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

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 72 and 75

[EPA-HQ-OAR-2005-0132; FRL-8511-1]

RIN 2060-AN16

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

X

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

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Final rule.

SUMMARY:

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

X

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

The 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 do not impose significant new requirements upon sources with regard to monitoring or quality assurance activities.

DATES:

This final rule is effective on January 24, 2008, for good cause found as explained in this rule.

The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of January 24, 2008, for good cause found as explained in this rule.

ADDRESSES:

The EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2005-0132. All documents in the docket are listed in the

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

www.regulations.gov

or in hard copy at the Air and Radiation Docket, EPA/DC, EPA West Building, EPA Headquarters Library, Room 3334, 1301 Constitution Avenue, 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

X

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.

World Wide Web (WWW).

In addition to being available in the docket, an electronic copy of the final rule is also available on the WWW through the Technology Transfer Network Web site (TTN Web). Following signature, a copy of the 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.

Judicial Review.

Under CAA section 307(b), judicial review of this final action is available only by filing a petition for review in the U.S. Court of Appeals for the District of Columbia Circuit on or before March 24, 2008. Under CAA section 307(d)(7)(B), only those objections to the final rule that were raised with specificity during the period for public comment may be raised during judicial review. Moreover, under CAA section 307(b)(2), the requirements established by today's final rule may not be challenged separately in any civil or criminal proceedings brought by EPA to enforce these requirements. Section 307(d)(7)(B) also provides a mechanism for the EPA to convene a proceeding for reconsideration if the petitioner demonstrates that it was impracticable to raise an objection during the public comment period or if the grounds for such objection arose after the comment period (but within the time for judicial review) and if the objection is of central relevance to the rule. Any person seeking to make such a demonstration to EPA should submit a Petition for Reconsideration, clearly labeled as such, to the Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200 Pennsylvania Ave., Washington, DC 20460, with a copy to the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel, Mail Code 2344A, U.S. EPA, 1200 Pennsylvania Ave., NW., Washington, DC 20460.

Outline

I. Detailed Discussion of Rule Revisions

A. Rule Definitions

B. General Monitoring Provisions

C. Certification Requirements

D. Missing Data Substitution

E. Recordkeeping and Reporting

F. Subpart H (NO

X

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

O. Other Rule Revisions

II. Statutory and Executive Order Reviews

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

J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations

K. Congressional Review Act

L. Petition for Judicial Review

M. Determination Under Section 307(d)

I. Detailed Discussion of 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 in 2009.

Therefore, EPA finds good cause to determine that the final rule is effective on January 24, 2008. EPA normally issues final regulations with at least a 30-day effective date after

Federal Register

publication. However, this provision of the rule which pertains to the re-engineering of the Clean Air Markets Division's data systems and to implementation of the Clean Air Mercury Regulation (CAMR), must be effective by January 1, 2008. Today's rule allows sources the option of reporting emissions data in the new XML data reporting format in 2008, one year before the use of XML becomes mandatory. The final rule provides the necessary record keeping and reporting requirements to support the XML format. Second, sources subject to CAMR are required to install and certify continuous mercury (Hg) monitoring systems by January 1, 2009. To meet this deadline, companies with multiple CAMR-affected units will begin monitor certification testing in the first quarter of 2008. As described in Sections I.C.3 and I.O.3., today's rule adds two recently-published Hg test methods,

i.e.

, Methods 30A and 30B, to Part 75 as alternatives to the Ontario Hydro Method. For many sources, 30A and 30B will be the test methods of choice. Third, as discussed in Section I.A., today's rule defers until January 1, 2010 the requirement for the calibration standards used to certify Hg continuous emission monitoring systems (CEMS) under CAMR to be traceable to the National Institute of Standards and Technology (NIST). Fourth, for CAMR units that seek to qualify as low mass emitting units under § 75.81, Hg emission testing is required in 2008. As discussed in Section G.2., today's rule adds considerable flexibility to the way in which this testing is conducted, particularly for common stack configurations and groups of identical units. The use of Methods 30A and 30B for this testing is also desirable. Absent this determination of good cause, sources would not be able to begin scheduled monitoring certification activities until the necessary provisions of this rule became effective. A thirty day delay would significantly decrease the overall amount of time available for industry to comply with the certification deadline of January 1, 2009. Such a delay could result in sources not being able to meet the certification deadline, since industry would lose some of its ability to spread utilization of various certification resources (

i.e.

, test teams, equipment, and vendor support) over the entire course of 2008.

For these reasons, EPA believes it has good cause to expedite the effective date of this final rule.

A. Rule Definitions

Background

EPA proposed to add several new definitions to Part 72, including definitions for: “Long-term cold storage” (to mean the complete shutdown of a unit intended to last for at least two calendar years); “EPA Protocol Gas Verification Program” (to support the proposed calibration gas audit program); “Air Emission Testing Body (AETB)” and “Qualified Individual” (to support the proposed stack tester accreditation program).

EPA also proposed to modify the definitions of “Capacity factor”, “EPA protocol gas,” and “Excepted monitoring system”, and to remove the definition of “Calibration gas” and related definitions describing the various types of gas standards that are classified as calibration gas.

Summary of Rule Changes

All of the proposed new and modified definitions have been finalized without substantive changes. However, one commenter cautioned that removing the definitions of the calibration gas standards from Part 72 might have consequences that could necessitate further rule revisions. In view of this, the Agency reconsidered these proposed changes and the final rule retains all but one of the definitions. The definition of “Research gas material” was found to be identical to the definition of “Research gas mixture” and has been removed from the rule.

Further, for consistency with Method 30A, the new instrumental reference method for mercury (Hg) (which, as noted in sections I.C.3 and I.O.3 of this preamble has been added to the list of acceptable Hg reference methods in § 75.22), and in light of other changes in today's rule related to the certification of Hg monitoring systems, EPA is adding definitions of “NIST traceable elemental Hg standards” and “NIST traceable source of oxidized Hg” to § 72.2. These definitions pertain to Hg calibration gas standards and are deemed necessary for implementation of the continuous monitoring requirements of the Clean Air Mercury Regulation (CAMR).

Affected units under CAMR are required to install and certify Part 75-compliant Hg monitoring systems by January 1, 2009. To meet this requirement, the vast majority of the

certification testing will be performed in 2008. When CAMR was first proposed, only one reference test method (the Ontario Hydro (OH) Method) was prescribed for the relative accuracy test audits (RATAs) of the required Hg monitoring systems. However, the OH method is wet chemistry-based, and is both difficult and expensive to perform. Also, the laboratory analysis required to obtain the test results can take a week or more, making the OH method incompatible with the Hg emissions trading program described in the CAMR model rule.

In a cap and trade program, the RATA results must be known while the test team is still on-site, so that any necessary corrective actions can be taken and retesting performed without delay. With the OH method, if the results of the lab analysis indicate a RATA failure, a retest must be rescheduled and the Hg monitoring system is considered out-of-control until a subsequent RATA is passed. This can result in an extended missing data period and loss of Hg allowances.

Thus, it became apparent during the CAMR rulemaking that an alternative to the OH method was needed. An instrumental Hg reference method was put forth as the logical choice, because it would provide real-time Hg concentration data, allowing the RATA results to be known on the day of the test. When CAMR was published on May 18, 2005, EPA stated its intention to “propose and promulgate” an instrumental Hg reference method (see 70 FR 28636). In support of the final CAMR rule, Hg monitoring provisions were added to Part 75. Among these was an amendment to § 75.22, allowing the use of either the OH method or an “instrumental reference method * * * subject to the approval of the Administrator” for the certification testing of Hg continuous monitoring systems. Method 30A was published on September 7, 2007 in a direct-final rulemaking, and became effective on November 6, 2007 (

see

72 FR 51494). Method 30A represents the fulfillment of the Agency's commitment to publish an instrumental reference method for Hg.

One of the most important Part 75 requirements for the certification of Hg continuous emission monitoring systems (CEMS) is that the concentrations of the elemental and oxidized Hg calibration gas standards used for the 7-day calibration error tests, linearity checks, and system integrity checks of the CEMS must be traceable to the National Institute of Standards and Technology (NIST) (

see

Part 75, Appendix A, Section 5.1.9). This NIST traceability requirement for Hg standards is modeled after the NIST traceability requirements in Section 5 of Appendix A for SO

2

, NO

X

, and diluent gas (CO

2

and O

2

) calibration gas standards.

For the SO

2

, NO

X

, CO

2

, and O

2

compressed gas standards used in Part 75 applications, “NIST traceability” means that the calibration gases have been prepared according to the EPA-approved protocol cited in Section 5.1.4 of Appendix A. Further, § 75.22(c)(1) requires NIST-traceable gas standards to be used to calibrate the instrumental reference methods used for relative accuracy testing of SO

2

, NO

X

, CO

2

, and O

2

CEMS (

i.e.

, Methods 6C, 7E and 3A).

Prior to today's rulemaking, no NIST traceability protocols for Hg calibration standards were referenced in Part 75. The new definitions of “NIST traceable elemental Hg standards” and “NIST traceable source of oxidized Hg” address this deficiency and cite the EPA protocols that must be followed to ensure that the elemental and oxidized Hg standards are traceable to NIST. However, these protocols, which are referenced in Section 16.0 of Method 30A, are not yet fully developed, and are not expected to be ready for use until the latter part of 2008. A cooperative field demonstration program that will include representatives from EPA, NIST, industry, equipment vendors, and other key personnel is planned for the coming months, to gather the data necessary to refine and finalize the traceability protocols. Once these traceability protocols are finalized, they will be posted on the Agency's Technology Transfer Network Web site (

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

) and on the Agency's Clean Air Markets Division Web site (

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

).

In view of this, EPA is temporarily deferring (until January 1, 2010) the requirement for elemental and oxidized Hg standards to be NIST traceable. The deferral affects both initial certifications of the CEMS and routine quality-assurance tests of the CEMS performed prior to January 1, 2010. Note that only the NIST traceability requirement for the Hg calibration standards is being waived, not the requirement to perform the calibration error tests, linearity checks, and system integrity checks of the Hg monitoring systems by January 1, 2009.

Beginning on January 1, 2010, all daily calibration error tests, linearity checks, and system integrity checks of Hg CEMS must be performed using NIST traceable elemental and oxidized Hg calibration standards, as defined in § 72.2. Section 5.1.9 of Appendix A to Part 75 has been revised to reflect this. In view of this, EPA strongly recommends that in 2009, all CAMR-affected sources should take the necessary steps to ensure that the NIST traceability requirement is met. In most cases, this will involve the certification of elemental and oxidized Hg generators, according to the traceability protocols. If a source elects to perform daily calibrations and/or linearity checks using compressed gas cylinders instead of an elemental Hg generator, the owner or operator will have to obtain cylinder gases that conform to the EPA traceability protocol for gaseous calibration standards.

Finally, note that EPA is conditionally allowing Method 30A to be used for Part 75 Hg emission testing and RATA applications prior to finalization of the traceability protocols in section 16.0 of the method. The condition is that interim traceability protocols are developed and posted on the Agency's Technology Transfer Network Web site (

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

), as “broadly applicable alternative test method approvals” that will expire when the final protocols are issued. EPA's authority to approve such test method alternatives is described in 72 FR 4257, January 30, 2007.

EPA believes that a phased-in approach to NIST traceability is appropriate and necessary, in light of the additional time needed to finalize the traceability protocols and the time required for the affected sources and equipment vendors to set up the necessary infrastructure to implement the protocols. The Agency also believes that this approach will not compromise the quality of the data for the emissions trading program under CAMR, since in 2010, the first year in which Hg emissions count against allowances held, NIST traceability of the Hg calibration standards is mandatory.

B. General Monitoring Provisions

1. Update of Incorporation by Reference (§ 75.6)

Background

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). EPA proposed changes to § 75.6 that 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.

Summary of Rule Changes

The updates and additions to § 75.6 have been finalized as proposed. One commenter requested that an additional ASTM method for analyzing the sulfur content of low-sulfur fuel oil, i.e., ASTM D5453-06, “Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and Engine Oil by Ultraviolet Fluorescence”, be added to the list of acceptable methods in § 75.6. This method has been incorporated by reference as § 75.6(a)(49) and has been added to section 2.2.5 of Appendix D.

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

Background

EPA proposed to allow LME units to use site-specific default SO

2

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

2

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, if made, would allow more representative, yet still conservatively high, SO

2

emissions data to be reported from oil-burning LME units. As proposed, the site-specific default SO

2

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.

The Agency also proposed to revise § 75.19(c)(1)(iv)(G) to clarify that fuel-and-unit-specific default NO

X

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. Lastly, the Agency proposed technical revisions to the Equations LM-5 and LM-6 changing the units of rate to units of measure to make the equations correct as units of rate cannot technically be summed.

Summary of Rule Changes

Commenters were generally supportive of the proposed revisions to § 75.19, and they have been finalized with only one substantive change. EPA has incorporated one commenter's suggestion not to restrict the allowable fuel oil sampling options to those described in Appendix D. The final rule allows the use of other consensus standard fuel sampling methods (e.g., ASTM, API, etc.) specified in applicable State or Federal regulations or in the unit's operating permit, to determine the sulfur content of the oil.

Another commenter requested that EPA go beyond its proposal for SO

2

and consider providing a similar, more reasonable site-specific alternative to reporting the generic NO

X

emission rates in Table LM-2. Specifically, the commenter suggested that for units with very low annual capacity factors, the Agency should waive the testing requirements of §§ 75.19(c)(1)(iv) and allow emission test data that was generated more than 5 years ago (e.g., from a Part 60 performance test) to be used to determine fuel-specific default NO

X

emission rates. The commenter asserted that the cost of additional testing could impose a financial burden on smaller affected sources. After careful consideration, EPA decided against allowing infrequently-operated units to use emission test data older than 5 years for Part 75 reporting. However, § 75.19(c)(1)(iv)(I) has been amended to provide reduced emission testing requirements for very low capacity factor LME units. The final rule allows single-load testing, between 75 and 100 percent of maximum load, to be performed (both for the initial Appendix E testing and for retests) if, for the 3 years prior to the year of the test, the unit's average capacity factor was 2.5 percent or less and did not exceed 4.0 percent in any of those three years. Alternatively, for combustion turbines, the emission test may be done at the maximum attainable load corresponding to the season of the year in which the test is performed. For a group of identical units, the single-load testing option may be used for any unit(s) in the group that meet the very low capacity factor requirements. For a more detailed discussion of this issue, refer to section 2.3.2 of the Response to Comments (RTC) document.

3. Default Moisture Value for Natural Gas

Background

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

2

O under § 75.11(b), and 18.0% H2O under § 75.12(b). The Agency also proposed that the higher default value would apply only when Equation 19-3, 19-4, or 19-8 (from Method 19 in appendix A-7 to part 60 of this chapter) is used to determine the NO

X

emission rate. The proposed default values represent the 10th and 90th percentile values from two sets of supplemental moisture data provided to the Agency, which is consistent with the approach that the Agency has used in responding to past petitions under § 75.66 for site-specific default moisture values.

Summary of Rule Changes

No adverse comments were received on these proposed rule changes and they have been finalized.

4. Expanded Use of Equation F-23

Background

EPA proposed to revise § 75.11(e)(1) to remove the current restrictions on the use of Equation F-23 to determine the SO

2

mass emission rate, by allowing Equation F-23 to be used whether or not the unit has an SO

2

monitor and to expand its use to fuels other than natural gas. The proposal would allow Equation F-23 to be used for any gaseous fuel that qualifies for a default SO

2

emission rate under Section 2.3.6(b) of Appendix D. Further, Equation F-23 could 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

2

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

Summary of Rule Changes

Commenters were supportive of the expanded use of Equation F-23 and the revisions to § 75.11(e) and corresponding changes to section 7 of Appendix F have been finalized as proposed.

5. Calculation of NO

X

Emission Rate—LME Units

Background

EPA proposed to re-title § 75.19(c)(4)(ii) as “NO

X

mass emissions and NO

X

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

X

emission rates for a LME unit. The NO

X

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

X

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

X

emission control status. Then, the Agency proposed that the quarterly NO

X

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

X

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

X

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

Summary of Rule Changes

No adverse comments were received on these proposed rule changes and the revisions to § 75.19(c)(4)(ii) have been finalized as proposed.

6. LME Units—Scope of Applicability

Background

EPA proposed to 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 is 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 is permitted. Parallel revisions to §§ 75.11(d)(3), 75.12(e)(3), and 75.13(d)(3), consistent with the changes to § 75.19(a)(1), were also proposed to clarify the Agency's intent.

Summary of Rule Changes

No adverse comments were received on the proposed changes and they have been finalized.

7. Use of Maximum Controlled NO

X

Emission Rate When Using Bypass Stacks

Background

Revisions to § 75.17(d)(2) were proposed that would allow a maximum controlled NO

X

emission rate (MCR) to be reported instead of the maximum potential NO

X

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. For example, for 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 MCR, rather than the MER, would be the more appropriate NO

X

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

X

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

X

concentration (MPC).

Summary of Rule Changes

Commenters were generally supportive of the proposed rule changes and they have been finalized. One commenter recommended that parallel language be added to § 75.72(c)(3), to cover non-Acid Rain Program units that are subject to the NO

X

mass emissions monitoring provisions of Subpart H. EPA agrees with this comment and has added the necessary language to § 75.72(c)(3).

C. Certification Requirements

1. Alternative Monitoring System Certification

Background

EPA proposed to 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 in §§ 75.40 through 75.48 that alternative monitoring systems must meet in order to be certified.

Summary of Rule Changes

Commenters were supportive of the proposed amendments to § 75.20(f), and they have been finalized.

2. Part 60 Reference Test Methods

Background

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). These test methods are prescribed for Part 75 emission testing and RATAs. Three new testing options that were added to the methods were deemed unacceptable for use under Part 75. These include:

(1) Section 7.1 of revised EPA Method 7E, allowing for custom calibration gas concentrations to be produced by diluting EPA protocol gases, in accordance with Method 205 in Appendix M of 40 CFR Part 51.

(2) Section 8.4 of revised EPA Method 7E, allowing the use of a multi-hole “rake” probe to satisfy the multipoint traverse requirement of the method.

(3) Section 8.6 of revised EPA Method 7E, allowing for the use of “dynamic spiking” as an alternative to the interference and system bias checks of the method.

Although revised Method 7E states that for use under Part 75 the three options above require approval by the Administrator, EPA proposed to add similar language to § 75.22(a)(5) to reinforce its position regarding these testing alternatives.

Summary of Rule Changes

No adverse comments were received on the proposed amendments to § 75.22(a)(5) and they have been finalized. However, one commenter brought to EPA's attention another revision to the Part 60 reference methods that impacts Part 75. EPA Method 20 was also revised on May 15, 2006. Method 20 has been the NO

X

emission test method prescribed for combustion turbines (CTs) in section 2.1.2.2 of Appendix E. Method 20 has also been used to determine fuel-specific NO

X

emission rates for combustion turbines that qualify as low mass emissions (LME) units under § 75.19.

The original Method 20 required testing at 8 sampling points per run, with typical run times averaging about 15 to 20 minutes. However, the revised Method 20 no longer specifies the minimum number of test points per run, but rather requires sampling point selection to be done according to Method 7E. Revised Method 7E requires 12 traverse points for an emission test run (which would suffice for Appendix E testing), but the method also allows the results of stratification testing to be used to justify using three or, in some cases, one sample point instead. This raises questions about the required length of an Appendix E test run. For instance, if testing were required at only one point, each Appendix E test run would be reduced from 15-20 minutes to as little as 2 minutes (depending on the system response time). The commenter stated that such short sampling runs seem inadequate to

develop a substantial correlation curve for emission reporting. The commenter recommended that EPA modify Appendix E or Method 20 and either set a minimum run time of 20 minutes (providing an hour of data at each load) or specify a minimum number of sampling points for an Appendix E test of a CT.

EPA has incorporated the commenter's recommendations into Part 75. First, § 75.22(a)(5) has been amended to prohibit the use of Method 7E to determine the required number of sample points for the emission testing of a combustion turbine. Section 75.22(a)(5)(ii) requires the sample points to be determined according to section 2.1.2.2 of Appendix E, instead. Second, for the emission test of a CT, section 2.1.2.2 of Appendix E has been revised to require a minimum of 12 test points per run, located according to EPA Method 1. Third, amendments have been made to § 75.22(a)(6), § 75.19(c)(1)(iv)(A), section 6.5.10 of Appendix A, and sections 2.1.2.2 and 2.1.2.3 of Appendix E, to remove all references to EPA Method 20 from Part 75. Fourth, for the testing of an Appendix E boiler, the text of section 2.1.2.1 of Appendix E has been revised to require 12 traverse points per run, making it consistent with revised section 2.1.2.2 (note that this is not a new requirement—section 2.1.2.1 has always required 12 test points, located according to section 8.3.1 of Method 3, and that section refers back to Method 1). Finally, in section 2.1.2.3 of Appendix E, the references to the measurement system response time in section 5.5 of Method 20 (which section no longer exists) have been replaced with references to the response time provisions in sections 8.2.5 and 8.2.6 of Method 7E. Appendix E tests performed on CTs prior to the effective date of these amendments are grandfathered from the revised test point location requirements.

3. Mercury Reference Methods

Background

EPA proposed to add an alternative relative deviation (RD) specification for the results of mercury (Hg) emission data collected with paired Ontario Hydro (OH) reference method sampling trains. The principal RD specification in § 75.22(a)(7) is 10 percent. However, this acceptance criterion may be too stringent for sources with low Hg emissions. Therefore, for average Hg concentrations of 1.0 μg/m

3

or less, EPA proposed an alternative RD specification of 20 percent. This is consistent with the acceptance criteria for data from paired OH trains, as specified in Performance Specification 12A in Appendix B of 40 CFR Part 60.

EPA also proposed amendments to §§ 75.22(a)(7), 75.59(a)(7), 75.81(c)(1), and to sections 6.5.10 and 7.6.1 of Appendix A, allowing EPA Method 29 (back-half impinger catch, only) 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). Two caveats on the use of Method 29 were proposed. First, sources electing to use Method 29 (which is similar to the OH method, but somewhat simpler and more familiar to stack testers) would be required to use paired sampling trains (i.e., two trains sampling the source effluent simultaneously), and the RD specifications in § 75.22(a)(7) would have to be met for each run. Second, certain analytical and quality assurance (QA) procedures in the OH method (ASTM D6784-02) would have to be followed instead of the corresponding procedures in Method 29 (because the analytical and quality assurance/quality control (QA/QC) requirements of the OH method are more detailed and rigorous than those in Method 29), and testers could opt to follow several of the sample recovery and preparation procedures in the OH method instead of the Method 29 procedures.

Finally, the Agency solicited comment on the use of sorbent traps for reference method testing. Members of the regulated community had expressed an interest in using portable sorbent trap monitoring systems for Hg reference method testing, as an alternative to the OH method. EPA proposed to accommodate a possible future sorbent-based reference method by adding language to § 75.22(a)(7) that would allow an “other suitable” reference method approved by the Administrator to be used for Hg emission testing and RATAs.

Summary of Rule Changes

Commenters were generally supportive of the proposed amendments that would add Method 29 as an alternative Hg reference method, and those provisions have been finalized without substantive change. One commenter objected to the requirement to use paired sampling trains for OH and Method 29 tests, asserting that this adds to the cost of testing and may result in significant numbers of test runs being discarded. However, EPA does not agree with the commenter. The Agency believes rather that paired sampling trains provide added assurance of data quality when these test methods are used. The decision to require paired trains for the OH method was made during the rulemaking that led to publication of the Clean Air Mercury Regulation (CAMR) (

see

70 FR 28636-28639, May 18, 2005).

Two commenters supported the proposed 20 percent alternative RD specification for low emitters, and that provision has been finalized. However, one of the commenters noted that even a 20 percent RD specification may be too stringent for extremely low Hg concentrations. EPA agrees that when Hg concentrations are exceptionally low (0.1 μg/m

3

or less), the 20 percent RD specification may be difficult to meet. Therefore, the final rule adds a third tier to the RD specifications in § 75.22. The paired train agreement is also considered to be acceptable if the absolute difference between the two measured Hg concentrations does not exceed 0.03 μg/m

3

.

Several commenters strongly supported the proposal to allow the use of a sorbent-based reference method for Hg emission testing and for the RATAs of Hg monitoring systems. Since publication of the proposed rule, a great deal of progress has been made in this area. First, EPA conducted a Method 301 analysis of available data comparing sorbent trap sampling to the OH method. The results of this analysis showed that a sorbent-based sampling method can be a viable alternative reference method. Second, EPA drafted “Method 30B”, a reference method that uses iodated carbon traps to measure vapor phase Hg emissions. Finally, as part of a direct final rulemaking, Method 30B was published on September 7, 2007 (

see

72 FR 51494-51531), along with Method 30A, an instrumental Hg reference method. Today's final rule allows both Methods 30A and 30B to be used.

D. Missing Data Substitution

1. Block Versus Step-Wise Approach

Background

Historically, EPA's policy has required sources to use a “block” approach for CEMS missing data substitution. The percent monitor data availability (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 reconsidered and revised its missing substitution data policy, to allow 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.

Since Part 75 is not clear about which of the two methods should be used for missing data substitution, EPA proposed to amend §§ 75.33 and 75.32(b), to clarify that the stepwise, hour-by-hour method is the preferred one, and that use of that method would be required for all CEMS data recorded on and after January 1, 2009, and for any CEMS data recorded in XML-format during the transition year of 2008.

Summary of Rule Changes

Commenters unanimously supported the proposal to adopt stepwise missing data substitution and the proposed amendments to §§ 75.32 and 75.33 have been finalized.

2. Substitute Data Values for Controlled Units

Background

For units with add-on emission controls, when the PMA for SO

2

or NO

X

is below 90.0 percent, § 75.34(a)(3) has historically allowed the designated representative (DR) to petition the Administrator under § 75.66 for permission to report the maximum controlled concentration or emission rate recorded in a specified lookback period instead of reporting the maximum value recorded in that lookback period, for each missing data hour in which the add-on controls are documented to be operating properly. After more than ten years of implementing the Acid Rain Program, EPA no longer believes that such special petitions are necessary, 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.

In view of this, the Agency proposed to remove from § 75.34(a)(3) and § 75.66(f) the requirement to petition the Administrator to use the maximum controlled SO

2

or NO

X

concentration (or maximum controlled NO

X

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 also proposed 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 missing data 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

2

or NO

X

concentration (MPC) or the maximum potential NO

X

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

2

and NO

X

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

X

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

X

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

X

MCR would be calculated in the same manner as the NO

X

MER, except that the MEC, rather than the MPC, would be used in the calculation. The proposed alternative data substitution methodology in § 75.34(a)(5) would ensure that the substitute data values for the fourth missing data tier are always higher than the corresponding substitute data values for the third tier.

Finally, EPA proposed to 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).

Summary of Rule Changes

Comments on the proposed alternative missing data substitution values for controlled units were generally supportive and these provisions have been finalized. Two commenters requested that parallel language be added to § 75.72(c)(3), to extend the use of the new missing data provisions to ozone season-only reporters. Another commenter asked EPA to clarify that the MCR may be implemented on a fuel-specific basis. EPA has incorporated both of these suggestions in the final rule. Two other commenters suggested that, for common stack configurations, EPA should allow the substitute data values to be apportioned or prorated in some way instead of requiring maximum potential values to be reported, in cases where the emission controls installed on some of the units sharing the stack are documented to be operating properly, but such documentation cannot be provided for the controls on the other units. The Agency believes that this approach would unnecessarily complicate the missing data substitution process and would provide no assurance that emissions are not being underestimated. Therefore, this suggestion was not incorporated in the final rule.

3. Substitute Data Values for Hg

Background

EPA proposed to revise the Hg missing data procedures. First, for Hg CEMS, the text of § 75.38(a) would be amended to clarify that the 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 proposed to completely revise the missing data provisions in § 75.39 for sorbent trap monitoring systems, to make them the same as for Hg CEMS, so that. the initial missing data procedures of § 75.31(b) and the standard Hg missing data provisions of § 75.38 would be followed for sorbent trap systems. EPA believes that this proposed missing data approach greatly simplifies the missing data substitution process for Hg monitoring systems. 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, under the proposal, when the owner or operator elects to use a primary Hg CEMS and a backup sorbent trap system (or vice-versa), the appropriate substitute data values would be derived from a lookback through the previous 720 hours of quality-assured data, irrespective of

whether they were from the primary monitoring system or from the backup system.

Summary of Rule Changes

Commenters were supportive of the proposed changes to the sorbent trap missing data procedures in § 75.39, and these provisions have been finalized.

4. Correction of Cross-References

Background

For sources that report emissions data on an ozone season-only basis, EPA proposed to revise § 75.74(c)(3)(xi) and (c)(3)(xii) by replacing references to specific missing data sections with more general references to the entire block of CEMS missing data sections, i.e., §§ 75.31 through 75.37.

Summary of Rule Changes

No adverse comments were received on these proposed rule changes and they have been finalized, as proposed.

E. Recordkeeping and Reporting

Background

To accommodate its new, re-engineered XML reporting format, which will replace the current electronic data reporting (EDR) format in 2009, EPA proposed to revise the monitoring plan recordkeeping requirements in § 75.53, with corresponding revisions to § 75.73(c)(3) (for sources reporting NO

X

mass emissions under Subpart H) and to § 75.84 (for sources reporting Hg mass emissions under Subpart I).

EPA proposed 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. Under this proposal, the provisions of paragraphs (g) and (h) would be followed instead of the existing recordkeeping requirements of paragraphs (e) and (f), on and after January 1, 2009. In 2008, sources would be allowed to choose between the EDR format and XML, but new sources reporting for the first time in 2008 would be strongly encouraged to use the XML format. Included among the proposed monitoring plan changes would be mandatory recording and reporting of the key rectangular duct wall effects data elements using these record types. The proposed requirements to record and report the results of wall effects adjustment factor (WAF) determinations in the monitoring plan are found in §§ 75.53 (e) and (g) and in § 75.64.

EPA also proposed to make a series of modifications to §§ 75.58 and 75.59 to support the new XML data structure. The proposed changes to the monitoring plan and recordkeeping sections were presented, section-by-section, in Tables 1, 2, and 3 in the preamble to the August 22, 2006 proposed rule.

Summary of Rule Changes

No significant adverse comments were received on the proposed changes and they have been finalized.

1. Other Reporting Issues

a. Long-Term Cold Storage and Deferred Units

Background

EPA proposed changes to Part 75 to clarify the meaning of the term “long-term cold storage (LTCS)”, found in § 75.4(d). First, a proposed 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, the Agency proposed to add a new paragraph, (a)(7), to § 75.61, requiring the owner or operator to provide notifications when a unit is placed in LTCS and when the unit re-commences operation. Third, modifications to § 75.20(b) were proposed, requiring 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 LTCS 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, for consistency.

EPA also proposed 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 proposed revisions would broaden the scope of § 75.4(d) beyond the Acid Rain Program, to include units in State or Federal pollutant mass emissions reduction programs that adopt 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 proposed revisions to §§ 75.4(d) and 75.61(a)(3) were deemed necessary because the CAIR and CAMR rules do not address deferred units.

The proposed revisions to § 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, EPA proposed that 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. Finally, the Agency proposed to revise the notification requirements of § 75.61(a)(3) to be consistent with the proposed changes to § 75.4(d).

Summary of Rule Changes

Commenters were generally supportive of the proposed long-term cold storage provisions, requesting only minor clarifications. These provisions have been finalized with no substantive changes. One commenter encouraged EPA to adopt the proposed amendments to broaden the scope of § 75.4(d), to ensure that deferred units under programs such as CAIR and CAMR are provided with a reasonable window of time in which to certify the required monitoring systems, when the units resume operation. EPA has finalized these amendments to § 75.4(d), as proposed.

b. Notice of Initial Certification Deadline

Background

EPA proposed to add a new paragraph (a)(8) to § 75.61, 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, this date will always be a particular number of calendar days or unit operating days after a unit either:

(a) Commences commercial operation; (b) commences operation; or (c) becomes an affected unit. For Acid Rain Program sources, 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.

Summary of Rule Changes

One commenter asserted that the requirement for sources to submit to EPA a notification of the deadline for initial monitoring system certification is unnecessarily burdensome and should not be incorporated into Part 75. Another commenter requested that the information be reported in the electronic monitoring plan, rather than requiring a separate notification. EPA does not agree that reporting this information will be burdensome or that it is appropriate to report the date of the initial certification deadline in the electronic monitoring plan. Rather, this date is an essential data element that will be managed using the web-based CAMD Business System (CBS). Therefore, the notification requirement can be met electronically using the CBS. In view of this, the amendment to § 75.61 has been finalized, as proposed.

c. Monitoring Plan Submittal Deadline

Background

EPA proposed to amend § 75.62(a) by changing 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, in order to synchronize the initial monitoring plan submittal with the initial test notice. Corresponding changes to Subpart H (§ 75.73(e)) and to Subpart I (§ 75.84(e)) were proposed, for consistency.

EPA also proposed to remove the requirement from § 75.62(a)(1) that the electronic 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, but this option would only be available to sources reporting in the new XML format under the re-engineered data submission process.

Summary of Rule Changes

No adverse comments were received on these proposed rule changes and they have been finalized, as proposed.

d. EPA Form 7610-14

Background

EPA proposed to amend §§ 75.63(a)(1) and (a)(2), to remove the requirement to submit hardcopy EPA form 7610-14 along with every certification or recertification application. Significant upgrades to EPA's data systems have been made in recent years, and Form 7610-14 is no longer needed to process these applications.

Summary of Rule Changes

No adverse comments were received on these proposed rule changes and they have been finalized, as proposed.

e. LME Applications

Background

EPA proposed to remove the requirement from § 75.63(a)(1)(ii)(A) for a hardcopy LME certification application to be submitted to the Administrator. The proposal would require only the electronic portion of the application, including the monitoring plan and LME qualification records, to be sent to EPA's Clean Air Markets Division. The hardcopy portion of the LME application would be sent to the State and to the EPA Regional Office.

Summary of Rule Changes

No adverse comments were received on these proposed rule changes and they have been finalized, as proposed.

f. Reporting Test Data for Diagnostic Events

Background

EPA proposed 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 proposed flexibility in the reporting of diagnostic test results would only be available to sources reporting in the new XML format under the re-engineered data submission process.

Summary of Rule Changes

No adverse comments were received on these proposed rule changes and they have been finalized, as proposed.

g. Modifications to § 75.64

Background

As part of its data systems re-engineering effort, EPA proposed to revise § 75.64(a) to describe the transition from the existing EDR reporting requirements to the reporting requirements of the new XML format. The Agency proposed to renumber several paragraphs, to replace paragraphs (a)(1) and (a)(2) with new paragraphs (a)(3) through (a)(7), and to remove existing paragraph (a)(8).

Summary of Rule Changes

No adverse comments were received on these proposed rule changes. These amendments to § 75.64(a) have been finalized, as proposed.

h. Steam Load Reporting

Background

EPA proposed to add a third option to Part 75 for reporting load data 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. The Agency proposed to add text to several sections in the main body of Part 75 and to the Appendices, to accommodate the new reporting option.

Summary of Rule Changes

No adverse comments were received on these proposed rule changes and they have been finalized, as proposed.

i. Test Notification Requirements—Hg Low Mass Emission Units

Background

Section 75.61(a)(5) requires the owner or operator or the designated representative to provide 21-day advance notice for various periodic quality-assurance tests, including the semiannual or annual relative accuracy tests of CEMS, and for the re-tests of Appendix E peaking units and low mass emissions (LME) units. Test notices 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).

Under Subpart I of Part 75, certain low-emitting units covered by the Clean Air Mercury Regulation (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. EPA proposed to expand the notification requirements of § 75.61(a)(5) and to add

corresponding introductory text to § 75.61(a)(1), requiring the owner or operator or the designated representative to provide at least 21 days notice of the scheduled dates of these periodic Hg emission tests.

Summary of Rule Changes

No adverse comments were received on this proposed rule change and this test notification requirement has been finalized, as proposed.

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

Background

Sections 75.60(b)(6) and (b)(7) 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. EPA proposed to 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 Hg emission tests required under § 75.81(d)(4) for low-emitting units covered by CAMR. The proposed time frame for submitting these Hg emission test results would be the same as the current one for the RATAs and Appendix E re-tests.

Summary of Rule Changes

No adverse comments were received and this provision has been finalized, as proposed.

k. Wall Effects Adjustment Factors

Background

For sources with flow monitors installed on circular stacks, reporting of wall effects information is currently required by §§ 75.64(a)(2)(xiii), 75.73(f)(1)(ii)(K) and 75.84(f)(1)(ii)(I), when Method 2H is used in conjunction with Method 2, 2F or 2G. The specific wall effects data elements that must be reported are found in § 75.59(a)(7)(ii) and (a)(7)(iii). These data 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, EPA proposed to revise the text of §§ 75.64(a)(2)(xiii), 75.73(f)(1)(ii)(K) and 75.84(f)(1)(ii)(I) and to add RATA support data elements to a new paragraph, (vii), in § 75.59(a)(7), to 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.

Summary of Rule Changes

No adverse comments were received on these proposed rule changes and they have been finalized, as proposed.

F. Subpart H (NO

X

Mass Emissions)

1. Subpart H Diluent Monitoring Systems

Background

For coal-fired Subpart H units that calculate NO

X

mass emissions as the product of NO

X

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

2

or CO

2

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

2

or CO

2

monitoring system”. EPA proposed to revise the text of § 75.71(a)(2) accordingly.

Summary of Rule Changes

No adverse comments were received. This clarification of § 75.71(a)(2) has been finalized, as proposed.

2. Identifying a NO

X

Mass Methodology

Background

EPA proposed to revise § 75.72 to require that only one NO

X

mass emissions methodology be identified in the monitoring plan at any given time, and to disallow the designation of primary and secondary NO

X

mass calculation methodologies. EPA believes that one methodology for NO

X

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

X

data when the diluent component of the NO

X

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

X

concentration times flow rate calculation method as the NO

X

mass calculation methodology. This would require a NO

X

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

X

emission rate system. The NO

X

concentration system would be used only to determine NO

X

mass emissions, and the NO

X

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

X

in lb/mmBtu.

Summary of Rule Changes

No adverse comments were received. This provision has been finalized, as proposed.

3. Reporting of Subpart H Facility Information

Background

Consistent with the proposed revisions to § 75.64, EPA proposed 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.

Summary of Rule Changes

No adverse comments were received. This provision has been finalized, as proposed.

4. Linearity Check Requirements for Ozone Season-Only Reporters

Background

For Subpart H sources that report emissions data on an ozone season-only (OSO) basis, EPA proposed to 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). Historically, OSO reporters have been 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. In some cases, this has resulted in CEMS out-of-control periods and has required the use of missing data substitution. OSO reporters have also been required 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 also not well-understood by the affected sources and assessing compliance with the provision has been difficult, since sources have not been required to report the results of any off-season calibration error tests done prior to April.

In view of these considerations, EPA proposed to revise § 75.74(c)(2) to require the pre-season linearity checks to be conducted in the month of April, and to delete all references to

performing the pre-season linearity checks at other times. The Agency also proposed to remove the conditional grace period provision from § 75.74(c)(2)(i)(D), and to address (in § 75.74(c)(3)(ii)(E)) data validation in the case where the April linearity check is not completed prior to the start of the ozone season. In that case, 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. A 168 unit operating hour period of conditional data validation would be allowed, in which to perform the required linearity check. Passing the linearity check on the first attempt within the allotted time would result in the conditionally valid data becoming quality-assured. Failing the linearity check would result in all data from the monitor be invalidated back to the beginning of the ozone season and the data would remain invalid until a linearity check is passed. Performing the linearity check after the 168-hour period expires would require the data validation provisions in § 75.20(b)(3)(viii) to be applied, subject to the restrictions of § 75.74(c)(3)(xii).

EPA proposed to 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, and to remove and reserve related Section 75.74(c)(3)(viii). 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, the Agency proposed that § 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 a linearity check is performed and passed in the third quarter, before the 168 operating hour window expires, EPA proposed that this 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.

Summary of Rule Changes

The amendments to § 75.74(c) have been finalized, as proposed. Commenters supported EPA's proposal to allow a linearity check performed in April to satisfy both the pre-season and second quarter linearity check requirements. However, several commenters requested that the Agency allow greater flexibility in the timing of the required linearity checks. The proposed amendments requiring the pre-season linearity check to be performed April and the 3rd quarter test to be done in July were perceived as being too restrictive. EPA does not agree with these commenters that the revised quality assurance requirements for ozone season-only reporters lack flexibility. The amendments allow sources to use conditional data validation for up to 168 unit or stack operating hours, in situations where the linearity check cannot be completed by the prescribed deadline. If the required test is performed and passed within the allotted window of time, the source will incur no data loss. OSO reporters desiring greater flexibility in scheduling quality assurance tests should seriously consider switching to year-round reporting. Doing so would provide many benefits, such as grace periods, test deadline extensions, and in some cases, test exemptions.

5. RATA Requirements for Ozone Season Only Reporters

Background

For Subpart H sources that report NO

X

mass emission data on an ozone season-only (OSO) basis, Part 75 has required, 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. In past years, this requirement has been 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. The rule has further required each CEMS to be operated, calibrated and maintained in the time period extending from the completion of the RATA, through April 30. 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.

In view of these considerations, EPA proposed to restrict the window of time in which pre-season RATAs may be performed. As 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. That restriction would prohibit RATAs done in the previous year from being used to validate data in the current ozone season.

EPA also proposed to revise § 75.74(c)(2)(ii)(F), to address data validation. The proposed data validation rules for RATAs are similar to those proposed for linearity checks, in that a period of conditional data validation (720 operating hours) would be allowed when the pre-season RATA is not completed by the April 30th deadline. Consistent with these revisions, the Agency proposed to delete the data validation and conditional grace period provisions in § 75.74(c)(2)(ii)(G) and (c)(2)(ii)(H) and to remove and reserve § 75.74(c)(3)(vi), (vii), and (viii).

Summary of Rule Changes

The amendments to § 75.74(c) have been finalized, as proposed. One commenter objected to the proposed restriction on the timing of the RATAs and requested that the existing flexibility in the rule be retained. The commenter expressed a strong preference to perform RATAs in the autumn, rather than in the January-April time frame proposed by EPA. A second commenter stated that EPA should remove the requirement to keep records of off-season daily calibration and interference check records in a format suitable for inspection from § 75.74(c)(2)(ii)(E)(

1

).

Regarding the first commenter's assertion that the proposed RATA time frame for OSO reporters is too restrictive, EPA recommends that the owner or operator seriously consider switching to year-round reporting. Year-round reporting allows complete freedom to schedule RATAs at any convenient time during the year and provides many benefits, such as grace periods, test deadline extensions, and in some cases, test exemptions. Even if EPA had decided not to amend the RATA provisions for OSO reporters, § 75.74(c)(2)(ii)(E)(

1

) would still require the CEMS to be operated, maintained and calibrated in the time period between the RATA and the start of the next ozone season. Thus, if the RATAs are performed in the autumn (e.g., November), the CEMS would have to be maintained and calibrated for at least 10 months of the year; in this case, OSO reporting offers no clear advantage over year-round reporting.

EPA did not incorporate the second commenter's suggestion to remove the recordkeeping requirement from § 75.74(c)(2)(ii)(E)(

1

). However, the text of § 75.74(c)(6)(iii) has been revised to remove the requirement to report the daily calibrations and interference checks done in the month of April. The requirement to record these data remains intact, but the reporting has been made optional.

6. Determining Peaking Status for Ozone Season Only Reporters

Background

EPA proposed 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.

Summary of Rule Changes

No adverse comments were received. This provision has been finalized, as proposed.

7. Calculation of Ozone Season NO

X

Mass Emissions—LME Units

Background

EPA proposed to correct an organizational error in Subpart H of Part 75. The proposal would remove § 75.72(f), which describes ozone season NO

X

mass calculations for units using the low mass emission (LME) methodology under § 75.19, and the basic content of § 75.72(f) 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.

Summary of Rule Changes

No adverse comments were received. This provision has been finalized, as proposed.

G. Subpart I (Hg Mass Emissions)

1. Heat Input Provisions for Common and Multiple Stacks

Background

Due to an apparent oversight, the heat input monitoring provisions for certain monitoring configurations in Subpart I of Part 75 were inadvertently omitted when Subpart I was promulgated. In particular, EPA found the heat input methodologies for common stacks shared by affected and non-affected units and for multiple stack or duct configurations to be missing. In view of this, the Agency proposed to 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.

Summary of Rule Changes

No adverse comments were received. These provisions have been finalized, as proposed.

2. Low Mass Emission Alternative

Background

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), as originally published, allowed 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 was implied that the periodic retests for common stack configurations would also have to be done at the unit level. EPA has reconsidered this approach, believing it to be overly restrictive, unnecessarily difficult, and costly to implement.

Therefore, EPA proposed 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 proposed option, the group of 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 amendments allowed 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, i.e., 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. 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 have to be “normal”, as defined in Section 6.5.2.1 of Appendix A.

EPA also proposed to revise § 75.81(c)(1), to specify the acceptable time frame in which to perform the initial certification testing for the low mass emission option. As originally published, the 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.

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. This also raises questions about which default emission rate to use for the initial reporting. In view of these considerations, EPA proposed 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 proposed to amend §§ 75.81(d)(4) and (d)(5) to address the emission testing requirements when the fuel supply is changed. The proposed revisions would require additional Hg retesting within 720 unit operating hours, following a change in the fuel supply. The results of this retest would then be applied retrospectively, back to the time of the fuel switch. The Agency also proposed to revise § 75.81(c)(1) 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 proposed revisions only addressed 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. EPA solicited comments and suggestions on how to apply the Hg low mass emitter option in situations 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 (i.e., what emission testing and reporting requirements might be appropriate).

Summary of Rule Changes

Commenters were generally supportive of the proposed amendments that would reduce the testing requirements for Hg low mass emission units in common stack configurations. The final rule differs somewhat from the proposal, however, in that it also allows the initial qualifying test to be performed at the common stack, if certain conditions are met. The conditions are: (1) Testing must be done at a combined load corresponding to the designated normal load level (low, mid, or high) defined in the monitoring plan; (2) all of the units that share the stack must be operating in a normal, stable manner and at typical load levels during the emission testing; (3) the coal combusted in each unit during the testing must be representative of the coal that will be combusted in that unit at the start of the Hg mass emission reduction program (preferably from the same source(s) of supply); and (4) if flue gas desulfurization and/or add-on Hg emission controls are used to reduce the level of emissions exiting from the common stack, these emission controls must be operating normally during the emission testing and the owner or operator must record parametric data or SO

2

concentration data in accordance with § 75.58(b)(3)(i) to document proper operation of the controls.

For retests, provided that the required load level is attained and that all of the units sharing the stack are fed from the same on-site coal supply during normal operation, it is not necessary for all of the units sharing the stack to be in operation during a retest. However, if two or more of the units that share the stack are fed from different on-site coal supplies (e.g., one unit burns low-sulfur coal for compliance and the other combusts higher-sulfur coal), then the owner or operator must either: (1) Perform the retest with all units in normal operation; or (2) if this is not possible, due to circumstances beyond the control of the owner or operator (e.g., a forced unit outage), perform the retest with the available units operating and assess the test results as follows. The Hg concentration obtained in the retest is used for reporting purposes if the concentration is greater than or equal to the value obtained in the most recent test. However, if the retested value is lower than the Hg concentration from the previous test, then the higher value from the previous test continues to be used for reporting purposes, and that same higher Hg concentration is used in Equation 1 to determine the due date for the next retest.

The final rule expands the testing of groups of identical units beyond identical units that share a common stack. Section 75.81(c)(1)(iv) has been amended to allow a subset of any group of identical units to be tested according to Table LM-4 in § 75.19, whether or not the units share a common stack. This amendment is modeled after the provisions of § 75.19(c)(1)(iv)(B) for testing groups of identical LME units.

Several commenters objected to the proposed requirement to perform retesting of low mass emission units when the fuel supply is changed. Concerns were expressed that the term “change in fuel supply” is not clearly defined and could be interpreted to require frequent, unnecessary retesting, especially in light of the variation in coal supplies from day to day in competitive wholesale power markets. A number of the commenters recommended that retesting be limited to changes in coal rank or classification (e.g., changing from bituminous coal to sub-bituminous coal). EPA has incorporated the commenters' suggestion into the final rule. Section 75.81(d)(4) of the final rule clarifies what constitutes a “change in fuel supply” that will trigger LME retesting. If a unit switches to a different rank of coal as the primary fuel for the unit, in-between the scheduled LME retests (where coal rank is defined by ASTM D388-99), an additional LME retest is required within 720 operating hours of the change. The results of this retest are then applied retrospectively back to the date and hour of the fuel switch. The four principal coal ranks are anthracitic, bituminous, subbituminous, and lignitic. The ranks of anthracite coal refuse (culm) and bituminous coal refuse (gob) are considered to be anthracitic and bituminous, respectively.

Equation 1 in § 75.81(c )(2), which is used to demonstrate that a unit qualifies as a Hg low mass emissions unit, conservatively estimates the unit's potential annual Hg emissions by assuming that it operates at the maximum potential flow rate for 8,760 hours per year. One commenter requested that EPA consider modifying Equation 1 to conditionally allow a number of hours less than 8,760 to be used in the calculations, the condition being that there is a Federally-enforceable permit provision in place, limiting the unit's annual operating hours. EPA has incorporated this suggestion into the final rule. The term “8,760” in Equation 1 has been replaced with “N”, which will either be 8,760 or the maximum number of operating hours per year allowed by the unit's Federally-enforceable operating permit (if less than 8,760). If the operating permit restricts the unit's annual heat input but not the number of annual unit operating hours, the owner or operator may divide the allowable annual heat input (mmBtu) by the design rated heat input capacity of the unit (mmBtu/hr) to determine the value of “N”.

Finally, no comments were received on the proposal to require that the Hg emission testing for initial certification of a low mass emission unit be done no more than 1 year prior to the applicable compliance date. Therefore, this provision has been finalized, as proposed. For units subject to the Clean Air Mercury Regulation (CAMR), the certification deadline is January 1, 2009. In view of this, only those Hg emission tests of candidate low mass emission units that are performed on and after January 1, 2008 will be accepted for initial certification.

3. Harmonization of Subpart I With Other Proposed Rule Revisions

Background

Subpart I of Part 75 also contains a recordkeeping and reporting section (§ 75.84). which, for the most part, 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.

To make Subpart I consistent with the proposed revisions to the monitoring plan, recordkeeping, notification, and reporting sections of Part 75, EPA proposed to make a number of minor adjustments to the text of §§ 75.84(c)(3), (e)(1), (e)(2), and (f)(1).

Summary of Rule Changes

No adverse comments were received. These provisions have been finalized, as proposed.

H. Appendix A

1. CO

2

Span Values

Background

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

2

spans less than 6.0 percent CO

2

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

2

span value mirrors a similar provision in Section 2.1.3 for O

2

span values.

Summary of Rule Changes

No adverse comments were received. This provision has been finalized, as proposed.

2. Protocol Gas Audit Program

Background

EPA is responsible for implementing air quality programs that rely heavily on the accuracy of calibration gas standards. 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. One notable result of these audits was a steady, significant reduction in the failure rate of the audited gas cylinders, from about 27% in 1992 down to 5% in 1996. The annual audits were discontinued after 1996. Then, in 2003, EPA conducted a “surprise” audit of 14 national specialty gas producers and found that the failure rate had risen to 11%.

In view of this, EPA proposed to establish a Protocol Gas Verification Program (PGVP) and would require that EPA Protocol Gases being used for 40 CFR Part 75 purposes be obtained from specialty gas producers who participate in the PGVP. As proposed, the rule would allow only program participants to market their gas standards as “EPA Protocol Gases.” EPA proposed to maintain a web site, listing the PGVP participants and the audit results, in order to provide calibration gas users with detailed information about the quality of EPA Protocol Gases.

EPA also proposed to: (1) Add a definition of “specialty gas producer” to § 72.2; (2) delete several calibration gas standards and reference materials from section 5.1 of appendix A (believing them to be prohibitively expensive and not used in practice by Part 75 sources); (3) remove from § 72.2 the corresponding definitions of the deleted calibration gas standards; and (4) consolidate the remaining calibration gas standards under section 5.1 of appendix A.

Finally, EPA requested 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 other EPA Protocol gases to be within 2 percent of the certified tag values.

Summary of Rule Changes

Only one organization commented on the proposed protocol gas verification program (PGVP). The commenter stated that a transition period is needed to implement the program. Sources need time to communicate with their gas vendors regarding their participation in the PGVP. The commenter further asserted that the PGVP would be disruptive and costly, both in the short-term and in the long-term, and that the affected sources would bear the brunt of the cost impact.

EPA agrees with the commenter regarding the need for a transition period. The final rule amends section 5.1.4 (c) to have the Protocol Gas Verification Program (PGVP) take effect on January 1, 2009. As the commenter has stated, the costs of the PGVP will be borne by the Part 75 sources using the calibration gases, and the Agency notes that these minimal costs ($5 to $10 added to a $500 to $1,000 cylinder) will be offset by the savings generated by fewer failed calibration error tests, linearity checks, and relative accuracy test audits.

3. Requirements for Air Emission Testing Bodies

Background

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. In view of this, EPA proposed to 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.

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

X

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.

EPA also proposed to incorporate ASTM Method D7036-04 by reference in § 75.6(a)(45), and to add a definition of “Air Emission Testing Body” to § 72.2.

Summary of Rule Changes

The amendments to Section 6.1.2 of Appendix A, Section 2.1 of Appendix E, and to Section 1 of Appendix B, requiring AETBs to conform to ASTM D7036-04, have been finalized, as proposed. Two commenters strongly supported the proposed revisions. However, several others objected to them, believing they would be costly and burdensome, without producing any noticeable improvement in data quality. EPA does not agree with these commenters, for the following reasons.

The experience of the State and Federal regulators in the ASTM work group indicates that implementation of the ASTM Practice will result in improved data quality. EPA believes the evidence is abundant that unqualified, under-trained and inexperienced testers are often deployed on testing projects. The Agency has had experiences with tests that have been invalidated or called into question due to poor performance by testing contractors (see Docket Items OAR-2005-0132-0009, -0021, and -0035). Conformance with ASTM D7036-04 does not guarantee that every test will be performed properly. However, it will reduce the likelihood of problems. Furthermore, it provides a guideline for both regulatory agencies and affected sources to evaluate and select competent testing

firms. One of the cornerstones of the Practice is that AETBs must collect performance data on how well they plan and execute test projects. These data must be shared with regulators and clients upon request.

In response to claims that ASTM D7036-04 will significantly increase the cost and burden of Part 75 testing, EPA notes that no data were provided to support these claims. The ISO 17025 standard upon which the ASTM standard is based has been implemented in Europe for many years. Mark Elliot, Chairman of the Stack Testing Association (STA) of Great Britain, has provided the following information on the costs of their programs. Their certification program (for individuals) is called MCERTS.

• MCERTS testing fees: Level 1 $350; Level 2 $940

• Technical endorsements (1-4): $350 each

The Level 2 certification requires a personal interview with the applicant. Please note that according to Mr. Elliot, this program has been successfully implemented in the UK with no small companies going out of business and no complaints of being overly burdensome on industry. In fact, many large companies such as Mobil, Dow, Pfizer, and 3M are members of the STA and fully support the program because, according to Mr. Elliot, they believe it improves the quality of the data provided by testing companies. Even major UK utility companies such as Drax Power, Energy Power Resources, the Electricity Supply Board, PB Power, Scottish and Southern Energy, and Scottish Power participate in the program. And they do this voluntarily because they have found it to their benefit to do so.

There are several differences between the program described in the final rule and the UK program. First, the final rule does not require accreditation. The individual testing requirements in the rule are less expensive and less stringent than the UK program. In the US, The Source Evaluation Society is currently providing Qualified Individual testing. The fees are $155 for the first test (including a one-time $15 SES membership) and $89 for any subsequent tests taken during the same testing session). It should also be noted that ASTM D7036-04 does not require that every individual be tested. Only one “Qualified Individual” need be present on-site during a test. Therefore, even this minimal cost and burden is considerably less than the successful UK program.

The costs of coming into initial compliance with the ASTM D7036-04 standard depend on the current state of an AETB's quality program. Those that do not currently have an organized quality program will most likely incur greater costs than those who do. In any case, the burden will be no greater than that experienced by the UK companies who successfully went through the same process.

The main costs to comply with the ASTM D7036-04 standard are associated with taking a stack test QSTI (qualified stack test individual) competency exam, and developing or revising a quality assurance (QA) manual. A nationwide compliance cost estimate may be obtained using the following estimates:

• 450 stack test companies in U.S. (The number of private (external) stack test companies came from

www.epa.gov/ttn/emc/software.html#testfirm

. RMB Consulting, Inc. estimated 10 in-house utility RATA test teams in the U.S.);

• On average, 10 people per company (Source:

www.epa.gov/ttn/emc/software.html#testfirm

);

• QSTI exam (required by ASTM) costs $150 and must be taken every 5 years (Source: December 11, 2006 letter from the Source Evaluation Society in Docket OAR-2005-0132); and

• Roughly 1 QSTI is required for every 3 people in a stack test company.

Using these inputs, the Agency estimates the cost to comply with ASTM D7036-04 at about $100 per yr per company to cover the QSTI exam. There is also approximately a $4,000 one time cost per company, whether a large or small entity as defined by the Small Business Administration's (SBA) regulations at 13 CFR 121.201, to develop a QA manual (estimate provided by Air Tech, see Docket Item # EPA-HQ-OAR-2005-0132-0093). However, the costs will be borne by the Part 75 sources using the air emission testing bodies, and the Agency notes that these costs will be offset by the savings generated by fewer failed or incorrectly performed relative accuracy test audits, and fewer repeat tests required. Therefore, the effect of this revision is to actually relieve a regulatory burden on these entities.

Regarding the issue of the financial impact on smaller companies and the request to provide funds to these companies, EPA notes that small stack test companies were represented on the ASTM work group. At least one small stack test company (3 people) has already complied with ASTM D7036-04, is supportive of the requirement, and expects to actually realize an increase in business because of their compliance with ASTM D7036-04. As stated in another response, the costs to comply with ASTM D7036-04 are reasonable. Similar requirements have been successfully implemented for many years in the UK with no small companies going out of business and no complaints of being overly burdensome on industry. EPA does not expect to provide funds to support small stack test companies in meeting the requirements of ASTM D7036-04.

EPA notes that virtually the same program has been in place in Europe for several years and is functioning very well with the support of stack testers, the government, and industry. The ASTM standard is actually less stringent in some areas than the European program. Based on this extensive experience in Europe, EPA believes that this program can be successfully implemented here in the U.S. with very little additional burden. In summary, there is an abundance of both data and experience showing that this program can be implemented without an unreasonable burden, and also (according to UK industry participants) that it will improve the quality of data.

Two commenters asserted that the existing infrastructure is not adequate for testers to comply with the ASTM method. EPA disagrees with these claims. The Source Evaluation Society is currently offering qualification exams in several areas. The commenters may be concerned that the SES website used to state that their exams may not specifically satisfy the requirements of the ASTM Practice (because they were not developed specifically for that purpose). However, SES has updated the wording on their Web site to say that their qualification exams do meet the exam requirement of the ASTM Practice. The Stack Testing Accreditation Council (STAC) also recognizes that not only does the SES program meet the requirements of the ASTM standard—it actually exceeds them. It requires more experience than the ASTM standard and also requires letters of recommendation. Both EPA and STAC accept an SES certification as meeting the external testing and experience requirements of the ASTM Practice.

If an external QSTI test is not available to a company, an internal test may be used to meet the requirements of ASTM D7036-04 until an external test becomes available. EPA is aware of at least one large stack test company that has developed a training module for mercury methods meeting the requirements of the ASTM D7036-04, and has trained and tested their people according to the internal qualification exam provision of ASTM D7036-04. When a third party test becomes

available, this company has indicated that they will re-certify their people according to the requirements of ASTM D7036-04. The Source Evaluation Society is reviewing steps to improve and expand the QSTI examination process.

Four commenters asked EPA to clarify how compliance with ASTM D7036-04 would be determined. Section 6.1.2 in Appendix A of the final rule specifically states that there are two ways an AETB can certify compliance: (1) A certificate of accreditation, or (2) a letter of certification signed by senior management. The latter option is similar to the way major sources certify compliance with their Title V permits. However, AETBs are under much more direct regulatory scrutiny than a Title V source. Every state has a field test observer program. In the case of one large stack testing company, Clean Air Engineering, about half of their compliance tests are directly observed by state regulators. This oversight provides an on-going check of whether an AETB remains in conformance. In co-operation with the New Jersey DEP, a standardized state observer checklist is being developed that will facilitate incorporating state observer assessments into the ASTM process.

EPA expects to treat non-compliance with this standard in the same way it treats noncompliance with any other standard—using its enforcement discretion. EPA does not anticipate invalidating test results because of minor infractions. The proper way to deal with these issues, if either the regulatory authority or the client discovers them, is to notify the AETB that a problem has been found. The AETB is then obligated to initiate a corrective action to address the problem. This becomes part of the AETB's Performance Data required by the Practice. The Agency recommends that the client also ask the AETB to report back on what corrective actions were taken. In the case of serious infractions, EPA may exercise the same authority it has always had to reject the test.

EPA encounters deviations in test methodology routinely in reviewing stack test reports. Minor deviations are noted and reported back to the source but the underlying results are accepted. Major deviations result in a rejection of the test. This situation is no different. This Practice should be treated much like a test method in this regard. Minor deviations may be of the type the commenters cite in their examples. Major deviations may include (for example) not having a Qualified Individual on-site, not having proper calibration records for the equipment used, or failing to follow through with corrective actions when required.

There will undoubtedly be some discussions between EPA, affected sources and AETB's as this program unfolds that will help define the implementation of the Practice. But this is the case with every new rule and standard.

There is always a balance in standard writing between being overly detailed and prescriptive and being too loose and flexible. The stakeholders involved in the consensus process of ASTM determined that the proper balance had been achieved. It is important to keep in mind that ASTM D7036-04 is essentially an international standard that has been used successfully in countries all over the world.

Three commenters requested that EPA provide a 1-2 year transition period after promulgation of the final rule, to allow AETBs sufficient time to conform to ASTM D7036-04. Particular concerns were expressed about the availability of Qualified Individuals (QIs) for Hg emission testing. EPA agrees that a transition period is appropriate, given the testers' relative unfamiliarity with Hg test methods. Therefore, the final rule gives AETBs until January 1, 2009 to comply with ASTM D7036-04.

A number of other comments were received on the proposed AETB certification program. These are addressed in detail in the Response to Comments (RTC) document.

4. Linearity Requirements for Dual-Span Applications

Background

In May 1999, EPA revised the linearity check provisions in Part 75, Appendix A, section 6.2, to exempt SO

2

and NO

X

span values of 30 ppm or less from performing linearity checks. Since the May 1999 revisions became effective, 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. In view of this, EPA proposed to 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

X

-diluent monitoring system.

Summary of Rule Changes

The proposed amendments to Section 6.2 of Appendix A have been finalized, without substantive change. At the request of one commenter, the final rule clarifies that the low-span linearity exemption applies to recertification as well as to initial certification and ongoing QA.

5. Dual Span Applications-Data Validation

Background

EPA proposed 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. Sections 2.1.1.5(b) and 2.1.2.5(b) of Appendix A have provided instructions for reporting SO

2

and NO

X

concentration data when the full-scale range of the monitor is exceeded. For single-range applications, reporting a value of 200 percent of the range has been required when a full-scale exceedance occurs. For dual range applications, if the low range is exceeded, no special reporting has been 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 sources have been required to report the maximum potential concentration (MPC).

Believing that 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” to be too general, the Agency proposed to 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 be reported until the expired high-range test is redone or until the data return to the low scale. Thus, the proposed revisions would clarify that when the low range is up-to-date on its QA tests but the high range is not, the QA status of each range is evaluated separately.

Summary of Rule Changes

No adverse comments were received. These provisions have been finalized, as proposed.

6. Cycle Time Test-Stability Criteria

Background

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 test is designed to determine how long it takes for a monitor to respond to step changes in gas concentration. Two calibration gases (zero- and high-level) are used for the test, which has both an upscale and a downscale component.

Section 6.4 has specified criteria for determining when a stable gas concentration 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 can become overly stringent and difficult to meet. In view of this, the Agency proposed to add alternative stability criteria to Section 6.4 of Appendix A. By the alternative criteria, an SO

2

or NO

X

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

2

or O

2

for 2 minutes.

Summary of Rule Changes

Substantive changes have been made to the cycle time test procedure, in response to comments received. The sequence of the test has been reversed,

i.e.

, it now begins with a stable reading of stack emissions and ends with a stable reading of calibration gas concentration (see section 2.6 of the Response to Comments document for further discussion). Commenters were generally supportive of the proposed alternative stability criteria, and these have been incorporated into the final rule. One commenter noted the absence of corresponding alternative stability criteria for Hg monitors. To correct this apparent oversight, the final rule includes an alternative specification of 0.5 μg/m

3

for Hg CEMS. The same commenter also expressed concerns about temporal variations in stack gas concentration (particularly for Hg) that can make it difficult to meet the stability criteria, and recommended that the order of the cycle time test be reversed,

i.e.

, begin the test by measuring stack gas emissions and then inject the calibration gas. EPA agrees with this comment and has revised the cycle time test procedure and Figure 6 in Appendix A accordingly. EPA believes this change in the test procedure (which is closer to the way in which the test was originally presented in the January 1993 rule) gives a more accurate indication of the monitor's true response time and will help to prevent “false positive” test failures.

EPA has also revised the reporting requirement (in Appendix A § 6.4) for cycle time tests of dual range monitors in light of the transition to the revised XML format. The change requires that cycle time for both ranges of a component be reported separately (consistent with the reporting of other component level tests for CEMS), rather than only reporting the results from the range with the longer cycle time. This change is consistent with the proposed changes that required reporting of certain test at the component level rather than at a system/component level, which overall reduces redundant reporting of test data from shared components. No adverse comments were received on those similar proposed changes. This revision was necessary for consistency with those other proposed changes which EPA is finalizing.

7. System Integrity and Linearity Checks of Hg CEMS

Background

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, has been 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 has been provided. EPA proposed to restructure paragraph (3) of Section 3.2, to add the necessary mathematical procedure.

Believing that 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), the Agency also proposed to make the linearity and system integrity check specifications for Hg monitors the same,

i.e.

, 5.0 percent of the span value, with an alternative specification to 0.6 μg/m

3

absolute difference between the reference gas value and the monitor response.

Summary of Rule Changes

In the final rule, the performance specifications for the linearity checks and system integrity checks of Hg monitors have been made the same, but the proposed 5.0 percent of span criterion (with an alternative specification of 0.6 μg/m

3

) has not been adopted. The commenters did not take issue with the proposal to equalize the performance specifications for the two QA tests, but several commenters objected to the proposed values of the specifications, citing a lack of supporting data to demonstrate that the specifications are achievable. Two commenters favored setting both specifications at the existing values for the linearity check,

i.e.

, 10.0 percent of the reference gas value, with an alternative specification of 1.0 μg/m

3

.

In response to these comments, EPA analyzed data from two recent field studies in which elemental and oxidized Hg calibration gases were injected into commercially-available Hg CEMS, at different concentration levels (low, mid, high). Based on the results of the data analysis, the Agency has concluded that equalizing the performance specifications for linearity checks and system integrity checks of Hg monitors at 10.0 percent of the reference gas value, with an alternate specification of 0.8 μg/m

3

absolute difference is appropriate, and the final rule incorporates these specifications.

A total of 97 data points from the two field studies were analyzed. Data recorded during known periods of probe malfunction and excessive analyzer drift were excluded from the analysis. Eighteen of the 97 data points analyzed were elemental Hg injections, and the rest were oxidized Hg injections. Each gas injection was evaluated on a pass/fail basis against six candidate sets of performance specifications. These were: (1) The proposed performance specifications,

i.e.

, 5.0 percent of span, with an alternative specification of 0.6 μg/m

3

; (2) the existing linearity specifications,

i.e.

, 10.0 percent of the reference gas value, with alternative specification of 1.0 μ/m

3

; (3) the existing system integrity specification,

i.e.

, 5.0 percent of span, with no alternative specification; (4) 5.0 percent of span, with an alternative specification of 0.8 μg/m

3

; (5) 5.0 percent of span, with an alternative specification of 1.0 μg/m

3

; and (6) 10.0 percent of the reference gas value, with alternative specification of 0.8 μg/m

3

. For each set of performance specifications, the pass rate of the 97 gas

injections was determined. The two highest pass rates (96.9% and 95.9%) were attained with sets (2) and (5), respectively, which have the widest alternative specification of 1.0 μg/m

3

. Similarly high pass rates (93.8% and 94.8%) were also attained with sets (4) and (6), both of which have an alternative specification of 0.8 μg/m

3

. The lowest pass rates (85.5% and 75.3%) were attained with sets (1) and (3), the proposed performance specifications and the existing system integrity check specification.

From these results, EPA concludes, on the one hand, that both the proposed performance specifications (set 1) and existing system integrity check specifications (set 3) may be too stringent. On the other hand, very high pass rates were achieved with the four sets having the wider alternate specifications of 1.0 μg/m

3

and 0.8 μg/m

3

,

i.e.

, sets (2), (5), (4), and (6). For these four sets, it seems to make little or no difference whether the main specification is 5.0 percent of span or 10.0 percent of the reference gas value. In view of these considerations, EPA has selected the main specification for the system integrity and linearity checks to be 10.0 percent of the reference gas value, and the alternative specification to be the more stringent value of 0.8 μg/m

3

. These values have been incorporated into paragraph (3) of Section 3.2 in Appendix A.

8. Correction of Hg Calibration Gas Concentrations for Moisture

Background

When calibration error tests and linearity checks of SO

2

, NO

X

, 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 is sometimes added to the calibration gas. This creates a potential source of error in the calculations. In view of this, EPA proposed 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. The proposed revisions would also require the calibration gas concentration to be converted to a dry basis for purposes of performing the calibration error calculations.

The Agency also proposed to add parallel language 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.

Summary of Rule Changes

No comments were received on the proposal. Therefore, the provisions have been finalized, but there is one notable change. The proposed rule inappropriately limited the requirement to account for added moisture in the calibration gas to dry-basis Hg CEMS. In the final rule text, this restriction has been removed. This is simply a technical correction of a misstatement in the proposal.

9. Correction of Cross-References

Background

EPA proposed to 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 referred 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. Finally, corrections to sections 6.5.6(b)(3) and 6.5.6.3 of Appendix A were proposed, changing references to Section 3.2 of Performance Specification No. 2 (PS2) to Section 8.1.3, of PS2.

Summary of Rule Changes

No adverse comments were received. These corrections have been finalized, as proposed.

I. Appendix B

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

Background

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”. As written, this rule provision actually allows more than five years (20 calendar quarters) to elapse between 3-load flow RATAs. For instance, if successive 3-load flow RATAs are performed in the 1st quarter of 2002 and in the 4th quarter of 2007, this satisfies the “once every 5 consecutive calendar years” requirement, but there would be 23 calendar quarters between the two tests.

In light of this, EPA proposed 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 both the other 5-year testing requirements in Part 75 (i.e., for Appendix E and LME units) and the maximum allowable interval between successive accuracy tests of Appendix D fuel flowmeters.

EPA also proposed to revise the RATA grace period provisions in Section 2.3.3, by removing the method of determining the deadline for the next RATA after a grace period test from paragraph (c) of Section 2.3.3 and replacing it with a different method described in new paragraph (d).

Paragraph (d) proposed a change to the methodology for determining RATA deadlines, without changing the end result. The intent of paragraph (c) in Section 2.3.3 had 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. However, for infrequently operated units (e.g., many 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 proposed a simpler 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 two QA operating quarters after the quarter of the test, if the RATA results trigger a semiannual test frequency, and three QA operating quarters after the quarter of the test if the RATA qualifies for an annual test frequency. As proposed, there was one exception to these rules. Regardless of the number of QA operating quarters that have elapsed following the grace period test, the maximum allowable interval between a grace period RATA and the next RATA would be eight calendar quarters. This is consistent with Section 2.3.1.1(a) of Appendix B.

Finally, EPA proposed to amend paragraph (c ) of Section 2.3.3, to state that when a RATA is performed after the expiration of a grace period, the “clock” is reset, and the deadline for the next RATA is determined in the usual manner,

i.e.

, the next test would be due within two QA operating quarters (for semiannual frequency) or four QA operating quarters (for annual frequency), not to exceed eight calendar quarters.

Summary of Rule Changes

Commenters were supportive of the proposed amendments to the RATA grace period provisions, and no comments were received on the proposal to determine 3-load flow RATA deadlines on a calendar quarter basis. Therefore, these provisions have been finalized, as proposed.

2. RATA Requirement for Shared Components

Background

EPA proposed to 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

X

pollutant concentration monitor is a component of both a NO

X

concentration monitoring system and a NO

X

-diluent monitoring system. In such cases, the Agency proposed that if the NO

X

concentration system RATA is failed, both the NO

X

concentration monitoring system and the associated NO

X

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

Summary of Rule Changes

No adverse comments were received. This amendment has been finalized, as proposed.

3. AETB Requirements

Background

EPA proposed to amend Appendix B 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.

Summary of Rule Changes

No adverse comments were received. This provision has been finalized, as proposed.

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

Background

EPA proposed to 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

2

or NO

X

).

The proposed revisions to Section 2.1.1 of Appendix B would require that “sufficient” calibration error tests be performed on the low and high monitor ranges to validate the data recorded on each range, in accordance with Section 2.1.5 of Appendix B. EPA also proposed to add a new paragraph, (3), 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. Under proposed paragraph (3), when 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 expires, this would have no effect on the QA status of the other range.

Further, the Agency proposed to amend Section 2.2.3(e) of Appendix B to make it clear that “hands-off” linearity checks of both ranges of a dual-range analyzer are required whenever a linearity check on either range fails or is aborted (unless, of course, a particular range is exempted from linearity checks under Section 6.2 of Appendix A).

Summary of Rule Changes

These provisions have been finalized, as proposed. Two commenters did not understand why failure of a calibration error test or a linearity check on one scale of a dual-range analyzer should invalidate data on both ranges, and asked for EPA to more fully explain the technical basis for this requirement.

The requirement to perform calibration error tests or linearity checks on both scales of a dual-range analyzer to resolve an out-of-control period does not reflect a change in Agency policy. Rather, EPA's proposal intended to clarify the existing requirement that each range of a dual-range monitor must be known to be in-control in order to validate data from the monitor.

The final rule allows data to be considered valid from a particular measurement range that has passed a calibration error check when the calibration error test for the other measurement range has expired. In such instances, since there is no indication that the monitor is not functioning properly, but there is evidence that the measurement range being used is properly calibrated, EPA is allowing that range to be considered quality assured. However, whenever a monitor fails any required daily, quarterly, semi-annual or annual quality assurance test, regardless of range, EPA maintains that data from that monitor must be considered invalid until the required quality assurance tests are passed. A failed test on either range of a dual range monitor indicates a problem with the monitor's ability to accurately measure emissions. While it is possible that in some instances, the problem causing the failure of a test on one range does not affect the accuracy of the monitor's measurements on the other range, it is far from certain. Therefore, the Agency's firm position is that whenever a calibration error test or linearity check is failed on either measurement scale of a dual-range analyzer, it is necessary to calibrate both ranges following corrective actions (which usually involve adjustments to the monitor), to verify that the monitor is back in-control and is able to generate quality-assured data on both ranges.

5. Off-Line Calibration Error Tests

Background

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. In view of this, the Agency proposed to 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.

EPA proposed to revise paragraph (2) in Section 2.1.1.2 to state that sources may make limited use of off-line calibrations if the off-line calibration demonstration has been performed and passed. The proposed changes to 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.

Summary of Rule Changes

Numerous commenters objected to the proposed revisions to Section 2.1.5.1 of Appendix B. The commenters found the proposed rule language to be confusing

rather than clarifying, and several of them asserted that EPA appeared to be placing new restrictions on the use of off-line calibration error tests.

After careful consideration of these comments, EPA agrees that the proposed rule language, particularly the term “sequence of consecutive unit operating hours” can be misinterpreted. However, the Agency's intent was (and is) simply to clarify the existing procedures for using off-line calibrations to validate CEMS data. That is, a source desiring to use the off-line calibration provisions in paragraph (2) of Appendix B, section 2.1.5.1 must first pass the off-line calibration demonstration described in section 2.1.1.2. After successfully completing this demonstration, off-line calibrations may be used on a limited basis for data validation. In particular, off-line calibrations may be used to validate data for up to 26 consecutive unit operating hours following a passed on-line calibration error test.

The term “consecutive unit operating hours” does not mean consecutive clock hours. For example, two consecutive unit operating hours could be separated by several hours, days, weeks, etc., due to a unit outage. Each off-line calibration error test has the same prospective, 26 clock hour window of data validation as an on-line calibration error test.

Therefore, for a source that has passed the off-line calibration demonstration, EPA considers the data for a particular operating hour to be valid if there is: (1) A passed on-line calibration within the 26

unit operating

hours preceding that operating hour; and (2) a passed off-line calibration within the 26

clock

hours immediately preceding that operating hour. The Agency has revised the proposed rule language to clarify these requirements. For each hour of unit operation, these criteria will be used to evaluate each monitoring system's control status with respect to daily calibrations.

6. Weekly System Integrity Check—Data Validation

Background

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, due to an apparent oversight, Section 2.6 did not explain the consequences of either failing the test or failing to perform the test on schedule. In view of this, EPA proposed to add the following data validation rules for the weekly system integrity check to Section 2.6 of Appendix B: (a) If the test fails, it would trigger an out-of-control period until a subsequent system integrity check is passed; and (b) 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.

The Agency also proposed to correct a typographical error in Section 2.6 of Appendix B. The performance specification for the weekly system integrity check was incorrectly referenced as Section 3.2 (c)(3) of Appendix A. The correct citation is Appendix A, Section 3.2, paragraph (3)(iii).

Summary of Rule Changes

The revision has been finalized as proposed. Several commenters objected to the proposed data validation rules for weekly system integrity checks of Hg CEMS. Commenters expressed concern that the specified test frequency, i.e., once every 168 unit operating hours, will cause scheduling difficulties, due to the limited availability of qualified technicians and other factors. The commenters requested that EPA provide a grace period of 72 to 96 hours for this QA test, to minimize the possibility of data loss.

EPA does not agree with the commenters' assertions that the 168 operating hour requirement will be difficult to implement and that a grace period should be added. The number of operating hours since the last weekly system integrity check can (and should) be tracked by the data acquisition and handling system (DAHS). An alarm or prompt could be activated when the deadline for the next test is near (e.g., when 120 or 144 operating hours have elapsed since the last test).

EPA favors basing the interval between successive tests on operating hours rather than clock hours in a week, primarily for reasons of simplicity. The Agency acknowledges that this is distinctly different from the way in which the deadlines for RATAs and linearity checks are determined. For a RATA or linearity check, the deadline is always at the end of a calendar quarter. Grace periods are provided for these tests because the deadlines can pass while the unit is either off-line or experiencing operational abnormalities that prevent the monitors from being tested on time. Also, a limited number of RATA deadline extensions and linearity check exemptions are provided for “non-QA operating quarters”, i.e., calendar quarters in which the unit operates for < 168 hours.

However, the required frequency for the system integrity checks of a Hg CEMS is weekly, not quarterly. This is the only weekly QA test required by Part 75. Therefore, the existing “QA operating quarter” model and grace period scheme cannot be directly applied to the system integrity check. A new concept, perhaps a “QA operating week” would have to be introduced and an appropriate grace period determined. EPA considered this approach and decided against it, believing that it would unnecessarily complicate the process of QA status tracking for Hg CEMS.

The Agency believes that if the DAHS is programmed to track the number of unit operating hours since the last system integrity check and if an alert is provided to let plant personnel know when the test deadline is approaching, there will seldom, if ever be a missed test. Furthermore, the Agency believes that as experience is gained with Hg monitors, it may be possible to automate the weekly system integrity check so that during the 168th hour of operation since the last system integrity check, the check is automatically initiated by the DAHS computer system or other appropriate programmable logic controller (PLC) systems. Such automation would further reduce the probability of a missed test.

7. Correction of Hg Units of Measure—Figure 2

Background

EPA proposed to correct a minor error in the units of measure for Hg concentration in Figure 2 of Appendix B, changing the units of micrograms per dry standard cubic meter (μg/dscm) to micrograms per standard cubic meter (μg/scm). This change was proposed because not all Hg monitoring systems measure Hg concentration on a dry basis.

Summary of Rule Changes

No adverse comments were received. The proposed correction to Figure 2 has been made.

J. Appendix D

1. Update of Incorporation by Reference

Background

As previously noted, EPA proposed to update the list of test methods, sampling and analysis procedures, and other items that are incorporated by reference in § 75.6. As such, the proposed rule

included corresponding updates to the references in Appendix D.

EPA also proposed 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.

Summary of Rule Changes

These provisions have been finalized, as proposed. Note that in response to a comment, EPA has also incorporated by reference ASTM D5453-06, “Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and Engine Oil by Ultraviolet Fluorescence”

1

, and has added ASTM D5453-06 to the list of acceptable oil sampling methods in Section 2.2.5 of Appendix D (see section 2.7 of the Response to Comments document for further discussion). In addition, the equation for Hourly SO

2

Mass Emissions from the Combustion of all Fuels in Appendix D, section 3.5.1 has been revised to be consistent with the new XLM format. This change is considered to be insignificant and was made to be consistent with the proposed changes to harmonize the units of measure for reporting hourly mass emissions.

1

ASTM D5453-05 is no longer available. EPA is thus adding ASTM D5453-06, the version currently available. EPA considers this a minor ministerial correction.

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

Background

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

2

mass emissions using a default SO

2

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

2

emission rate, the owner or operator must document 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, the rule has required that 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, the rule has required each one to meet the 0.5 gr/100 scf total sulfur limit.

Many suppliers of natural gas regularly sample the total sulfur content of the gas (in many cases, daily) and 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 asked whether the gas would be disqualified from using the 0.0006 lb/mmBtu SO

2

emission rate if the total sulfur content of one of these daily samples exceeded 0.5 gr/100 scf. EPA has been handling these requests individually, on a case-by-case basis. However, the Agency believes it will be more efficient to address the issue through rulemaking. In view of this, amendments to Sections 2.3.1.4(a)(2) and (e) of Appendix D were proposed.

For the initial documentation that the gas meets the 0.5 gr/100 scf total sulfur limit, the proposed revisions to Section 2.3.1.4(a)(2) would allow sources with at least 100 total sulfur samples from the previous 12 months to reduce the data to monthly averages. Then, 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

2

emission rate. Alternatively, if at least 98 percent of the 100 (or more) samples from the previous 12 months have a total sulfur content of 0.5 gr/100 scf or less, the fuel would qualify as pipeline natural gas.

The proposed 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 the results of at least 100 total sulfur samples from the past 12 months are obtained, 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 also proposed to clarify the gross calorific value (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, the Agency proposed to revise Section 2.3.4.1 to require that the 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 in the case where the owner or operator has elected to use the actual monthly GCV value in the emission calculations, revisions to Section 2.3.7(c) of Appendix D were proposed, requiring the monthly average GCV value to be applied starting from the latest date of any of the individual GCV samples used to calculate the monthly average. In the case where an assumed GCV value is used in the calculations (i.e., either a contract value or the highest monthly average from the previous year), the assumed value would continue to be used unless superseded by a higher monthly average GCV value.

Summary of Rule Changes

The provisions pertaining to documentation that a particular gaseous fuel qualifies as pipeline natural gas have been finalized, with only minor editorial changes. Regarding the proposed requirement to average the results of all GCV samples of natural gas taken in each calendar month, one commenter asked whether the monthly average would be used to back-calculate the heat input values for each day in that month.

The proposed revisions to Section 2.3.7(c) of Appendix D specified that when the option to use the actual monthly GCV in the calculations is selected and multiple samples are taken, each monthly average GCV would be applied prospectively, starting on the date of the last sample taken during the month. However, in light of the commenter's question, EPA has reconsidered this approach. The final rule requires instead that each monthly GCV value be applied to every day in that month. The Agency believes that this approach provides a more representative estimate of the unit's true monthly heat input.

Note that the text of paragraph (b)(2) in section 2.3.7 has also been modified to address the new alternative methodology for making annual assessments of the sulfur content of natural gas.

3. Requirement to Split Oil Samples

Background

For affected units that combust fuel oil and use the Appendix D

methodology to quantify SO

2

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 density of the oil (as applicable). 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.

Believing that the requirement to split and maintain oil samples should only apply to samples that are taken at the affected facility, EPA proposed to revise Section 2.2.5 of Appendix D to limit this requirement to samples that are taken on-site. If this proposed amendment were finalized, sources electing to sample each fuel lot would no longer be required to split and maintain oil samples in cases where the samples are taken off-site, from the fuel supplier's storage container.

Summary of Rule Changes

No adverse comments were received. This provision has been finalized, as proposed.

K. Appendix E

1. AETB Requirements

Background

EPA proposed 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 a LME unit, would have to conform to ASTM D7036-04.

Summary of Rule Changes

No adverse comments were received. This provision has been finalized, as proposed.

2. Reporting Data When the Correlation Curve Expires

Background

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

X

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

X

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. However, the appropriate missing data procedure to follow when a correlation curve expires has been conspicuously absent from Section 2.5 of Appendix E. To address this deficiency, EPA proposed to add a new Section, 2.5.2.4, to Appendix E, requiring the fuel-specific maximum potential NO

X

emission rate (MER) to be reported, from the date and hour in which a baseline correlation curve expires until a new correlation curve is generated.

Summary of Rule Changes

No adverse comments were received. This provision has been finalized, as proposed.

L. Appendix F

1. NO

X

Mass Calculations

Background

EPA proposed to revise the manner in which NO

X

mass data are collected under the XML format that will be required in 2009 as part of EPA's effort to re-engineer the Agency's data collection systems. To achieve this, the hourly NO

X

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

X

mass emission (lb), when the source transitions from EDR reporting format to the XML format.

To effect this, Equations F-24, and F-27 in Appendix F of Part 75 would have to be modified and Equation F-26 removed. However, since the current EDR reporting format will continue to be supported through 2008, these equations must remain in the rule until the transition to XML is complete. Therefore, EPA proposed to revise Section 8 of Appendix F by adding Equations F-24a for the reporting of hourly NO

X

mass emission rate (lb/hr) and Equation F-27a , for the calculation of cumulative NO

X

mass emissions. In 2009, the use of Equations F-24a and F-27a would become mandatory for all sources and Equations F-24 and F-27 would no longer be applicable.

EPA also proposed to revise Section 8.2 of Appendix F, by splitting it into two subsections, 8.2.1 and 8.2.2. Section 8.2 had described a procedure for calculating the NO

X

mass emission rate in lb/hr, when NO

X

mass emissions are determined using a NO

X

concentration monitoring system and a flow monitor. However, Section 8.2 simply cross-referenced other parts of the rule, rather than showing the actual equations used. To correct this, the Agency proposed to add Equation F-26a to subsection 8.2.1 and Equation F-26b to subsection 8.2.2, clearly showing how the NO

X

mass emission rate is calculated on a wet and dry basis, and to renumber Equation F-26 in Section 8.3 as Equation F-26c. Proposed Equations F-26a and F-26b have been used since 2002 by sources in the NO

X

Budget Program, and the equations have been represented in the EDR reporting instructions as Equations N-1 and N-2, respectively.

Summary of Rule Changes

No adverse comments were received. These provisions have been finalized, as proposed.

2. Use of the Diluent Cap

Background

EPA proposed to restrict the use of the diluent cap to NO

X

emission rate determinations. The original purpose for allowing the diluent cap to be used was to keep calculated NO

X

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

2

or O

2

) concentration is close to the level in the ambient air. However, since 1999, Part 75 has allowed the diluent cap to be used for heat input rate calculations, CO

2

mass emission calculations, and calculation of hourly CO

2

concentration from measured O

2

concentrations, in addition to being used for NO

X

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

X

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

X

emission rate.

Summary of Rule Changes

No adverse comments were received. These provisions have been finalized, as proposed.

3. Negative Emission Values

Background

EPA proposed 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

X

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

2

value, EPA proposed to require 0.0% CO

2

to be reported as the average CO

2

value for that hour. Third, the Agency proposed 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.

Summary of Rule Changes

These provisions have been finalized, with one notable change. The final rule will 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 hourly heat input rate that is less than or equal to zero.

4. Calculation of Stack Gas Moisture Content

Background

EPA proposed to add Equation F-31 to a new Section 10 in Appendix F, to be used to calculate stack gas moisture values from wet and dry oxygen measurements, as described in Appendix A, Section 6.5.7(a). Sources have been using this equation for many years and it has been represented in the EDR reporting instructions as Equation M-1.

Summary of Rule Changes

No adverse comments were received. This provision has been finalized, as proposed.

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

Background

For units that use CEMS to measure the NO

X

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

2

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 has never specified how much fuel sampling data is required to develop a site-specific F-factor or how often the F-factor must be updated.

To address this issue, EPA proposed to 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.

Summary of Rule Changes

No adverse comments were received. These provisions have been finalized, as proposed.

6. Prorated F-Factors

Background

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

X

emission rate or unit heat input rate, Section 3.3.6.4 of Appendix F has required 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 has never specified how the total unit heat input and the fraction of the heat input contributed by each fuel are determined

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