data validation.” This statement can be easily misinterpreted. It could be understood to mean that a single off-line calibration error test can be used to validate 26 unit operating hours of data, regardless of the number of clock hours it takes to accumulate the 26 unit operating hours. However, this is not the intended meaning because it would directly contradict the statement, in Section 2.1.5 of Appendix B, that the window of data validation from a passed calibration error test extends for only 26 clock hours.

To clarify EPA's intent regarding the use of off-line calibration error tests to validate CEM data, today's rule would revise Sections 2.1.1.2 and 2.1.5.1 of Appendix B. First, paragraph (2) in Section 2.1.1.2 would be revised to state that sources may make limited use of off-line calibrations if the off-line calibration demonstration has been performed and passed. Revised paragraph (2) of Section 2.1.5.1 would explain what “limited use” of off-line calibrations means. Off-line calibrations could be used to validate up to 26 consecutive unit operating hours of data before an on-line test is required. Each individual off-line calibration would be valid only for 26 clock hours, and if the sequence of consecutive operating hours validated by off-line calibrations is broken before reaching the 26th consecutive unit operating hour, data from the monitor would become invalid until an on-line calibration is performed and passed. The sequence of consecutive valid hours would be considered broken whenever a unit operating hour is not contained within the 26 clock hour data validation window of a passed off-line calibration error test.

6. Weekly System Integrity Check—Data Validation

For a Hg CEMS that is equipped with a converter and that uses elemental Hg for daily calibrations, Section 2.6 of Part 75, Appendix B requires a weekly system integrity check, using a NIST-traceable source of oxidized Hg. This “weekly” test is required once every 168 unit operating hours. However, Section 2.6 does not explain the consequences of either failing the test or failing to perform the test on schedule. Today's rule would add data validation rules for the weekly system integrity check to Section 2.6 of Appendix B. If the test is failed, it would trigger an out-of-control period until a subsequent system integrity check is passed. Also, if the test is not performed within 168 unit operating hours of the previous successful system integrity check, data from the CEMS would become invalid, starting with the 169th unit operating hour and continuing until a system integrity check is passed.

Today's rule would also correct a typographical error in Section 2.6 of Appendix B. The performance specification for the weekly system integrity check is incorrectly referenced in the current rule as Section 3.2 (c)(3) of Appendix A. The correct citation is Appendix A, Section 3.2, paragraph (3)(iii).

7. Correction of Hg Units of Measure—Figure 2

Today's rule would correct a minor error in the units of measure for Hg concentration in Figure 2 of Appendix B. The units of micrograms per dry standard cubic meter (μg/dscm) would be changed to micrograms per standard cubic meter (μg/scm). This change is necessary because not all Hg monitoring systems measure Hg concentration on a dry basis.

J. Appendix D

1. Update of Incorporation by Reference

As discussed in Section II.B.1of this preamble, EPA proposes to update the list of test methods, sampling and analysis procedures, and other items that are incorporated by reference in Part 75. As such, this proposal also includes the necessary updates to the references in Appendix D.

EPA is also proposing to add to Section 2.1.5.1 of Appendix D, the American Petroleum Institute's (API) Manual of Petroleum Measurement Standards Chapter 22—Testing Protocol: Section 2—Differential Pressure Flow Measurement Devices (First Edition, August 2005) as a new standard procedure for verifying flowmeter accuracy.

2. Pipeline Natural Gas—Method of Qualification and Monthly GCV Values

For a unit which combusts a fuel that meets the definition of “pipeline natural gas” (PNG) in § 72.2, Section 2.3.1.1 of Appendix D allows the owner or operator to estimate the unit's SO

mass emissions using a default SO

emission rate of 0.0006 lb/mmBtu. To qualify to use this SO

emission rate, the owner or operator must document in the

monitoring plan for the unit that the natural gas has a total sulfur content of 0.5 grains per 100 standard cubic foot or less. Section 2.3.1.4 describes three ways to initially demonstrate that the gas meets this total sulfur requirement: (1) Based on the gas quality characteristics specified in a purchase contract, tariff sheet, or pipeline transportation contract; or (2) based on historical fuel sampling data from the previous 12 months; or (3) based on at least one representative sample of the gas, if the requirements of (1) or (2) cannot be met. When fuel sampling data are used to qualify, each individual sample result must meet the total sulfur limit. Once a fuel has qualified as pipeline natural gas, Section 2.3.1.4(e) of Appendix D requires annual sampling of the total sulfur content to demonstrate that the fuel still meets the definition of PNG. At least one sample per year must be taken and if multiple samples are taken, each one must meet the 0.5 gr/100 scf total sulfur limit.

The criteria for documenting the total sulfur content of PNG were promulgated on June 12, 2002, and the annual total sulfur requirement became effective on January 1, 2003. Since then, EPA has learned that many suppliers of natural gas regularly sample the total sulfur content of the gas (in many cases, daily) and will provide that data to their customers upon request. Sources desiring to use this data to meet the initial or ongoing total sulfur sampling requirements of Appendix D have approached EPA, asking whether the gas would be disqualified from using the 0.0006 lb/mmBtu SO

emission rate if the total sulfur content of one of these daily samples exceeded 0.5 gr/100 scf. Thus far, the Agency has addressed these requests on a case-by-case basis. Generally, in cases where the number of total sulfur samples far exceeds the requirements of Appendix D, EPA has allowed the sources to reduce the data to monthly averages. Then, if all of the monthly averages are below the 0.5 gr/100 scf , the fuel would be allowed to continue using the 0.0006 lb/mmBtu default SO

emission rate.

EPA believes that the current rule requirements for documenting the sulfur content of pipeline natural gas are too restrictive and need to be revised. For example, a source that takes only one or perhaps a handful of sulfur samples each year is allowed to use the 0.0006 lb/mmBtu default emission rate without question if all samples have ≤ 0.5 gr/100 scf of total sulfur. However, a source with hundreds of total sulfur sample results could possibly be disqualified from using the default emission rate if one sample exceeded the 0.5 gr/100 scf limit. To correct this inequitable situation, today's rule would revise Sections 2.3.1.4(a)(2) and (e) of Appendix D.

For the initial documentation that the gas meets the 0.5 gr/100 scf total sulfur limit, proposed Section 2.3.1.4(a)(2) would allow sources whose fuel suppliers have provided them with at least 100 daily (or more frequent) total sulfur samples from the previous 12 months to reduce the data to monthly averages. If all monthly averages meet the 0.5 gr/100 scf limit, the fuel would qualify as pipeline natural gas, and the source could use the 0.0006 lb/mmBtu default SO

emission rate. Alternatively, if at least 98 percent of the 100 (or more) samples have a total sulfur content of 0.5 gr/100 scf or less, the fuel would qualify as pipeline natural gas.

The revisions to Section 2.3.1.4(e) would allow this same calculation methodology to be used for the annual total sulfur sampling requirement. That is, each year, if at least 100 total sulfur samples from the past 12 months are provided by the fuel supplier, the data could either be reduced to monthly averages, or the percentage of the samples that meet the 0.5 gr/100 scf limit could be determined.

EPA is also proposing to clarify the GCV sampling requirements for pipeline natural gas in Section 2.3.4.1 of Appendix D. The current rule requires monthly GCV sampling for PNG. However, Section 2.3.4.1 refers only to the “monthly sample” (singular), whereas affected sources may collect and analyze multiple GCV samples each month, or may receive the results of multiple GCV samples from the fuel supplier each month. In view of this, revised Section 2.3.4.1 would require that a monthly average GCV value be used for Part 75 reporting, for any month in which multiple samples are taken and analyzed. To implement this provision, whenever Section 2.3.7(c) of Appendix D requires the results of a monthly GCV sample to be applied “starting from the date on which the sample was taken”, the owner or operator would apply the monthly average GCV value, starting from the latest date of any of the individual GCV samples used to calculate the monthly average. EPA believes that monthly averaging of the available GCV samples will ensure that representative robust GCV values are used in the Appendix D heat input calculations.

3. Requirement To Split Oil Samples

For affected units that combust fuel oil and use the Appendix D “excepted” methodology to quantify SO

mass emissions and/or unit heat input, Section 2.2 of Appendix D requires the owner or operator to perform periodic sampling of the sulfur content, gross calorific value and (if necessary) density of the oil. There are four basic oil sampling options described in Section 2.2: (a) Daily sampling; (b) flow proportional sampling (composite sample, up to 7 days); (c) sampling from a unit's storage tank after each addition of oil to the tank; and (d) sampling of each fuel lot (either upon receipt of the lot or sampling from supplier's storage tank prior to delivery). Regardless of which sampling option is selected, Section 2.2.5 of Appendix D requires each oil sample to be split and a portion (at least 200 cc) of it to be maintained for at least 90 days after the end of the allowance accounting period.

The requirement to split and maintain a portion of each oil sample has been in Appendix D since it was first promulgated on January 11, 1993. At that time, on-site fuel oil sampling was required on every day that the unit combusted oil. Later, on May 17, 1995, an option to sample each shipment upon delivery was added for diesel fuel. Then, on May 26, 1999, the four basic oil sampling options in the current rule were put in place. However, the requirement to split and maintain a portion of each sample has remained unchanged through all of these rulemakings.

EPA believes that the requirement to split and maintain oil samples should only apply to samples that are taken at the affected facility. Today's rule would revise Section 2.2.5 of Appendix D to limit this requirement to samples that are taken on-site. Therefore, sources using the fourth sampling option in Section 2.2 of Appendix D,

i.e.

, sampling from each fuel lot, would no longer be required to split and maintain oil samples in the case where the samples are taken off-site, from the fuel supplier's storage container.

K. Appendix E

1. AETB Requirements

EPA proposes to revise Section 2.1 of Appendix E to require that any Air Emissions Testing Body (AETB) performing emission measurements to develop an Appendix E correlation curve or to derive a default emission rate for an LME unit, would have to conform to ASTM D7036-04.

2. Reporting Data When the Correlation Curve Expires

For oil and gas-fired peaking units using the Appendix E “excepted” methodology to estimate NO

emissions, the owner or operator is

required, for each fuel type, to perform four-load emission testing for initial certification in order to develop a correlation curve of NO

emission rate versus heat input rate. Each correlation curve is programmed into the data acquisition and handling system (DAHS), and retesting is required every five years (20 calendar quarters) to develop a new curve.

If the 20 calendar quarter test deadline passes without a retest having been performed, the previous correlation curve expires and is no longer valid. Ordinarily, when data from a Part 75 monitoring system become invalid, missing data substitution procedures are applied. Section 2.5 of Appendix E contains missing data provisions that address the following situations: (a) When the monitored QA parameters are unavailable or invalid; (b) when the measured heat input rate is higher than the highest heat input rate on the correlation curve; (c) when NO

emission controls are either not operating or not documented to be working properly; and (d) when emergency fuel is burned.

Conspicuously absent from Section 2.5 is a missing data procedure to follow when a correlation curve expires. To address this deficiency, today's rule would add a new Section, 2.5.2.4, to Appendix E, requiring the fuel-specific maximum potential NO

emission rate (MER) to be reported when a baseline correlation curve expires. The MER would continue to be reported until a new correlation curve is generated.

L. Appendix F

1. NO

Mass Calculations

EPA proposes to revise the manner in which NO

mass data are collected under the XML-EDR format that will be required in 2009 as part of EPA's effort to re-engineer the Agency's data collection systems. Under the current reporting requirements, sources are required to report hourly NO

mass emissions (lb) and then to sum these hourly records and divide by 2000 lb/ton to determine the quarterly NO

mass emissions (tons). This is inconsistent with the manner in which SO

and CO

mass emissions data are reported and aggregated. For SO

and CO

, the hourly values are reported as mass emission rates (lb/hr). The quarterly cumulative mass emissions are calculated by multiplying each reported hourly mass emission rate by the corresponding unit or stack operating time, summing these products, and then dividing the sum by 2000 lb/ton to get tons of SO

or CO

Today's proposed rule seeks to harmonize the reporting formats by requiring the reporting of hourly NO

mass emission rate (lb/hr) instead of hourly NO

mass emission (lb), when the source transition from the current EDR reporting format to the XML-EDR reporting format. As previously discussed, sources may use either the existing EDR format or the new XML-EDR reporting format in 2008, but will be required to use the new XML-reporting format, only, in 2009.

Requiring the reporting of hourly NO

mass emission rate (lb/hr) necessitates the modification of Equations F-24, and F-27 in Appendix F of Part 75 and the removal of Equation F-26. However, since the current EDR reporting format will continue to be supported through 2008, EPA must retain these equations in the rule until the transition to XML-EDR is complete. Therefore, EPA is proposing to revise Section 8 of Appendix F, by adding Equation F-24a for the reporting of hourly NO

mass emission rate (lb/hr). Equation F-24a is a modified version of F-24, in which the operating time variable is removed. The use of Equation F-24a would be mandatory in the new XML-EDR format. Likewise, Equation F-27a would be added, which is a modified form of Equation F-27 that includes the operating time variable. In the XML-EDR format, cumulative NO

mass emissions would be calculated using Equation F-27a.

Since both EDR reporting formats currently in use (

i.e.

, EDR versions 2.1 and 2.2) require reporting of hourly NO

mass emissions (lb), the current versions of Equations F-24 and F-27 would remain in the rule. However, these equations would no longer be applicable in 2009, when the use of XML-EDR format is required for all affected sources.

Today's proposal also would revise Section 8.2 of Appendix F, by splitting it into two subsections, 8.2.1 and 8.2.2. Section 8.2 of the current rule describes a procedure for calculating the NO

mass emission rate in lb/hr, when NO

mass emissions are determined using a NO

concentration monitoring system and a flow monitor. Section 8.2 cross-references other parts of the rule, rather than showing the actual equations used. Today's proposed rule would add Equation F-26a to proposed subsection 8.2.1 and Equation F-26b to proposed subsection 8.2.2, clearly showing how the NO

mass emission rate is calculated on a wet and dry basis. Equation F-26 in Section 8.3 would be re-numbered as Equation F-26c. Proposed Equations F-26a and F-26b are currently used by sources to calculate NO

mass emissions under Subpart H of Part 75. These equations are represented in the EDR reporting instructions, as Equations N-1 and N-2 respectively. EPA believes that it is appropriate to add these equations to the rule at this time.

2. Use of the Diluent Cap

Today's proposed rule would restrict the use of the diluent cap to NO

emission rate calculations. The original purpose for implementing the diluent cap was to keep calculated NO

emission rates from approaching infinity during periods of unit startup and shutdown, where the diluent gas (CO

or O

) concentration is close to the level in the ambient air. However, the current rule allows the diluent cap to be used for heat input rate calculations, CO

mass emission calculations, and calculation of hourly CO

concentration from measured O

concentrations, in addition to being used for NO

emission rate. Sources are also allowed to use the cap value for some of these calculations and not others. This greatly complicates the data collection process. EPA has also found that using the diluent cap for other parameters besides NO

emission rate always leads to over-reporting of these parameters, which is clearly contrary to the intended purpose of the diluent cap. Therefore, today's proposed rule would remove all of the references in Sections 4 and 5 of Appendix F which allow the diluent cap to be used for other parameters besides NO

emission rate

3. Negative Emission Values

EPA proposes to provide special reporting instructions to account for situations where the equations prescribed by the rule yield negative values. First, when Equation 19-3 or 19-5 (from EPA Method 19 in 40 CFR Part 60, Appendix A) is used to calculate NO

emission rate, modified forms of these equations, designated as Equations 19-3D and 19-5D, would be used whenever the diluent cap is applied. Second, for any hour where Equation F-14b results in a negative hourly average CO

value, EPA proposes to require 0.0% CO

to be reported as the average CO

value for that hour. Third, EPA proposes to require a default heat input rate value of 1 mmBtu/hr to be reported for any hour in which Equation F-17 results in a negative hourly heat input rate. These changes would be accomplished by modifying Sections, 3.3.4, 4.4.1, and 5.2.3 of Appendix F.

4. Calculation of Stack Gas Moisture Content

Today's proposed rule would add Equation F-31 to a new Section 10 of Appendix F. This equation is used to calculate stack gas moisture values from wet and dry oxygen measurements, as described in Appendix A, Section 6.5.7(a). The equation is currently represented in the EDR reporting instructions as Equation M-1.

5. Site-Specific F-Factors (Single Fuel)

For units that use CEMS to measure the NO

emission rate in lb/mmBtu and/or the unit heat input rate in mmBtu/hr, an equation from Appendix F of Part 75 or from Method 19 of 40 CFR Part 60 is required to convert the raw CEMS data into the proper units of measure. Each of these equations contains an F-factor, which represents either the total volume of flue gas or the volume of CO

generated per million Btu of heat input. The F-factor is fuel-specific.

Sections 3.3.5 and 3.3.6 of Appendix F allow the owner or operator to use either a default F-factor from Table 1 in Appendix F, or use Equation F-7a or F-7b in Appendix F to calculate a site-specific F-factor, based on the composition of the fuel. However, Appendix F neither specifies how much fuel sampling data is required to develop a site-specific F-factor, nor how often the F-factor must be updated.

To address this issue, today's rule would revise the introductory text of Appendix F, Section 3.3.6 to require each site-specific F-factor to be based on a minimum of 9 samples of the fuel. Fuel samples taken during the 9 runs of an annual RATA would be acceptable for this purpose. Further, re-determination of the F-factor would be required at least annually, and the value from the most recent determination would be used in the emission calculations.

6. Prorated F-Factors

For affected units that co-fire combinations of fossil fuels or fossil fuels and wood residue and that use CEMS to monitor the NO

emission rate or unit heat input rate, Section 3.3.6.4 of Appendix F requires a prorated F-factor to be used in the emission calculations. The prorated F-factor is calculated using Equation F-8 in Appendix F. In applying Equation F-8, the F-factor for each type of fuel is weighted according to the fraction of the total heat input contributed by the fuel. However, Equation F-8 fails to specify how the total unit heat input and the fraction of the heat input contributed by each fuel are determined. Data from the CEMS cannot be used for this purpose because the prorated F-factor must be known before the unit heat input rate can be calculated.

Through the years, in response to inquiries about this, EPA has advised sources to use the best available auxiliary process data, such as fuel feed rates and measured GCV values, to provide heat input estimates for calculating the prorated F-factor, but no official Agency policy guidance has been issued. To correct this situation, today's rule would revise the definition of “X

” (the fraction of the total heat input derived from each fuel) in the Equation F-8 nomenclature. The revised definition would require sources to determine X

from the best available information on the quantity of each fuel combusted and its GCV value over a specified time period. The value of X

would be updated periodically, either hourly, daily, weekly, or monthly, and the prorated F-factor used in the emission calculations would be derived from the X

values from the most recent update. The owner or operator would be required to document in the hard copy portion of the monitoring plan the method used to determine the X

values.

7. Default F-Factors

EPA proposes to add default F-factors for petroleum coke and tire derived fuels to Table 1 in Section 3.3.5 of Appendix F. The proposed values are 9,832 dscf/mmBtu for F

and 1,853 scf CO

/mmBtu for F

for petroleum coke and 10,261 dscf/mmBtu for F

and 1,803 scf CO

/mmBtu for F

for tire derived fuels. These F-factors are needed because petroleum coke and tires are being used as a fuel by a number of units. EPA is also proposing 9,819 dscf/mmBtu for F

and 1,840 scf CO

/mmBtu for F

as F-factors for sub-bituminous coal. These F-factors were calculated using Part 75, Appendix F, Equations F-7a and F-7b and representative composition and gross calorific value (GCV) data for each fuel.

8. Revisions to Equation F-23

Consistent with the proposed changes to § 75.11(e), expanding the applicability of Equation F-23 (which are discussed in detail in Section II.B.4 of this preamble), modifications would be made to Section 7 of Appendix F (introductory text), and to the Equation F-23 nomenclature.

M. Appendix G

Consistent with the changes to other parts of the rule, EPA proposes to update the current ASTM standards listed in Sections 2.1.2, 2.2.1, and 2.2.2, of Appendix G, citing the newer versions.

N. Appendix K

Today's proposed rule addresses several issues regarding the use of sorbent trap monitoring systems for the measurement and reporting of Hg mass emissions. When this monitoring option is selected, the current rule requires the use of paired sorbent traps to measure the effluent Hg concentration. If the two Hg concentrations measured by the paired traps meet the required relative deviation (RD) specification in Appendix K of Part 75, and if each trap individually meets certain other QA requirements of Appendix K, then the two Hg concentrations are averaged arithmetically and the average value is used to determine the Hg mass emissions in each hour of the data collection period. However, in cases where either or both of the traps fails to meet the acceptance criteria, § 75.15(h) and Table K-1 of Appendix K specify consequences of varying severity. As discussed in the following paragraphs, EPA has reconsidered these rule provisions and has concluded that some of the consequences are too lenient while others are unnecessarily harsh. The Agency is therefore proposing to revise them to make them more consistent and equitable.

Section 75.15(h) currently provides a measure of relief to the affected sources whenever one of the paired traps is accidentally lost, damaged, or broken and cannot be analyzed. In such cases, the owner or operator is allowed to use the remaining trap to determine the Hg concentration for the data collection period, provided that the remaining trap meets all of the QA requirements of Appendix K. But the rule does not require any adjustment of the data to compensate for the loss of one of the samples. In view of this, EPA is proposing to revise § 75.15(h) to require that the Hg concentration measured by the remaining valid trap be multiplied by a “single trap adjustment factor” (STAF) of 1.222. The STAF represents the maximum amount by which the Hg concentration from the lost, damaged or broken trap could have exceeded the concentration measured by the valid trap and still met the 10% RD specification.

The Agency is also proposing to revise Table K-1 in Appendix K, to extend the use of the STAF to cases where one of the paired sorbent traps either: (a) Fails a post-test leak check; (b) has excessive breakthrough in the second section; or (c) is unable to meet the required percent recovery of the third section elemental Hg spike. In all

three of these cases, provided that the other trap meets all Appendix K requirements, rather than invalidating the sorbent trap system data for the entire collection period, the Hg concentration measured by the valid trap, multiplied by the STAF, could be used for Part 75 reporting.

Section 7.2.3 of Appendix K requires that for each hour of the data collection period, the ratio of the stack gas flow rate to the sample flow rate through each sorbent trap must be maintained within 25 percent of the initial ratio established in the first hour of the data collection period. However, the current rule does not say what to do if this criterion is not met. Rather, Table K-1 indicates that the appropriate consequences are to be determined on a “case-by-case” basis. EPA has reconsidered this approach and is proposing to revise it, because it opens the door to inconsistent application of the sorbent trap monitoring methodology. Therefore, Table K-1 would be revised to specify that a sample is invalidated if either: (a) More than 5 percent of the hourly ratios; or (b) more than 5 hourly ratios in the data collection period (whichever is less restrictive) fail to meet the ±25 percent acceptance criterion. Further, if only one of the paired traps is able to meet the specification, provided that it also meets the rest of the Appendix K QA criteria, the valid trap could be used for Part 75 reporting, if the single trap adjustment factor of 1.222 is applied to the measured Hg concentration.

Appendix K currently requires that the data from a sorbent trap monitoring system be invalidated whenever the relative deviation between the Hg concentrations measured by the paired traps is greater than 10 percent. EPA proposes to revise this requirement, to allow sources to report the higher of the two Hg concentrations measured by a pair of sorbent traps whenever the RD specification is not met, rather than invalidating the sorbent trap system data for the entire collection period. EPA is also proposing, for consistency with the proposed changes § 75.22(a) (which are discussed in Section II.C.3 of this preamble), to revise Table K-1 to include an alternative relative deviation specification of 20 percent for paired sorbent traps, where low effluent concentrations of Hg (≤ 1 μg/m

) are encountered.

Today's proposed rule would add two new paragraphs, (k) and (l), to § 75.15. Proposed § 75.15(k) would require that whenever the RATA of a sorbent trap system is performed, the sorbent traps used to collect the RATA run data must be the same size as the traps used for daily operation of the monitoring system. Likewise, the sorbent material must be the same type that is used for daily operation. Proposed § 75.15(l) would require a diagnostic RATA of the sorbent trap system whenever the size of the sorbent traps or the type of sorbent material is changed. Data from the modified sorbent trap system would not be acceptable for Part 75 reporting until the RATA is passed, with one exception,

i.e.

, data collected during a successful diagnostic RATA test period could be reported as quality-assured. EPA is proposing to add these requirements because the relative accuracy and bias of a sorbent trap monitoring system are dependent upon both the trap design and the type of sorbent material used.

Finally, today's proposed rule would revise section 7.2.3 of Appendix K to require that the sample flow rate through a sorbent trap monitoring system must be zero when the unit is not operating. This clarification is needed to prevent the system from sampling ambient air during periods when the combustion unit is off-line. Sampling ambient air when the unit is not in operation would artificially lower the Hg concentrations measured by the sorbent traps, resulting in under-reporting of Hg mass emissions.

II. Administrative Requirements

A. Executive Order 12866—Regulatory Planning and Review

This action is not a “significant regulatory action” under the terms of Executive Order (EO) 12866 (58 FR 51735, October 4, 1993) and is therefore not subject to review under the EO.

B. Paperwork Reduction Act

The information collection requirements in the proposed rule have been submitted for approval to OMB under the Paperwork Reduction Act, 44 U.S.C. 3501

et seq.

The Information Collection Request (ICR) document prepared by EPA has been assigned EPA ICR number 2203.01. The information requirements are based on the proposed revisions to the monitoring, recordkeeping, and reporting requirements in 40 CFR Part 75, which are mandatory for all sources subject to the Acid Rain Program under Title IV of the Clean Air Act and certain other emissions trading programs administered by EPA. 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 existing Part 75 rule requirements are covered by existing ICRs for the Acid Rain Program (EPA ICR number 1633.13; OMB control number 2060-0258), the NO

SIP Call (EPA ICR number 1857.03; OMB number 2060-0445), and the Clean Air Interstate Rule (EPA ICR number 2152.01). The separate ICR for the proposed rule revisions addresses the one ti

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