BEFORE THE ADMINISTRATOR 

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

WASHINGTON, DC 

PETITION FOR ADMINISTRATIVE RECONSIDERATION 

OF THE FINAL RULE 

"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" 

73 FED. REG. 4321 (JANUARY 24, 2008) 

 Air Liquide America Specialty Gases LLC 

 2700 Post Oak Boulevard 

Suite 1800 

Houston, TX 77056 

 Petitioner 

 Lisa M. Jaeger 

Richard Alonso 

 Bracewell & Giuliani LLP 

 2000 K Street, NW 

 Suite 500 

 Washington, DC 20006 

 Attorneys for Petitioner 

 March 24, 2008
 -2- 

INTRODUCTION

Pursuant to § 307(d) of the Clean Air Act, 42 U.S.C. § 7607(d), § 553-557 of the Administrative 

Procedure Act and for the reasons set forth below, Air Liquide America Specialty Gases LLC

(Air Liquide) petitions the Administrator of the United States Environmental Protection Agency 

(EPA) to reconsider certain provisions of the "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" 73 Fed. Reg. 4312 (January 24, 2008). (CEMs Rule). 

Specifically, Air Liquide seeks reconsideration of provisions of the Final CEMs Rule related to 

implementation of Section 2.1.10 of the 1997 Traceability Protocol and/or the EPA Protocol Gas 

Verification Program (PGVP). 

Reconsideration of the rule is warranted for issues that are “of central relevance to the outcome 

of the rule,” which arose after the public comment period or could not be raised due to 

impracticability. 42 U.S.C. § 7607(d). 

SUMMARY OF PETITION 

Air Liquide, which combined its assets with those of Scott Specialty Gases in 2007, is a supplier 

of calibration gases that companies must utilize for compliance with the revised final CEMs 

Rule. Air Liquide is a "specialty gas producer" as defined in the final CEMs Rule, and must 

comply with and is directly affected by its provisions, including any amendments and 

reinterpretations of the EPA Traceability Protocol for Assay and Certification of Gaseous 

Calibration Standards (EPA Protocol). 

The period for public comment on EPA's proposed CEMs Rule closed on October 23, 2006, 

without publication for public notice and comment of the Draft PGVP or any materials providing 

even the most basic description of the PGVP. Therefore, as described in detail below, the 

grounds for the objections raised in this petition "arose after the period for public comment." 42 

U.S.C. § 7607(d). In addition, EPA did not identify or describe in the proposed CEMs rule the 

elements of the PGVP or its relationship to the EPA Protocol, thus making it impracticable for 

Air Liquide and other directly and indirectly affected parties to comment on the PGVP and on 

EPA's interpretation of Section 2.1.10 of the Traceability Protocol. 

The PGVP includes a number of significant, substantive deficiencies that are central to the 

operation of specific requirements of the CEMs rule. The deficiencies are so substantial as to 

render the PGVP as referenced in the final CEMs Rule arbitrary and capricious or otherwise 

contrary to law. 

Air Liquide urges EPA to grant this Petition for Reconsideration of the relevant provisions of the 

CEMs Rule in a supplemental administrative proceeding, and provide a forum for notice and 

comment on the PGVP and any other plans for implementing the related provisions in the CEMs 

Rule and newly interpreted provisions of the related Traceability Protocol. 
 -3- 

BASES FOR ADMINISTRATIVE RECONSIDERATION 

I. EPA FAILED TO PROVIDE ADEQUATE NOTICE OF AND OPPORTUNITY 

TO COMMENT ON SIGNIFICANT CHANGES TO ITS PROTOCOL GAS 

AUDIT PROGRAM, DIRECTLY AND INDIRECTLY AFFECTING 

REGULATED ENTITIES 

On August 22, 2006, EPA provided notice of and sought comment on proposed revisions to the 

40 CFR Part 75 Continuous Emission Monitoring rules applicable to several categories of 

stationary sources under EPA's Clean Air Act emission trading programs. The proposed changes 

modified existing requirements for sources affected by the NOx Budget Trading Program, the 

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

explained in the Preamble that the proposed modifications were part of an EPA “process of reengineering the data systems” that would enhance data collection, evaluation, quality assessment 

and reporting. 71 Fed. Reg. 49255 (August 22, 2006). 

As part of this CEMs rulemaking, EPA also proposed changes to provisions relating to 

calibration gases in Part 72 and Appendix A to Part 75. In the Preamble, EPA explained that the 

results of a performance audit in 2003 showed a higher failure rate of calibration gases from 

various suppliers.1

 71 Fed. Reg. 49268. To address this apparent declining performance, EPA 

decided to "require that EPA Protocol Gases being used for 40 CFR Part 75 purposes be obtained 

from those specialty gas producers who participate in the audit program." 71 Fed. Reg. 49268. 

EPA explained that protocol gas suppliers would bear the cost of the audit and EPA would 

publish audit results on a web site to provide information to purchasers about the quality of EPA 

Protocol Gas. 71 Fed. Reg. 49268. 

EPA proposed these relevant specific regulatory changes to Part 72.2 and Appendix A to Part 75: 

• The definition of "EPA protocol gas" would be amended to require that "vendors 

advertising certification with the EPA Traceability Protocol or distributing gases as 'EPA 

Protocol Gas' must participate in the EPA Protocol Gas Verification Program. Nonparticipating vendors may not use "EPA" in any form of advertising for these products, 

unless approved by the Administrator." 71 Fed. Reg. 49278-279. 

• "Specialty gas producer" would be defined under Part 72.2 as "an organization that 

prepares and analyzes compressed gas mixtures for use as calibration gases and that 

offers the mixtures for sale to end users or to third-party vendors for resale to end users." 

71 Fed. Reg. 49279. 

• "EPA Protocol Gas Verification Program" would be newly defined as: "the EPA Protocol 

Gas audit program described in Section 2.1.10 of the "EPA Traceability Protocol for 

Assay and Certification of Gaseous Calibration Standards," September 1997, EPA600/R-97/121 or such revised procedure as approved by the Administrator." 71 Fed. Reg. 

49279. 

 1

 As EPA has acknowledged, the 2003 audit results were flawed, due to mistakes by the 

analytic laboratory that led to test results from producers being changed several times. 
 -4- 

Section 2.1.10 of the 1997 Traceability Protocol states that that EPA will assess the accuracy of 

calibration standards certified under the protocol by conducting audits, and directs interested 

parties to the published results of past EPA audits.2

 Consistently throughout the proposed 

changes to the CEMs Rule, EPA made the 1997 Traceability Protocol, and specifically Section 

2.1.10, the touchstone of its rule revisions, including defining the PGVP as "the audit program 

described in Section 2.1.10" (§ 72.2, 71 Fed. Reg. 49279) and directing commenters to the 

Protocol: "A copy of EPA-600/R-97/121 is available from the National Technical Information 

Service, 5285 Port Royal Road, Springfield, VA, 703-605-6585 or http://www.ntis.gov, and from 

http://www.epa.gov/ttn/emc/news.html or http://www.epa.gov/appcdwww/tsb/index.html." 

Appendix 5.1.1(d); 71 Fed. Reg. 49299-300. 

Nowhere in the CEMs proposed rule did EPA indicate that a parallel effort to develop a separate 

PGVP had been underway. In fact, EPA had begun in 2002 a parallel, unpublished effort to 

extensively revamp the procedures that EPA would require to ensure the accuracy of protocol 

gas. Even where EPA preserved the ability to further develop the PGVP by defining it as the 

audit "or such revised procedure as approved by the Administrator," EPA never gave any 

indication that a revised procedure was well on its way to completion. The changed procedures 

directly affect both the producers and end users of specialty gases. 

EPA recognized that regulated producer and consumer entities would be affected by the further 

refinement of Section 2.1.10 and any other regulatory developments that would be put in place. 

See generally PGVP. But EPA did not inform parties required to comply with CEMs rules, 

including stationary source emitters and calibration gas suppliers, that their interests could be 

affected by the PGVP in the making. By the time of publication of the proposed CEMs rule on 

August 22, 2006, a significant body of materials had already been developed by EPA through a 

separate workgroup. EPA did not place those materials in the docket for the proposed CEMs 

Rule. The comment period closed on October 23, 2006. 

In February 2007, after the comment period closed on the CEMs rule, a commenter submitted 

adverse comments on the unpublished PGVP, and expressly requested that EPA place the 

comments in the CEMs Rule docket. EPA accepted the comments but noted that only one 

organization had submitted comments on the PGVP. See EPA Response to Comments 

Submitted by Scott Specialty Gases, OAR-2005-0132-0108.1) (RTC to Scott Specialty Gases).3

 

 2

 Section 2.1.10 states in full: "Periodically, the U.S. EPA will assess the accuracy of 

compressed gas calibration standards that have been assayed and certified according to its 

protocol. The accuracy of representative standards will be assessed by EPA audits. The audit 

results, identifying the specialty gas producers or other analytical laboratories that assayed and 

certified the standards, will be published as public information. A summary of EPA's audit 

results from 1992 to the present is available as a WordPerfect 6.1 file at EPA's Ambient 

Monitoring Technology Information Center (Internet Address: http://www.epa.gov/ttn). This 

document can be found in the Directory of TTNWeb Sites/AMTIC/Publications/ORD-NERL 

Documents." 

3

 EPA's description of those comments is in error. The comments related only to the 

published new regulatory requirement that effectively narrowed the field of gas suppliers, not to 
 -5- 

Of course, inclusion in the docket of the Comments by Scott Specialty Gases regarding specific 

elements of the PGVP, and of EPA's Response to Comments does not cure the fatal flaw in 

EPA's proceeding. EPA must provide notice in the Federal Register of its proposed actions; 

parties bear no obligation to search the docket for submissions by other parties that may signal 

the existence of additional Agency documents that may affect their rights and liabilities. 

EPA published the final CEMs Rule revisions on January 24, 2008. In the final rule, EPA 

adopted the changes to the relevant revisions as proposed, including the revised interpretation of 

"audit." Under the Clean Air Act (CAA), EPA is required to first publish a notice of proposed 

rule making and provide an opportunity for public comment when promulgating or revising its 

rules implementing certain provisions of the CAA. §§ 307(d). The Administrative Procedure 

Act similarly requires EPA to publish a notice of proposed rule making in the Federal Register. 5 

U.S.C. § 553(b). EPA also must provide terms or substance of the proposed rule or a description 

of the subjects and issues involved. 5 U.S.C. § 553(b)(3). The APA requires also that the 

Agency give interested persons an opportunity to participate in the rule making through public 

comment. 5 U.S.C. § 553(c). 

The fundamental obligation of an Agency to provide notice and comment to affected parties 

secures two critical rights to parties: the right to comment on the substance of a rule and the 

right to seek judicial review of final agency action. It is well established that exemptions to 

notice and comment are "narrowly construed and only reluctantly countenanced." American Fed. 

Govt. Employees v. Block, 655 F. 2d 1153 (D.C. Cir. 1981). Furthermore, these exemptions do 

not apply to agency action that "substantially alter[s] the rights or interests of regulated" parties. 

See e.g. American Hosp. Ass'n v. Bowen, 834 F.2d 1037 (D.C.Cir. 1987); Air Transport Assn. or 

America v. Dept. of Transportation, 900 F.2d 369 (D.C.Cir. 1990). Notice and comment is 

critical when an Agency interpretation of its authority diverges significantly from a past 

interpretation. Alaska Prof'l Hunters Ass'n v. FAA, 177 F.3d 1030, 1034 (D.C. Cir. 1999) 

("When an agency has given its regulation a definitive interpretation, and later significantly 

revises that interpretation, the agency has in effect amended its rule, which requires notice and 

comment."). 

Implementing the PGVP through a passing reference to the program in the CEMs Rule in no way 

satisfies EPA's fundamental obligations to ensure that affected parties have the opportunity to 

comment on the proposed rule and preserve their ability to seek judicial review. 

EPA has conducted the development of the PGVP in an ad-hoc fashion, through an informal 

EPA/industry working group. EPA's primary points of contact with regulated industry on the 

work group were two trade associations: the Institute of Clean Air Companies (ICAC) , the 

Electric Power Research Institute (EPRI), and two suppliers of calibration gas. By restricting its 

notice process in this way, EPA deprived sources that would be directly and indirectly affected 

by the new PGVP requirements of an opportunity to comment on all phases of the development 

of the program. 

 

the unpublished PGVP. See Comments of Council of Industrial Boiler Owners, OAR-2005-

0132-00063.1 
 -6- 

Further, the selected trade associations do not represent the interests of all industry participants, 

nor of all end users. In fact, in some cases, the industry representatives have asserted positions 

directly counter to those of Air Liquide and other producers of specialty gases. The interests of 

Air Liquide, other suppliers and non-represented end users have thereby been directly and 

perhaps negatively affected, without the opportunity for notice and comment. 

These impacts are significantly more egregious in this case, because the PGVP would impose the 

cost of the verification program on specialty gas producers, based on a disproportionately spread 

fee schedule, which is administered by the trade association rather than by a disinterested neutral 

third party. 

The PGVP is fundamentally so different from the Traceability Protocol that EPA must use notice 

and comment to effectuate this change. Since 1977, parties' adherence to Protocol standards has 

been verified through audits conducted by EPA pursuant to Section 2.1.10 of the Traceability 

Protocol. The Protocol is a technical standards document, and the "audit" is commonly 

understood as an objective, scientifically reliable methodology for assessing compliance with 

standards. In the CEMs Rule, EPA purported to continue that longstanding approach, when it 

defined the PGVP as the "audit" in the Traceability Protocol. EPA-600/R-97/121 at 2-1. 

Parties reading the CEMs rule could not possibly have contemplated that the unpublished PGVP 

is, by its own terms, expressly not an audit. Rather, it is a newly formed verification program 

that "will not provide end users with a scientifically defensible estimate of whether gases of 

acceptable quality can be purchased from a specific producer." PGVP Draft Final Version 

(February 2008). 

Clearly, EPA has taken a different path that so widely departs from the longstanding 

interpretation of "audit" in the Traceability Protocol that affected parties should have been 

notified of such a changed interpretation and been afforded – on the record – the opportunity to 

comment and preserve their right to challenge EPA's new interpretation. 

EPA's failure to provide notice and opportunity to comment to all potentially affected parties of, 

inter alia, EPA's changed interpretation of the Traceability Protocol audit, the new verification 

approach and elements of the PGVP, the anticipated interrelationship between the Protocol and 

the PGVP, and other aspects of the program, is a clear violation of EPA's obligation to provide 

notice and comment under the CAA and the APA. On this basis alone, EPA should grant 

Reconsideration of the relevant provisions of the CEMs rule, establish a docket for the PGVP 

and undertake an open, public notice and comment process to revise audit-related provisions of 

the CEMs Rule. 
 -7- 

II. THE PGVP AS REFERENCED IN THE CEMS RULE CONSTITUTES 

 ARBITRARY AND CAPRICIOUS AGENCY ACTION, IS UNSUPPORTED BY A 

 RECORD AND IS OTHERWISE CONTRARY TO LAW. 

The PGVP as currently drafted would not further EPA’s stated goals, would not provide any 

meaningful environmental benefits and is without a record to provide a rational basis for its 

various elements. EPA has failed to meet its legal obligation to justify its regulatory decisions 

with data, analysis and demonstrably rational decision-making. Motor Vehicle Manufacturers 

Ass'n v. State Farm Mutual Insurance Co., 463 U.S. 29, 43 (1983).

A. The PGVP would not meet EPA’s goal of ensuring a high quality of protocol gas to 

ensure monitoring compliance. 

The intent of the Traceability Protocol Audit and PGVP is to facilitate the availability of 

acceptable quality calibration gases for use in air emission monitoring systems around the 

country. The final test results are made public and EPA suggests that end users would be able to 

make informed decisions, which enable the selection of quality producers and products. PGVP 

at 2. By EPA's own admission, however, "the program will not collect enough samples from 

any one producer to be able to associate a failure or an acceptable audit result with the 

probability that a monitoring organization will receive a gas cylinder of unacceptable or 

acceptable quality." PGVP at 3. 

This insufficient sampling, standing alone, warrants reconsideration of the PGVP program. 

Given that the data being presented to these end users will, in effect, have no statistical 

significance and be truly unrepresentative, the effectiveness of the entire program is plainly and 

substantially undermined. The program creates the unavoidable risk of false negatives and false 

positives: unfairly labeling generally compliant producers based on unrepresentative sampling, 

and unjustly rewarding underperforming producers based on a few fortuitous samples. In the 

end, both scenarios run counterproductive to EPA's stated goals. 

Even accepting EPA's contention that testing results are significant enough to serve as a basis for 

appropriate product selection, the PGVP program would nonetheless not effect any meaningful 

change in the quality of EPA Protocol Gases and as a consequence, confer no net benefit to the 

environment. EPA asserts that beneficial market shifts may have occurred as a result of 

previous audits. However, historically little change in the market distribution for Protocol Gases 

has occurred and EPA’s assertion remains unsupported by any firm data. 

Under the current regulatory system, capable specialty gas producers already maintain EPA 

Protocol Gas at an extremely high level. For producers that may be underperforming under the 

current system, the PGVP only incentivizes poor performance. The PGVP program provides no 

mechanism for sanctions or potential disqualification as a result of poor performance in the audit. 

On the contrary, EPA proposes to provide technical assistance to specialty gas companies whose 

EPA Protocol Gases have biases that exceed the acceptance criteria. PGVP at 31. Therefore, 
 -8- 

under the PGVP as now structured, producers that have maintained EPA Protocol Gases below 

the acceptance criteria will effectively subsidize the operations of poor performing companies. 

In an effort to support the PGVP program, EPA contends that previous gas audits have impacted 

the purchasing decisions of end users and resulted in market shifts favoring better performing 

companies. EPA suggests that this market shift was either caused by, or resulted in, several 

smaller gas companies either merging or going out of business. The assumption here, 

presumably, is that end users turned to better performing companies, which resulted in a loss of 

market share for companies that could not meet acceptable performance criteria. From this 

standpoint then, previous audits could be viewed as an effective mechanism to ensure that end 

users are selecting better performing companies. 

The PGVP program, unlike what EPA contends resulted from previous audits, would not 

produce the intended market shifts. In fact, poor performing specialty gas companies, which 

prior to PGVP may have lost market share as a result of poor performance, would gain a 

competitive advantage under the program. The PGVP gives discretion to the analytical 

verification laboratory to give technical assistance to gas producers with differences that exceed 

the Part 75 accuracy acceptance criterion. PGVP at 31. In this way, companies that comply 

would be forced to contribute unquantifiable resources to companies that are unable to meet 

acceptance criteria or, more likely, have made a calculated business decision not to invest in the 

appropriate infrastructure with the knowledge that they can receive technical assistance from 

EPA. In either event, better performing companies will be penalized under the PGVP program 

and end users will be forced to make uncertain decisions about which specialty gas producers are 

best suited to provide quality products. Therefore, not only will the PGVP program result in no 

meaningful environmental benefits, but it may work counter to the EPA's stated goals by 

sustaining otherwise unviable producers. 

The lack of EPA oversight of and the administrative structure of the PGVP is also not rationally 

related to the goal of ensuring calibration gas quality. The PGVP vests primary administrative 

authority, including significant decision-making authority in ICAC, an industry trade association 

that represents some but not all industry participants, and that provides services only to its 

members for an annual membership fee. As a membership organization, ICAC does not 

represent the interests of all calibration gas producers, yet the PGVP does not guarantee 

representation of the views of non-ICAC members, nor of other affected industry participants. 

The broad authority of a non-neutral industry trade association, including vesting it with 

responsibility for communicating with all industry parties, is not a rational element for a program 

that EPA considers to be the mechanism for meeting Clean Air Act obligations to ensure 

monitoring accuracy and permit compliance. 

B. PGVP fees are assessed inequitably across the industry and are not justified by the 

achievement of stated environmental benefits. 

Maintaining multiple supplier production facilities is extremely beneficial to end users in terms 

of service, lead time, cost and security of supply. It also ensures higher quality product and 

monitoring. Under the PGVP, program fees are assessed against each individual production 
 -9- 

facility. This directly and disproportionately burdens companies with multiple locations without 

improving the quality of the audit data. 

EPA’s cost impact projections to producers and end users are not rational or supported by any 

record.4

 The PGVP program fees are unknown and have not been estimated. The program has 

no apparent limits on what can be charged to producers, no cost controls or cost accountability, 

and no cost recourse for the participants. In a Response to Comments, EPA estimates, without 

record support, "that the nationwide cost of the PGVP program will be approximately $100,000." 

RTC to Scott Specialty Gases at 2. It is unclear how this estimate relates to the estimate in the 

PGVP of an annual cost of $233,000. PGVP at 15. Abundantly clear, however, is that the real 

cost has not been assessed with any accuracy, given that "the details of the actual funding 

mechanism, equitability issues, any necessary cost controls, how surpluses/deficits will be 

handled, and financial auditing and reporting" have yet to be determined. RTC to Scott Specialty 

Gases at 2. In addition, the PGVP includes elements that render its "cost cap" a nullity, 

including, for example, permitting program administrators to estimate future costs and allowing 

for future unidentified "major changes" to the program. PGVP at 15. 

Regardless of the level of impact of compliance cost, that cost must correspond to some benefit 

or it lacks all rationality. Here, the PGVP will increase the cost of EPA Protocol Gases with no 

apparent benefit or value delivered to the end user. 

Given EPA’s failure to contain the cost of compliance or accurately assess its amount, EPA 

cannot reasonably impose these fees on producers without defensible, record support for the 

accuracy of its projections. In light of EPA’s failure to provide notice and comment by all 

potentially affected parties, including producers and non-utility end users not represented on the 

workgroup, a first-time imposition of unquantified fees is particularly indefensible. All parties 

impacted by fees should be given a full opportunity to comment on the program in a separate 

rulemaking, if only to help minimize the cost that is eventually passed through to consumers. 

C. EPA must evaluate and reasonably justify any rejection of reasonable alternatives 

to defining the audit as the PGVP. 

EPA has not evaluated and provided a reasonable explanation for its rejection of reasonable 

alternatives to the PGVP that would meet EPA’s stated objectives. Several alternatives to the 

PGVP verification approach would achieve EPA’s goal of ensuring consistently high standards 

in the supply of EPA protocol gas. Among these alternatives is the adoption of ISO 17025, 

which has measurable advantages over EPA’s chosen PGVP approach. Yet EPA has never 

 

4

 In addition, EPA may not have considered the costs of implementing the PGVP when it sought 

approval to implement the CEMs rule in its Information Collection Request (ICR) under the 

Paperwork Reduction Act (PRA), 44 U.S.C. §§ 3501 et seq. As presently formulated, the PGVP 

may also improperly augment EPA’s appropriation to carry out its duties under the Clean Air 

Act, in violation of the “miscellaneous receipts” statute. 31 U.S.C. §3302(b). 
 -10- 

offered a reasoned basis on the record for its rejection of that and other alternatives, rendering its 

selection of PGVP irrational. 

III. CONCLUSION 

EPA proposed several specific changes to CEM rules which improve the integrity of protocol 

gases and improved environmental protection through a supplier audit program. EPA failed to 

provide notice to all potentially affected parties with any reasonable specificity of its program 

changes then under discussion in an unpublished forum. Only after one commenter insisted on 

including in the CEMs rulemaking docket its comments on the unpublished draft PGVP program 

mentioned in the CEMs rule, was EPA compelled to respond to comments on the record on 

significant failings of the PGVP and its substantial departure from the existing longstanding 

audit program. 

EPA is faced here with a procedural violation that easily could be cured by establishing an 

official docket for the PGVP program, subjecting all relevant documents to public scrutiny, and 

providing notice and comment on its proposed program. EPA would thereby cure the affected 

parties’ inability to participate in the development of the draft PGVP, which, although it is 

mentioned in the CEMs Rule, was not described in the Rule or docketed in the CEMs 

rulemaking proceeding for full review. Controlling statutory and case law require this outcome. 

In an administrative proceeding on the record, EPA should address the significant substantive 

deficiencies of the PGVP, including those described in this Petition. As presently drafted, the 

PGVP constitutes illegal, arbitrary and capricious agency action, and its elements are not 

supported by an administrative record. Under the specific terms of the PGVP, EPA 

acknowledges that the program is not an audit. 

For all of the foregoing reasons, EPA should grant reconsideration of the relevant provisions of 

the CEMs rule to address the procedural and substantive failings of the PGVP in an orderly 

fashion consistent with its obligations under the Clean Air Act, Administrative Procedure Act 

and other applicable law. 
Thursday, 

January 24, 2008 

Part II 

Environmental 

Protection Agency 

40 CFR Parts 72 and 75 

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; Final Rule 


sroberts on PROD1PC70 with RULES
4312 Federal Register / Vol. 73, No. 16 / Thursday, January 24, 2008 / Rules and Regulations 

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, NOX 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 NOX 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, email 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 NOX

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 


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D. Missing Data Substitution 

E. Recordkeeping and Reporting 

F. Subpart H (NOX 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 reengineering the data systems associated 

with the collection and processing of 

emissions, monitoring plan, quality 

assurance, and certification data. The reengineering 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 recentlypublished 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 


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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 SO2, NOX, and diluent 

gas (CO2 and O2) calibration gas 

standards. 

For the SO2, NOX, CO2, and O2

compressed gas standards used in Part 

75 applications, ‘‘NIST traceability’’

means that the calibration gases have 

been prepared according to the EPAapproved 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 SO2, NOX, CO2, and 

O2 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 qualityassurance 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 CAMRaffected 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 


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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 SO2 emission 

rates for fuel oil combustion, in lieu of 

using the ‘‘generic’’ default SO2

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, SO2 emissions data to be reported 

from oil-burning LME units. As 

proposed, the site-specific default SO2

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 fueland-unit-specific default NOX 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 qualityassured 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 SO2 and 

consider providing a similar, more 

reasonable site-specific alternative to 

reporting the generic NOX 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 

NOX 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% 

H2O 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 NOX 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 sitespecific 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 

SO2 mass emission rate, by allowing 

Equation F–23 to be used whether or not 

the unit has an SO2 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 

SO2 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 SO2 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. 


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5. Calculation of NOX Emission Rate—

LME Units 

Background 

EPA proposed to re-title 

§ 75.19(c)(4)(ii) as ‘‘NOX mass emissions 

and NOX emission rate’’ and to add a 

new subparagraph (D) to § 75.19 

(c)(4)(ii), providing instructions for 

determining quarterly and cumulative 

NOX emission rates for a LME unit. The 

NOX emission rate for each hour (lb/ 

mmBtu) would simply be the 

appropriate generic or unit-specific 

default NOX emission rate defined in 

the monitoring plan for the type of fuel 

being combusted and (if applicable) the 

NOX emission control status. Then, the 

Agency proposed that the quarterly NOX

emission rate would be determined by 

averaging all of the hourly NOX

emission rates and the cumulative (yearto-date) NOX 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 NOX

Emission Rate When Using Bypass 

Stacks 

Background 

Revisions to § 75.17(d)(2) were 

proposed that would allow a maximum 

controlled NOX emission rate (MCR) to 

be reported instead of the maximum 

potential NOX 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 

NOX 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 NOX

concentration (MEC) would be used 

instead of the maximum potential NOX

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 NOX 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 NOX

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 fuelspecific NOX 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 


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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/m3 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 sorbentbased 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/m3 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/m3. 

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 


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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 SO2 or NOX

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 SO2 or NOX concentration (or 

maximum controlled NOX 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 SO2 or NOX concentration 

(MPC) or the maximum potential NOX

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 SO2 and NOX

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 NOX emission 

rate, the replacement value for the MER 

would be the greater of: (a) The 

maximum controlled NOX emission rate 

(MCR); or (b) 1.25 times the maximum 

controlled value in the standard missing 

data lookback period. The NOX MCR 

would be calculated in the same manner 

as the NOX 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 


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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, reengineered 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 NOX 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 reengineered 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 ‘‘longterm 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 recommences 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: 


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(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 reengineering 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 


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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 (NOX Mass Emissions) 

1. Subpart H Diluent Monitoring 

Systems 

Background 

For coal-fired Subpart H units that 

calculate NOX mass emissions as the 

product of NOX concentration and flow 

rate and are required to monitor and 

report the unit heat input, § 75.71(a)(2) 

requires the installation of an ‘‘O2 or 

CO2 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 ‘‘O2 or CO2

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 NOX Mass Methodology 

Background 

EPA proposed to revise § 75.72 to 

require that only one NOX mass 

emissions methodology be identified in 

the monitoring plan at any given time, 

and to disallow the designation of 

primary and secondary NOX mass 

calculation methodologies. EPA believes 

that one methodology for NOX 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 NOX data when 

the diluent component of the NOX

emission rate system is out-of-control, 

that source should choose the NOX

concentration times flow rate 

calculation method as the NOX mass 

calculation methodology. This would 

require a NOX concentration system to 

be identified in the monitoring plan, in 

addition to the NOX emission rate 

system. The NOX concentration system 

would be used only to determine NOX

mass emissions, and the NOX emission 

rate system would be used only to meet 

the ARP requirement to report NOX 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 inseason 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 


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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 preseason 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 

NOX 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 preseason (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. Yearround 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. 


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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 NOX

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 

NOX 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 


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(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 

SO2 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, inbetween 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 Federallyenforceable 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 


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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. CO2 Span Values 

Background 

EPA proposed to revise Section 2.1.3 

of Appendix A, to allow the use of CO2

spans less than 6.0 percent CO2 if a 

technical justification is provided in the 

hardcopy monitoring plan. This added 

flexibility in the CO2 span value mirrors 

a similar provision in Section 2.1.3 for 

O2 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 shortterm 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 improperlyperformed 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, 

NOX emission tests of Appendix E and 

LME units, or Hg emission tests of lowemitting 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 


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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 


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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 cooperation 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 SO2

and NOX 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 

NOX-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 qualityassured (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 SO2 and NOX

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 lowrange 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 outof-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. 


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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 SO2 or NOX 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% CO2 or O2 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/m3 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/m3

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/m3) 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/m3. 

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/m3 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/m3; (2) the existing linearity 

specifications, i.e., 10.0 percent of the 

reference gas value, with alternative 

specification of 1.0 μ/m3; (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/m3 ; (5) 5.0 percent of span, with an 

alternative specification of 1.0 μg/m3; 

and (6) 10.0 percent of the reference gas 

value, with alternative specification of 

0.8 μg/m3. For each set of performance 

specifications, the pass rate of the 97 gas 


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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/m3. 

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/m3. 

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/m3 and 0.8 μg/ 

m3, 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/ 

m3. 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 SO2, NOX, and 

diluent gas monitors are performed, 

EPA protocol gases are used. The 

protocol gases are essentially moisturefree. 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. 


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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 

NOX pollutant concentration monitor is 

a component of both a NOX

concentration monitoring system and a 

NOX-diluent monitoring system. In such 

cases, the Agency proposed that if the 

NOX concentration system RATA is 

failed, both the NOX concentration 

monitoring system and the associated 

NOX-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 qualityassurance 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., SO2 or NOX). 

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, semiannual 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 offline 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 wellunderstood 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 


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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 online 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 NISTtraceable 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 


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1ASTM D5453–05 is no longer available. EPA is 

thus adding ASTM D5453–06, the version currently 

available. EPA considers this a minor ministerial 

correction. 

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 SO2 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. 

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 SO2 mass 

emissions using a default SO2 emission 

rate of 0.0006 lb/mmBtu. To qualify to 

use this SO2 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 SO2 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 

SO2 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 


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methodology to quantify SO2 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 NOX 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 NOX 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 NOX 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. NOX Mass Calculations 

Background 

EPA proposed to revise the manner in 

which NOX 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 NOX mass emission rate (lb/hr) 

would be reported instead of hourly 

NOX 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 NOX mass emission rate (lb/hr) 

and Equation F–27a , for the calculation 

of cumulative NOX 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 NOX mass emission rate 

in lb/hr, when NOX mass emissions are 

determined using a NOX concentration 

monitoring system and a flow monitor. 

However, Section 8.2 simply crossreferenced 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 NOX 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 NOX 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 NOX emission rate 

determinations. The original purpose for 

allowing the diluent cap to be used was 

to keep calculated NOX emission rates 

from approaching infinity during 

periods of unit startup and shutdown, 

when the diluent gas (CO2 or O2) 

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, 

CO2 mass emission calculations, and 

calculation of hourly CO2 concentration 

from measured O2 concentrations, in 

addition to being used for NOX 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 NOX 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 NOX emission rate. 

Summary of Rule Changes 

No adverse comments were received. 

These provisions have been finalized, as 

proposed. 


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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 NOX 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 CO2 value, EPA 

proposed to require 0.0% CO2 to be 

reported as the average CO2 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 NOX 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 CO2 generated per million 

Btu of heat input. The F-factor is fuelspecific. 

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 sitespecific 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, redetermination 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 NOX 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. 

Data from the CEMS cannot be used for 

this purpose because the prorated Ffactor must be known before the unit 

heat input rate can be calculated. 

To correct this situation, EPA 

proposed to revise the definition of ‘‘Xi’’

(the fraction of the total heat input 

derived from each fuel) in the Equation 

F–8 nomenclature. The proposed 

revision would require sources to 

determine Xi from the best available 

information on the quantity of each fuel 

combusted and its GCV value over a 

specified time period. The value of Xi

would be updated periodically, either 

hourly, daily, weekly, or monthly, and 

the prorated F-factor used in the 

emission calculations would be derived 

from the Xi values from the most recent 

update. The owner or operator would be 

required to document in the hard copy 

portion of the monitoring plan the 

method used to determine the Xi values. 

Summary of Rule Changes 

The revisions to Section 3.3.6.4 of 

Appendix F regarding the prorating of 

F-factors have been finalized, with only 

minor changes. However, several 

commenters requested that EPA 

consider allowing the use of the ‘‘worstcase’’ (i.e., highest) F-factor as an 

alternative to prorating, when 

combinations of fuels are co-fired. After 

careful consideration of these 

comments, EPA is persuaded by the 

commenters’ arguments in favor of this 

option and has decided to incorporate 

this suggestion into the final rule (see 

section 2.4 of the Response to 

Comments document). New Section 

3.3.6.5 of Appendix F allows sources 

that burn combinations of fuels listed in 

Table 1 of Appendix F to use the highest 

(‘‘worst-case’’) F-factor for any unit 

operating hour, in lieu of prorating the 

F-factor. Note that in view of the 

revisions to Section 3.3.6.4, Agency has 

deemed it necessary to modify the 

language in Section 3.3.6.3 of Appendix 

F. Administrative approval of the Ffactor is no longer required when 

combinations of fossil fuels with wood 

or bark are combusted, since F-factors 

for these fuels are listed in Table 1. 

Rather, revised Section 3.3.6.3 requires 

Administrative approval of the F-factor 

only when a fuel not listed in Table 1 

is co-fired with a fuel (or fuels) listed in 

the Table. 

7. Default F-Factors 

Background 

In recent years, petroleum coke and 

tires have begun to be used as primary 

or secondary fuels by a number of 

affected sources. In view of this, EPA 

proposed to add default F-factors for 

petroleum coke and tire-derived fuels to 

Table 1 in Section 3.3.5 of Appendix F. 

The proposed values were 9,832 dscf/ 

mmBtu for Fd and 1,853 scf CO2/mmBtu 

for Fc for petroleum coke and 10,261 

dscf/mmBtu for Fd and 1,803 scf CO2/ 

mmBtu for Fc for tire-derived fuels. The 

Agency also proposed F-factors of 9,819 

dscf/mmBtu (for Fd) and 1,840 scf CO2/ 

mmBtu (for Fc) for sub-bituminous coal. 

All of the proposed F-factors were 

calculated using Equations F–7a and F–

7b and representative composition and 

gross calorific value (GCV) data for each 

fuel. 


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Summary of Rule Changes 

These provisions have been finalized, 

with minor editorial changes. One 

commenter recommended that the 

proposed F-factor values be rounded off 

to the nearest multiple of 10, to be 

consistent with the other values in 

Table 1. EPA agrees with this comment 

and has rounded off the F-factors 

accordingly. 

8. Revisions to Equation F–23 

Background 

Consistent with the proposed changes 

to § 75.11(e), expanding the 

applicability of Equation F–23, EPA 

proposed to amend Section 7 of 

Appendix F (introductory text), and the 

Equation F–23 nomenclature. 

Summary of Rule Changes 

No adverse comments were received. 

These provisions have been finalized, as 

proposed. 

M. Appendix G 

Background 

Consistent with the changes to other 

parts of the rule, EPA proposed to 

update the current ASTM standards 

listed in Sections 2.1.2, 2.2.1, and 2.2.2, 

of Appendix G, citing the newer 

versions. 

Summary of Rule Changes 

No adverse comments were received. 

These provisions have been finalized, as 

proposed. 

N. Appendix K 

Background 

EPA proposed to addresses several 

issues regarding the use of sorbent trap 

monitoring systems for the 

measurement and reporting of Hg mass 

emissions. When this monitoring option 

is selected, paired sorbent traps are 

required to measure the effluent Hg 

concentration. If the two Hg 

concentrations measured by the paired 

traps meet the required relative 

deviation (RD) specification in 

Appendix K of Part 75, and if each trap 

individually meets certain other QA 

requirements of Appendix K, then the 

two Hg concentrations are averaged 

arithmetically and the average value is 

used to determine the Hg mass 

emissions in each hour of the data 

collection period. However, in cases 

where either or both of the traps fails to 

meet the acceptance criteria, § 75.15(h) 

and Table K–1 in Appendix K specify 

consequences of varying severity. In the 

months following promulgation of these 

rule provisions, EPA revisited them and 

concluded that some of the 

consequences were too lenient and 

others unnecessarily severe. The Agency 

therefore proposed to revise them to 

make them more consistent and 

equitable. 

Whenever one of the paired traps is 

accidentally lost, damaged, or broken 

and cannot be analyzed, § 75.15(h) has 

allowed the owner or operator to use the 

remaining trap to determine the Hg 

concentration for the data collection 

period, provided that the remaining trap 

meets all of the QA requirements of 

Appendix K. But no adjustment of the 

data has been required to compensate 

for the loss of one of the samples. In 

view of this, EPA proposed to revise 

§ 75.15(h) to require that the Hg 

concentration measured by the 

remaining valid trap be multiplied by a 

‘‘single trap adjustment factor’’ (STAF) 

of 1.222. The STAF represents the 

maximum amount by which the Hg 

concentration from the lost, damaged or 

broken trap could have exceeded the 

concentration measured by the valid 

trap and still met the 10% RD 

specification. 

The Agency also proposed to revise 

Table K–1 in Appendix K, to extend the 

use of the STAF to cases where one of 

the paired sorbent traps either: (a) fails 

a post-test leak check; (b) has excessive 

breakthrough in the second section; or 

(c) is unable to meet the required 

percent recovery of the third section 

elemental Hg spike. In all three of these 

cases, provided that the other trap meets 

all Appendix K requirements, rather 

than invalidating the sorbent trap 

system data for the entire collection 

period, the Hg concentration measured 

by the valid trap, multiplied by the 

STAF, could be used for Part 75 

reporting. 

Section 7.2.3 of Appendix K requires 

that for each hour of the data collection 

period, the ratio of the stack gas flow 

rate to the sample flow rate through 

each sorbent trap must be maintained 

within ±25 percent of the initial ratio 

established in the first hour of the data 

collection period. However, the rule has 

stated that when this criterion is not 

met, the appropriate consequences are 

to be determined on a ‘‘case-by-case’’

basis. EPA has reconsidered this 

approach and now believes that it 

allows for inconsistent application of 

the sorbent trap monitoring 

methodology. Therefore, the Agency 

proposed to revise Table K–1 to specify 

that a sample is invalidated if either: (a) 

More than 5 percent of the hourly ratios; 

or (b) more than 5 hourly ratios in the 

data collection period (whichever is less 

restrictive) fail to meet the ±25 percent 

acceptance criterion. Further, if only 

one of the paired traps is able to meet 

the specification, provided that it also 

meets the rest of the Appendix K QA 

criteria, the valid trap could be used for 

Part 75 reporting, if the STAF value of 

1.222 is applied to the measured Hg 

concentration. 

Appendix K has required data from a 

sorbent trap monitoring system to be 

invalidated whenever the relative 

deviation between the Hg 

concentrations measured by the paired 

traps is greater than 10 percent. EPA 

proposed to revise this requirement, to 

allow sources to report the higher of the 

two Hg concentrations measured by a 

pair of sorbent traps whenever the RD 

specification is not met, rather than 

invalidating the sorbent trap system 

data for the entire collection period. The 

Agency also proposed, for consistency 

with the proposed changes § 75.22(a), to 

revise Table K–1 to include an 

alternative relative deviation 

specification of 20 percent for paired 

sorbent traps, when low effluent 

concentrations of Hg (≤ 1 μg/m3) are 

encountered. 

EPA further proposed to add two new 

paragraphs, (k) and (l), to § 75.15. 

Proposed § 75.15(k) would have 

required that whenever the RATA of a 

sorbent trap system is performed, the 

sorbent traps used to collect the RATA 

run data must be the same size as the 

traps used for daily operation of the 

monitoring system. Likewise, the 

sorbent material must be the same type 

that is used for daily operation. 

Proposed § 75.15(l) would have required 

a diagnostic RATA of the sorbent trap 

system whenever either the size of the 

sorbent traps or the type of sorbent 

material was changed. Data from the 

modified sorbent trap system would not 

have been acceptable for Part 75 

reporting until the RATA is passed, 

with one exception, i.e., data collected 

during a successful diagnostic RATA 

test period could be reported as qualityassured. 

Finally, revisions to section 7.2.3 of 

Appendix K were proposed, requiring 

that the sample flow rate through a 

sorbent trap monitoring system must be 

zero when the unit is not operating. EPA 

believes this clarification is needed to 

prevent the system from sampling 

ambient air during periods when the 

combustion unit is off-line, which 

would artificially lower the Hg 

concentrations measured by the sorbent 

traps, resulting in under-reporting of Hg 

mass emissions. 

Summary of Rule Changes 

The commenters generally favored the 

proposal to add a 20 percent alternative 

relative deviation (RD) specification for 

sources with low Hg emissions (≤ 1.0 


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μg/m3). However, concerns were 

expressed that even a 20 percent RD 

specification might be difficult to meet 

when emissions are exceptionally low. 

For instance, following a flue gas 

desulfurization system, the Hg emission 

levels can be as low as 0.1 to 0.2 μg/m3. 

One commenter suggested that the 

allowable RD for low emitters should be 

either 20 percent or 0.03 μg/m3 absolute 

difference, whichever is less restrictive 

(see section 2.9.2 of the Response to 

Comments document). EPA agrees with 

this comment and has incorporated the 

0.03 μg/m3 alternative RD specification 

into both Appendix K (for sorbent trap 

monitoring systems), and § 75.22 (for 

the Ontario Hydro Method and EPA 

Method 29). 

The commenters were divided on the 

proposed single trap adjustment factor 

(STAF) provisions. Two commenters 

supported the proposed amendments 

and four others objected to them. Those 

objecting expressed concern that 

applying the proposed STAF value of 

1.222 in cases where one trap meets all 

of the QA requirements is unnecessarily 

punitive. Several of the commenters 

recommended that the STAF value 

should be 1.111, which would be 

consistent with the averaging that is 

performed when the results of both 

traps are available and would 

appropriately weight the results of the 

valid trap (see section 4.3 of the 

Response to Comments document for 

further discussion). After careful 

consideration of the comments, EPA has 

decided to incorporate the commenters’

suggestion regarding the value of the 

STAF. Therefore, the single-trap 

adjustment factor provisions have been 

finalized as proposed, except that the 

value of the STAF is 1.111. 

Regarding proposed paragraphs (k) 

and (l) in § 75.15, EPA has reconsidered 

its position and has withdrawn the 

requirement for the sorbent traps used 

for RATA testing to be the same size as 

the traps used for daily operation of the 

monitoring system. Accordingly, the 

proposed requirement to perform a 

diagnostic RATA when the trap size is 

changed has also been withdrawn. The 

Agency is finalized paragraph (k) as part 

of a direct-final rulemaking on 

September 7, 2007 (72 FR 51494–

51531). Paragraph (k) requires only that 

the type of sorbent material used for the 

RATAs be the same as the sorbent 

material used for daily operation. 

Today’s rule finalizes paragraph (l) of 

§ 75.15, to require a diagnostic RATA 

within 720 operating hours whenever a 

new type of sorbent material begins to 

be used in the traps (e.g., using 

brominated carbon instead of iodated 

carbon). Commenters on proposed 

paragraph (l) questioned why data 

collected by the modified sorbent trap 

system are considered invalid prior to 

the diagnostic RATA. The commenters 

requested that EPA revise paragraph (l) 

to allow data collected prior to the 

diagnostic RATA to be reported as valid 

if the RATA is passed. The commenters’

suggestion is reasonable and has been 

incorporated into the final rule. A 

passed diagnostic RATA demonstrates 

that the change in sorbent material has 

not significantly affected the monitoring 

system’s ability to accurately measure 

Hg emissions. Therefore, § 75.15(l) 

allows the data from the modified 

sorbent trap system to be considered 

conditionally valid according to 

§ 75.20(b)(3), for up to 720 unit or stack 

operating hours after switching to a new 

type of sorbent material. If the 

diagnostic RATA is passed within the 

720 operating hour window, the data 

recorded by the modified system prior 

to the RATA may be reported as qualityassured. If the RATA is failed, no data 

from the modified system may be 

reported as quality-assured until a 

subsequent RATA is passed. If the 

diagnostic RATA is not completed 

within the allotted 720 operating hour 

window but is passed on the first 

attempt, data from the modified system 

are considered to be invalid from the 

first hour after the expiration of the 720 

operating hour window until the 

completion of the RATA. 

No comments were received on the 

following proposed amendments: (1) 

The proposal to allow the higher Hg 

concentration to be reported when the 

RD criterion for the paired sorbent traps 

is not met; (2) the proposed acceptance 

criteria for the hourly ratios of stack gas 

flow rate to sample flow rate; and (3) the 

proposal to require the sample flow rate 

through a sorbent trap monitoring 

system to be zero when the affected unit 

is off-line. Therefore, these provisions 

have been finalized, as proposed. 

O. Other Rule revisions 

1. Particulate Matter Monitoring 

Systems 

Background 

EPA received a comment that was 

outside the scope of the proposed rule, 

requesting that units with installed 

particulate matter (PM) monitoring 

systems be exempted from the opacity 

monitoring requirements of § 75.14. 

Summary of Rule Changes 

Although the comment was outside 

the scope of this rulemaking and no 

response is required, EPA believes that 

it has merit in light of June 13, 2007 

amendments to Subparts Da and Db of 

40 CFR Part 60 (see: 72 FR p.32710). For 

certain affected units (some of which are 

also subject to Part 75), these rule 

revisions either require or allow a 

particulate matter (PM) monitoring 

system to be used in lieu of an opacity 

monitor (e.g., see §§ 60.49Da(t), and 

60.48b(j)). 

Summary of Rule Changes 

Today’s rule incorporates the 

commenter’s recommendation, as new 

paragraph (e) in § 75.14. The Agency 

believes that this revision to Part 75 is 

non-controversial and is consistent with 

EPA’s ongoing commitment to 

harmonization of the Part 60 and Part 75 

continuous monitoring regulations. 

2. Default Moisture Values for Hg 

Monitoring 

Background 

For dry-basis Hg CEMS and sorbent 

trap monitoring systems, the hourly Hg 

emissions data must be corrected for the 

stack gas moisture content. This 

requirement can be met by using one of 

the fuel-specific default moisture values 

specified in Part 75. Several places in 

§ 75.80, § 75.81, and Appendix K state 

that for the purposes of Hg monitoring, 

a default moisture value from § 75.11(b) 

or § 75.12(b) may be used in lieu of 

installing a continuous moisture 

monitoring system. However, the 

reference to § 75.12(b) is incorrect. Only 

the default moisture values in § 75.11(b) 

are appropriate for Hg monitoring 

applications. Equation F–29, the only 

Hg mass emissions equation with a 

moisture correction term, is structurally 

similar to Equation F–2 for SO2 mass 

emissions. The default moisture values 

in § 75.11(b) are the ones that apply to 

Equation F–2. Hence, they apply also to 

Equation F–29. The default moisture 

values in § 75.12(b) are used for NOX

emission rate calculations, and several 

of them are not applicable to Hg mass 

emissions monitoring. 

Summary of Rule Changes 

All references to the default moisture 

values in § 75.12(b) have been removed 

from § 75.80, § 75.81, and Appendix K. 

3. Hg Stratification Testing 

Background 

To support the Clean Air Mercury 

Regulation (CAMR), which was 

published in 2005 (see: 70 FR 28606, 

May 18, 2005), EPA added Hg 

monitoring provisions to Part 75, among 

which were revisions to § 75.22(a) and 

to section 6.5.10 of Appendix A, 

specifying ASTM D6784–02, the 

‘‘Ontario Hydro Method’’, as the 

appropriate reference method for 


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measuring Hg concentration. On August 

22, 2006 EPA proposed to add Method 

29 (which is similar to Ontario Hydro) 

to Part 75, as an alternative Hg reference 

method. Most recently, in a direct-final 

action on September 7, 2007. EPA 

published two more alternative 

reference methods (RMs) for measuring 

vapor phase Hg emissions, Method 30A 

(an instrumental method) and Method 

30B (a sorbent-based method). Today’s 

rule allows the use of Methods 29, 30A, 

and 30B as alternatives to the Ontario 

Hydro Method (see the revisions to 

§ 75.22(a) and Section 6.5.10 of 

Appendix A). EPA anticipates that in 

2008 and beyond, all four of the Hg 

reference methods in Part 75 will be 

used, to a greater or lesser extent, for the 

Hg emission testing required under 

§§ 75.81(c) and (d) and for RATAs of Hg 

monitoring systems. 

For Hg emission tests, Methods 30A 

and 30B require 12 sampling points 

(located according to EPA Method 1) for 

each test run, unless the results of a Hg 

stratification test justify using fewer 

points. The Ontario Hydro Method and 

Method 29 each require a minimum of 

12 sample points and do not include 

any stratification test provisions or 

alternative sampling point location 

criteria. 

For the RATAs of Part 75 Hg 

monitoring systems, when Methods 30A 

and 30B are used, both methods defer to 

the RM point selection and location 

procedures described in Part 75, 

Appendix A, section 6.5.6 and 

Performance Specification 2 (PS2) in 

Appendix B of 40 CFR Part 60. This is 

the familiar sampling approach that 

allows the use of a ‘‘short’’ 3-point 

measurement line at locations where 

stratification is not expected, but 

requires the use of a 3-point ‘‘long’’

measurement line (which includes a 

point at the center of the stack) at 

locations where stratification is 

suspected (e.g., after a wet scrubber), 

unless the results of a stratification test 

justify using the 3-point short line (or 

perhaps a single sampling point). As an 

alternative, Part 75 allows the use of six 

Method 1 sampling points located along 

a diameter, at any test location 

(including those where stratification is 

suspected). This same RM sampling 

point location methodology applies to 

Hg RATAs in which the Ontario Hydro 

Method or Method 29 is used as the 

reference method. 

However, when testing is performed 

downstream of a scrubber, measuring at 

the center of a large-diameter stack is 

extremely difficult logistically, and 

testing at 6 points along a diameter may 

not be possible for certain test platform 

and test port configurations. Therefore, 

historically, most testers have opted to 

perform stratification testing at scrubbed 

stacks to justify sampling along a 3- 

point short line (or at a single point), 

which greatly simplifies the test 

procedures, in that all measurements 

can be made at one test port, using a 

probe of reasonable length. 

Unfortunately, Part 75 does not have a 

stratification test procedure for Hg, and, 

as previously noted, neither the Ontario 

Hydro Method nor Method 29 has any 

stratification test provisions—but there 

is a Hg stratification test procedure in 

Method 30A. 

Summary of Rule Changes 

In view of these considerations, EPA 

has deemed it necessary to revise 

Section 6.5.6(c) of Appendix A, to crossreference the Hg stratification test 

provisions in Sections 8.1.3 through 

8.1.3.5 of Method 30A. Further, 

§ 75.22(a)(7) has been revised to address 

RM sample point location and 

stratification testing when the Ontario 

Hydro Method or Method 29 is used for 

the Hg low mass emission testing 

required under §§ 75.81(c) and (d). For 

that particular application, revised 

§ 75.22(a)(7) requires the sampling 

points to be located according to Section 

8.1 of Method 30A and cross-references 

the stratification test provisions in 

sections 8.1.3 through 8.1.3.5 of Method 

30A. 

These amendments to Appendix A 

and § 75.22 provide a consistent 

approach to stratification testing and 

RM sampling point location for Hg 

emission testing and Hg monitoring 

system RATAs, irrespective of which Hg 

reference method is used for the testing. 

II. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order (EO) 12866 (58 FR 

51735, October 4, 1993) and is therefore 

not subject to review under the EO. 

B. Paperwork Reduction Act 

The information collection 

requirements in the final rule have been 

submitted for approval to OMB under 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. The Information Collection 

Request (ICR) document prepared by 

EPA has been assigned EPA ICR number 

2203.02. The information collection 

requirements are not enforceable until 

OMB approves them. 

The information requirements are 

based on the revisions to the 

monitoring, recordkeeping, and 

reporting requirements in 40 CFR Part 

75, which are mandatory for all sources 

subject to the Acid Rain Program under 

Title IV of the Clean Air Act and certain 

other emissions trading programs 

administered by EPA. All information 

submitted to EPA pursuant to the 

recordkeeping and reporting 

requirements for which a claim of 

confidentiality is made is safeguarded 

according to Agency policies set forth in 

40 CFR Part 2, subpart B. The 

preexisting Part 75 rule requirements 

amended in this final rule are covered 

by existing ICRs for the Acid Rain 

Program (EPA ICR number 1633.14; 

OMB control number 2060–0258), the 

NOX SIP Call (EPA ICR number 1857.04; 

OMB number 2060–0445), and the 

Clean Air Interstate Rule (EPA ICR 

number 2152.02; OMB number 2060–

0570). The separate ICR for the final rule 

revisions addresses the one-time costs 

necessary for sources to review the rule 

revisions and adapt their recordkeeping 

and reporting systems to the revised 

requirements. The EPA believes that the 

long term implications of the rule 

revisions will be to reduce the ongoing 

burdens and costs associated with Part 

75 compliance, but those impacts will 

be addressed as EPA renews the 

individual program ICRs. The annual 

monitoring, reporting, and 

recordkeeping burden for this collection 

(averaged over the first 3 years after the 

effective date of the final rule) is 

estimated to be 124,976 labor hours per 

year at a total annual cost of $8,581,420. 

This estimate includes burdens for rule 

review, recordkeeping and reporting 

software upgrades, and software 

debugging activities, as well as the 

capital costs of upgrading recordkeeping 

and reporting software. 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. An Agency 

may not conduct or sponsor, and a 

person is not required to respond to a 

collection of information unless it 


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4338 Federal Register / Vol. 73, No. 16 / Thursday, January 24, 2008 / Rules and Regulations 

displays a currently valid OMB control 

number. The OMB control numbers for 

EPA’s regulations in 40 CFR are listed 

in 40 CFR Part 9. When this ICR is 

approved by OMB, the Agency will 

publish a technical amendment to 40 

CFR part 9 in the Federal Register to 

display the OMB control number for the 

approved information collection 

requirements contained in this final 

rule. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. For purposes of assessing 

the impacts of today’s rule on small 

entities, small entity is defined as: (1) A 

small business as defined by the SBA’s 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of today’s final rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

In determining whether a rule has a 

significant economic impact on small 

entities, the impact of concern is any 

significant adverse economic impact on 

small entities, since the primary 

purpose of the regulatory flexibility 

analysis is to identify and address 

regulatory alternatives ‘‘which minimize 

any significant economic impact of the 

rule on small entities.’’ 5 U.S.C. 603 and 

604. Thus, an agency may certify that a 

rule will not have a significant 

economic impact on a substantial 

number of small entities if the rule 

relieves regulatory burden or otherwise 

has a positive economic effect on all of 

the small entities subject to the rule. 

These final rule revisions represent 

minor changes to existing monitoring 

requirements used in EPA emission 

trading programs and we expect these 

revisions to reduce the economic 

burden for affected entities in the long 

term. 

Although there will be some small 

level of up front costs to reprogram 

existing electronic data reporting 

software used under this program, the 

long term effects of these revisions will 

be to allow continued efficient 

electronic data submittals that should 

act to relieve some of the long term 

reporting burdens for affected sources, 

which include some small entities. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Pub. L. 

104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

sector. Under section 202 of the UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most cost 

effective or least burdensome alternative 

that achieves the objectives of the rule. 

The provisions of section 205 do not 

apply when they are inconsistent with 

applicable law. Moreover, section 205 

allows EPA to adopt an alternative other 

than the least costly, most cost-effective, 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, it must have developed 

under section 203 of the UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. EPA has 

determined that this final rule does not 

contain a Federal mandate that may 

result in expenditures of $100 million or 

more for State, local, and tribal 

governments in the aggregate, or to the 

private sector in any 1 year, nor does 

this rule significantly or uniquely 

impact small governments, because it 

contains no requirements that impose 

new obligations upon them. Thus, this 

final rule is not subject to the 

requirements of sections 202 and 205 of 

the UMRA. 

EPA has determined that this rule 

contains no regulatory requirements that 

might significantly or uniquely affect 

small governments. The revisions 

primarily make certain changes EPA has 

determined are necessary as part of 

upgrading the data systems used to 

manage data submitted under the 

program and to streamline the methods 

for sources to report their information. 

The revisions also clarify certain issues 

that have been raised during ongoing 

implementation of the existing rule and 

update the information on various 

voluntary consensus standards 

incorporated by reference in the rule. 

Some States do have programs that rely 

on the monitoring provisions in 40 CFR 

Part 75, and States may incur some costs 

associated with reviewing the 

modifications to Part 75, but the rule 

revisions and the impact on the States 

are not significant. 

E. Executive Order 13132: Federalism 

Executive Order 13132, entitled 

‘‘Federalism’’ (64 FR 43255, August 10, 

1999), requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’ This 

final rule does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. These rule 

revisions represent minor adjustments 

to existing regulations. The revisions 

primarily make certain changes EPA has 

determined are necessary as part of 

upgrading the data systems used to 

manage data submitted under the 

program and to streamline the methods 

for sources to report their information. 

The revisions also clarify certain issues 

that have been raised during ongoing 

implementation of the existing rule and 

update the information on various 

voluntary consensus standards 

incorporated by reference in the rule. 

Some States do have programs that rely 

on the monitoring provisions in 40 CFR 

Part 75, and States may incur some costs 


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Federal Register / Vol. 73, No. 16 / Thursday, January 24, 2008 / Rules and Regulations 4339 

associated with reviewing the 

modifications to Part 75, but the rule 

revisions and the impact on the States 

are not significant. Thus, Executive 

Order 13132 does not apply to this final 

rule. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination With 

Indian Tribal Governments’’ (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This final rule does not 

have tribal implications, as specified in 

Executive Order 13175. It will not have 

substantial direct effects on tribal 

governments, on the relationship 

between the Federal government and 

Indian tribes, or on the distribution of 

power and responsibilities between the 

Federal government and Indian tribes. 

Thus, Executive Order 13175 does not 

apply to this final rule. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

Executive Order 13045: ‘‘Protection of 

Children From Environmental Health 

Risks and Safety Risks’’ (62 FR 19885, 

April 23, 1997) applies to any rule that: 

(1) Is determined to be ‘‘economically 

significant’’ as defined under Executive 

Order 12866, and (2) concerns an 

environmental health or safety risk that 

EPA has reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

the Agency must evaluate the 

environmental health or safety effects of 

the planned rule on children, and 

explain why the planned regulation is 

preferable to other potentially effective 

and reasonably feasible alternatives 

considered by the Agency. EPA 

interprets Executive Order 13045 as 

applying only to those regulatory 

actions that are based on health or safety 

risks, such that the analysis required 

under section 5–501 of the Order has 

the potential to influence the regulation. 

This rule is not subject to Executive 

Order 13045 because it does not 

establish an environmental standard 

intended to mitigate health or safety 

risks. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This rule is not subject to Executive 

Order 13211, ‘‘Actions Concerning 

Regulations That Significantly Affect 

Energy Supply, Distribution, or Use’’ (66 

FR 28355, May 22, 2001) because it is 

not a significant regulatory action under 

Executive Order 12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law No. 

104–113, section 12(d) (15 U.S.C. 272 

note) directs EPA to use voluntary 

consensus standards in its regulatory 

activities unless to do so would be 

inconsistent with applicable law or 

otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. The NTTAA directs 

EPA to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. This 

rule includes updated information on a 

number of voluntary consensus 

standards previously included in 40 

CFR Part 75, as well as the addition of 

certain other voluntary consensus 

standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629 

(Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. EPA 

has determined that this final rule will 

not have disproportionately high and 

adverse human health or environmental 

effects on minority or low-income 

populations because it does not affect 

the level of protection provided to 

human health or the environment. This 

final rule does not affect or relax the 

control measures on sources impacted 

by emission trading programs that rely 

on monitoring under 40 CFR Part 75. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

Agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this rule and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

This action is not a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). This rule 

will be effective on January 24, 2008 for 

good cause found as explained in this 

rule. 

L. Petitions for Judicial Review 

Under Clean Air Act section 307(b)(1), 

petitions for judicial review of this 

action must be filed in the United States 

Court of Appeals for the appropriate 

circuit by March 24, 2008. Filing a 

petition for reconsideration by the 

Administrator of this final rule does not 

affect the finality of this rule for the 

purposes of judicial review, nor does it 

extend the time within which a petition 

for judicial review may be filed, and 

shall not postpone the effectiveness of 

such a rule or action. This action may 

not be challenged later in proceedings to 

enforce its requirements. (See section 

307(b)(2) of the Administrative 

Procedures Act.) 

M. Determination Under Section 307(d) 

Pursuant to Clean Air Act section 

307(d)(1)(U), the Administrator 

determines that this action is subject to 

the provisions of section 307(d). Section 

307(d)(1)(U) provides that the 

provisions of section 307(d) apply to 

‘‘such other actions as the Administrator 

may determine.’’ While the 

Administrator did not make this 

determination earlier, the Administrator 

believes that all of the procedural 

requirements, e.g., docketing, hearing 

and comment periods, of section 307(d) 

have been complied with during the 

course of this rulemaking. 

List of Subjects in 40 CFR Parts 72 and 

75 

Environmental protection, Acid rain, 

Administrative practice and procedure, 

Air pollution control, Carbon dioxide, 

Continuous emission monitoring, 

Electric utilities, Incorporation by 

reference, Nitrogen oxides, Reporting 

and recordkeeping requirements, Sulfur 

oxides. 


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4340 Federal Register / Vol. 73, No. 16 / Thursday, January 24, 2008 / Rules and Regulations 

Dated: December 19, 2007. 

Stephen L. Johnson, 

Administrator. 

■ For the reasons set forth in the 

preamble, parts 72 and 75 of chapter I 

of title 40 of the Code of Federal 

Regulations are amended as follows: 

PART 72—PERMITS REGULATION 

■ 1. The authority citation for part 72 

continues to read as follows: 

Authority: 42 U.S.C. 7601 and 7651, et seq. 

Subpart A—Acid Rain Program 

General Provisions 

■ 2. Section 72.2 is amended as follows: 

■ a. Revising the definition of ‘‘Capacity 

factor’’; 

■ b. In the definition of ‘‘Diluent cap’’, 

by removing the words ‘‘, CO2 mass 

emission rate, or heat input rate,’’ after 

the words ‘‘NOX emission rate’’; 

■ c. In the definition of ‘‘EPA protocol 

gas’’, by adding a new sentence to the 

end of the definition; 

■ d. Revising the definition of 

‘‘Excepted monitoring system’’; 

■ e. Adding the new definitions in 

alphabetical order for ‘‘Air Emission 

Testing Body (AETB)’’, ‘‘EPA Protocol 

Gas Verification Program’’, ‘‘Long-term 

cold storage’’, ‘‘NIST traceable 

elemental Hg standards’’, ‘‘NIST 

traceable source of oxidized Hg’’, 

‘‘Qualified Individual’’, and ‘‘Specialty 

gas producer’’; and 

■ f. Removing the definition for 

‘‘Research gas material (RGM)’’

The revisions and additions read as 

follows: 

§ 72.2 Definitions. 

* * * * * 

Air Emission Testing Body (AETB) 

means a company or other entity that 

conducts Air Emissions Testing as 

described in ASTM D7036–04 

(incorporated by reference under § 75.6 

of this part). 

* * * * * 

Capacity factor means either: 

(1) The ratio of a unit’s actual annual 

electric output (expressed in MWe/hr) 

to the unit’s nameplate capacity (or 

maximum observed hourly gross load 

(in MWe/hr) if greater than the 

nameplate capacity) times 8760 hours; 

or 

(2) The ratio of a unit’s annual heat 

input (in million British thermal units 

or equivalent units of measure) to the 

unit’s maximum rated hourly heat input 

rate (in million British thermal units per 

hour or equivalent units of measure) 

times 8,760 hours. 

* * * * * 

EPA protocol gas * * * On and after 

January 1, 2009, vendors advertising 

certification with the EPA Traceability 

Protocol or distributing gases as ‘‘EPA 

Protocol Gas’’ must participate in the 

EPA Protocol Gas Verification Program. 

Non-participating vendors may not use 

‘‘EPA’’ in any form of advertising for 

these products, unless approved by the 

Administrator. 

EPA Protocol Gas Verification 

Program means the EPA Protocol Gas 

audit program described in Section 

2.1.10 of the ‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 

1997, EPA–600/R–97/121 (EPA Protocol 

Procedure) or such revised procedure as 

approved by the Administrator. 

* * * * * 

Excepted monitoring system means a 

monitoring system that follows the 

procedures and requirements of § 75.15 

of this chapter, § 75.19 of this chapter, 

§ 75.81(b) of this chapter or of appendix 

D, or E to part 75 for approved 

exceptions to the use of continuous 

emission monitoring systems. 

* * * * * 

Long-term cold storage means the 

complete shutdown of a unit intended 

to last for an extended period of time (at 

least two calendar years) where notice 

for long-term cold storage is provided 

under § 75.61(a)(7). 

* * * * * 

NIST traceable elemental Hg 

standards means either: 

(1) Compressed gas cylinders having 

known concentrations of elemental Hg, 

which have been prepared according to 

the ‘‘EPA Traceability Protocol for 

Assay and Certification of Gaseous 

Calibration Standards’’; or 

(2) Calibration gases having known 

concentrations of elemental Hg, 

produced by a generator that fully meets 

the performance requirements of the 

‘‘EPA Traceability Protocol for 

Qualification and Certification of 

Elemental Mercury Gas Generators’’. 

* * * * * 

NIST traceable source of oxidized Hg 

means a generator that: Is capable of 

providing known concentrations of 

vapor phase mercuric chloride (HgCl2), 

and that fully meets the performance 

requirements of the ‘‘EPA Traceability 

Protocol for Qualification and 

Certification of Oxidized Mercury Gas 

Generators’’. 

* * * * * 

Qualified Individual means an 

individual who meets the requirements 

as described in ASTM D7036–04, 

‘‘Standard Practice for Competence of 

Air Emission Testing Bodies’’

(incorporated by reference under § 75.6 

of this part). 

* * * * * 

Specialty gas producer means an 

organization that prepares and analyzes 

compressed gas mixtures for use as 

calibration gases and that offers the 

mixtures for sale to end users or to 

third-party vendors for resale to end 

users. 

* * * * * 

PART 75—CONTINUOUS EMISSION 

MONITORING 

■ 3. The authority citation for Part 75 

continues to read as follows: 

Authority: 42 U.S.C. 7601, and 7651k, and 

7651k note. 

Subpart A—General 

■ 4. Section 75.4 is amended by revising 

paragraph (d) to read as follows: 

§ 75.4 Compliance dates. 

* * * * * 

(d) This paragraph, applies to affected 

units under the Acid Rain Program and 

to units subject to a State or Federal 

pollutant mass emissions reduction 

program that adopts the emission 

monitoring and reporting provisions of 

this part. In accordance with § 75.20, for 

an affected unit which, on the 

applicable compliance date, is either in 

long-term cold storage (as defined in 

§ 72.2 of this chapter) or is shut down 

as the result of a planned outage or a 

forced outage, thereby preventing the 

required continuous monitoring system 

certification tests from being completed 

by the compliance date, the owner or 

operator shall provide notice of such 

unit storage or outage in accordance 

with § 75.61(a)(3) or § 75.61(a)(7), as 

applicable. For the planned and 

unplanned unit outages described in 

this paragraph, the owner or operator 

shall ensure that all of the continuous 

monitoring systems for SO2, NOX, CO2, 

Hg, opacity, and volumetric flow rate 

required under this part (or under the 

applicable State or Federal mass 

emissions reduction program) are 

installed and that all required 

certification tests are completed no later 

than 90 unit operating days or 180 

calendar days (whichever occurs first) 

after the date that the unit recommences 

commercial operation, notice of which 

date shall be provided under 

§ 75.61(a)(3) or § 75.61(a)(7), as 

applicable. The owner or operator shall 

determine and report SO2 concentration, 

NOX emission rate, CO2 concentration, 

Hg concentration, and flow rate data (as 

applicable) for all unit operating hours 

after the applicable compliance date 

until all of the required certification 

tests are successfully completed, using 

either: 


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Federal Register / Vol. 73, No. 16 / Thursday, January 24, 2008 / Rules and Regulations 4341 

(1) The maximum potential 

concentration of SO2 (as defined in 

section 2.1.1.1 of appendix A to this 

part), the maximum potential NOX

emission rate, as defined in § 72.2 of 

this chapter, the maximum potential 

flow rate, as defined in section 2.1.4.1 

of appendix A to this part, the 

maximum potential Hg concentration, 

as defined in section 2.1.7.1 of appendix 

A to this part, or the maximum potential 

CO2 concentration, as defined in section 

2.1.3.1 of appendix A to this part; or 

(2) The conditional data validation 

provisions of § 75.20(b)(3); or 

(3) Reference methods under 

§ 75.22(b); or 

(4) Another procedure approved by 

the Administrator pursuant to a petition 

under § 75.66. 

* * * * * 

■ 5. Section 75.6 is amended by: 

■ a. Removing ‘‘D129–91’’ and adding 

in its place ‘‘D129–00’’, in paragraph 

(a)(1); 

■ b. Removing ‘‘D240–87 (Reapproved 

1991)’’ and adding in its place ‘‘D240–

00’’, in paragraph (a)(2); 

■ c. Removing ‘‘D287–82 (Reapproved 

1987)’’ and adding in its place ‘‘D287–

92 (Reapproved 2000)’’, in paragraph 

(a)(3); 

■ d. Removing ‘‘D388–92’’ and adding 

in its place ‘‘D388–99’’, in paragraph 

(a)(4); 

■ e. Removing and reserving paragraph 

(a)(5); 

■ f. Removing ‘‘D1072–90’’ and adding 

in its place ‘‘D1072–06’’, and also by 

adding the phrase ‘‘by Combustion and 

Barium Chloride Titration’’ after the 

word ‘‘Gases’’, in paragraph (a)(6); 

■ g. Removing ‘‘D1217–91’’ and adding 

in its place ‘‘D1217–93 (Reapproved 

1998)’’, in paragraph (a)(7); 

■ h. Removing the phrase ‘‘(Reapproved 

1990)’’, and by removing ‘‘D1250–80’’

and adding in its place ‘‘D1250–07’’, 

and also by adding the phrase ‘‘Use of 

the’’ after the first occurrence of the 

word ‘‘for’’, in paragraph (a)(8); 

■ i. Removing the phrase ‘‘D1298–85 

(Reapproved 1990), Standard Practice 

for Density, Relative Density (Specific 

Gravity)’’ and adding in its place 

‘‘D1298–99, Standard Test Method for 

Density, Relative Density (Specific 

Gravity),’’, in paragraph (a)(9); 

■ j. Removing ‘‘D1480–91’’ and adding 

in its place ‘‘D1480–93 (Reapproved 

1997)’’, in paragraph (a)(10); 

■ k. Removing ‘‘D1481–91’’ and adding 

in its place ‘‘D1481–93 (Reapproved 

1997)’’, in paragraph (a)(11); 

■ l. Removing ‘‘D1552–90’’ and adding 

in its place ‘‘D1552–01’’, and also by 

removing the phrase, ‘‘High 

Temperature’’ and adding in its place 

‘‘High-Temperature’’, in paragraph 

(a)(12); 

■ m. Removing ‘‘D1826–88’’ and adding 

in its place ‘‘D1826–94 (Reapproved 

1998)’’, in paragraph (a)(13); 

■ n. Removing ‘‘D1945–91’’ and adding 

in its place ‘‘D1945–96 (Reapproved 

2001)’’, in paragraph (a)(14); 

■ o. Adding the phrase ‘‘(Reapproved 

2006)’’ after ‘‘D1946–90’’, in paragraph 

(a)(15); 

■ p. Removing and reserving paragraph 

(a)(16); 

■ q. Removing ‘‘D2013–86’’ and adding 

in its place ‘‘D2013–01’’, and also by 

removing the phrase, ‘‘Method of’’, and 

adding in its place, ‘‘Practice for’’, in 

paragraph (a)(17); 

■ r. Removing and reserving paragraph 

(a)(18); 

■ s. Removing ‘‘D2234–89’’ and adding 

in its place ‘‘D2234–00’’, and also by 

removing the phrase ‘‘Test Methods’’, 

and adding in its place, ‘‘Practice’’, in 

paragraph (a)(19); 

■ t. Removing and reserving paragraph 

(a)(20); 

■ u. Removing ‘‘D2502–87’’ and adding 

in its place ‘‘D2502–92 (Reapproved 

1996)’’, in paragraph (a)(21); 

■ v. Removing ‘‘D2503–82 (Reapproved 

1987)’’ and adding in its place ‘‘D2503–

92 (Reapproved 1997)’’, and also by 

removing the phrase ‘‘Molecular Weight 

(Relative Molecular Mass)’’, and by 

adding in its place, ‘‘Relative Molecular 

Mass (Molecular Weight)’’, in paragraph 

(a)(22); 

■ w. Removing ‘‘D2622–92’’ and adding 

in its place ‘‘D2622–98’’, and also by 

removing the phrase ‘‘X-Ray 

Spectrometry’’, and adding in its place 

‘‘Wavelength Dispersive X-ray 

Fluorescence Spectrometry’’, in 

paragraph (a)(23); 

■ x. Removing ‘‘D3174–89’’ and adding 

in its place ‘‘D3174–00’’, and also by 

removing the word ‘‘From’’ and adding 

in its place ‘‘from’’, in paragraph (a)(24); 

■ y. Adding the phrase ‘‘(Reapproved 

2002)’’ after ‘‘D3176–89’’, in paragraph 

(a)(25); 

■ z. Removing ‘‘D3177–89’’ and adding 

in its place the phrase ‘‘ D3177–02 

(Reapproved 2007)’’ in paragraph 

(a)(26); 

■ aa. Removing ‘‘ D3178–89 (1997), 

‘‘Standard Test Methods for Carbon and 

Hydrogen in the Analysis Sample of 

Coal and Coke’’ and adding in its place 

‘‘D5373–02 (Reapproved 2007) Standard 

Test Methods for Instrumental 

Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal 

and Coke’’ in paragraph (a)(27); 

■ bb. Removing ‘‘D3238–90’’ and adding 

in its place ‘‘D3238–95 (Reapproved 

2000)’’, in paragraph (a)(28); 

■ cc. Removing ‘‘D3246–81 (Reapproved 

1987)’’ and adding in its place ‘‘D3246–

96’’, and also by removing the word 

‘‘By’’ and adding in its place, ‘‘by’’, in 

paragraph (a)(29); 

■ dd. Removing and reserving 

paragraph (a)(30); 

■ ee. Removing ‘‘D3588–91’’ and adding 

in its place ‘‘D3588–98’’, and also by 

removing the phrase, ‘‘(Specific 

Gravity)’’, in paragraph (a)(31); 

■ ff. Removing ‘‘D4052–91’’ and adding 

in its place ‘‘D4052–96 (Reapproved 

2002)’’, in paragraph (a)(32); 

■ gg. Removing ‘‘D4057–88’’ and adding 

in its place ‘‘D4057–95 (Reapproved 

2000)’’, in paragraph (a)(33); 

■ hh. Removing ‘‘D4177–82 

(Reapproved 1990)’’ and adding in its 

place ‘‘D4177–95 (Reapproved 2000)’’, 

in paragraph (a)(34); 

■ ii. Removing ‘‘D4239–85’’ and adding 

in its place ‘‘D4239–02’’, and also by 

removing the phrase ‘‘High 

Temperature’’, and adding in its place 

‘‘High-Temperature’’, in paragraph 

(a)(35); 

■ jj. Removing ‘‘D4294–90’’ and adding 

in its place ‘‘D4294–98’’, adding the 

words ‘‘and Petroleum’’ after the word 

‘‘Petroleum’’, by removing the word ‘‘XRay’’ and adding in its place, ‘‘X-ray’’, 

and by removing the word 

‘‘Spectroscopy’’ and adding in its place, 

‘‘Spectrometry’’ in paragraph (a)(36); 

■ kk. Removing the phrase 

‘‘(Reapproved 1989)’’ and adding in its 

place the phrase ‘‘(Reapproved 2006)’’, 

in paragraph (a)(37); 

■ ll. Removing ‘‘(reapproved 2004)’’, 

and adding in its place, ‘‘(Reapproved 

2004)’’, in paragraph (a)(38); 

■ mm. Adding the phrase ‘‘(Reapproved 

2006)’’ after ‘‘D4891–89’’, in paragraph 

(a)(39); 

■ nn. Removing ‘‘D5291–92’’ and 

adding in its place ‘‘D5291–02’’, in 

paragraph (a)(40); 

■ oo. Removing ‘‘D5373–93’’, and 

adding in its place ‘‘D5373–02 

(Reapproved 2007)’’ and adding the 

word ‘‘Test’’ after the word ‘‘Standard’’, 

in paragraph (a)(41); 

■ pp. Removing ‘‘D5504–94’’ and 

adding in its place ‘‘D5504–01’’, in 

paragraph (a)(42); 

■ qq. Adding new paragraphs (a)(45), 

(a)(46), (a)(47), (a)(48), and (a)(49); 

■ rr. Removing the phrase ‘‘ASME 

MFC–3M–1989 with September 1990 

Errata’’ and adding in its place the 

phrase ‘‘ASME MFC–3M–2004 

(Revision of ASME MFC–3M–1989 

(R1995))’’, in paragraph (b)(1); 

■ ss. Removing the date ‘‘1990’’ and 

adding in its place the date ‘‘1997’’ in 

the parenthetical, in paragraph (b)(2); 

■ tt. Adding the phrase ‘‘(Reaffirmed 

1994)’’ after ‘‘ASME–MFC–5M–1985,’’, 

in paragraph (b)(3); 

■ uu. Removing the phrase ‘‘1987 with 

June 1987 Errata’’ and adding in its 


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4342 Federal Register / Vol. 73, No. 16 / Thursday, January 24, 2008 / Rules and Regulations 

place the number ‘‘1998’’ at the end of 

‘‘MFC–6M–’’, and also by removing 

‘‘Flow Meters’’ and adding in its place, 

‘‘Flowmeters’’, in paragraph (b)(4); 

■ vv. Removing the phrase ‘‘with 

December 1989 Errata’’ and adding in its 

place the phrase ‘‘(Reaffirmed 2001)’’, in 

paragraph (b)(6); 

■ ww. Removing the number ‘‘86’’ and 

adding in its place the number ‘‘96’’ at 

the end of ‘‘GPA Standard 2172–’’, in 

paragraph (d)(1); 

■ xx. Removing the number ‘‘90’’ and 

adding in its place the number ‘‘00’’ at 

the end of ‘‘GPA Standard 2261–00’’, in 

paragraph (d)(2); 

■ yy. Revising paragraphs (f)(1) and 

(f)(3); and 

■ zz. Adding new paragraph (f)(4). 

The revisions and additions read as 

follows: 

§ 75.6 Incorporation by reference. 

* * * * * 

(a) * * * 

(45) ASTM D6667–04, Standard Test 

Method for Determination of Total 

Volatile Sulfur in Gaseous 

Hydrocarbons and Liquefied Petroleum 

Gases by Ultraviolet Fluorescence, for 

appendix D of this part. 

(46) ASTM D4809–00, Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method), for 

appendices D and F of this part. 

(47) ASTM D5865–01a, Standard Test 

Method for Gross Calorific Value of Coal 

and Coke, for appendices A, D, and F of 

this part. 

(48) ASTM D7036–04, Standard 

Practice for Competence of Air Emission 

Testing Bodies, for appendices A, B, and 

E of this part. 

(49) 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, for appendix D of this 

part. 

* * * * * 

(f) * * * 

(1) American Petroleum Institute 

(API) Manual of Petroleum 

Measurement Standards, Chapter 3—

Tank Gauging, Section 1A, Standard 

Practice for the Manual Gauging of 

Petroleum and Petroleum Products, 

Second Edition, August 2005; Section 

1B—Standard Practice for Level 

Measurement of Liquid Hydrocarbons in 

Stationary Tanks by Automatic Tank 

Gauging, Second Edition June 2001; 

Section 2—Standard Practice for 

Gauging Petroleum and Petroleum 

Products in Tank Cars, First Edition, 

August 1995 (Reaffirmed March 2006); 

Section 3—Standard Practice for Level 

Measurement of Liquid Hydrocarbons in 

Stationary Pressurized Storage Tanks by 

Automatic Tank Gauging, First Edition 

June 1996; Section 4—Standard Practice 

for Level Measurement of Liquid 

Hydrocarbons on Marine Vessels by 

Automatic Tank Gauging, First Edition 

April 1995 (Reaffirmed, March 2006); 

and Section 5—Standard Practice for 

Level Measurement of Light 

Hydrocarbon Liquids Onboard Marine 

Vessels by Automatic Tank Gauging, 

First Edition March 1997 (Reaffirmed, 

March 2003); for § 75.19. 

* * * * * 

(3) American Petroleum Institute 

(API) Manual of Petroleum 

Measurement Standards, Chapter 4—

Proving Systems, Section 2—Pipe 

Provers (Provers Accumulating at Least 

10,000 Pulses), Second Edition, March 

2001, and Section 5—Master-Meter 

Provers, Second Edition, May 2000, for 

appendix D to this part. 

(4) American Petroleum Institute 

(API) Manual of Petroleum 

Measurement Standards, Chapter 22—

Testing Protocol, Section 2—Differential 

Pressure Flow Measurement Devices 

(First Edition, August 2005), for 

appendix D to this part. 

■ 6. Section 75.11 is amended by: 

■ a. Revising the heading of the section; 

■ b. Adding the phrase ‘‘and 14.0% for 

natural gas (boilers, only);’’ after the 

word ‘‘wood;’’, in paragraph (b)(1); 

■ c. Revising paragraph (d)(3); 

■ d. Revising paragraphs (e) 

introductory text and (e)(1); 

■ e. Removing and reserving paragraph 

(e)(2); 

■ f. Revising paragraph (e)(3) 

introductory text; 

■ g. Add new paragraph (e)(4); and 

■ h. Revising paragraph (f). 

The revisions and additions read as 

follows: 

§ 75.11 Specific provisions for monitoring 

SO2 emissions. 

* * * * * 

(d) * * * 

(3) By using the low mass emissions 

excepted methodology in § 75.19(c) for 

estimating hourly SO2 mass emissions if 

the affected unit qualifies as a low mass 

emissions unit under § 75.19(a) and (b). 

If this option is selected for SO2, the 

LME methodology must also be used for 

NOX and CO2 when these parameters 

are required to be monitored by 

applicable program(s). 

(e) Special considerations during the 

combustion of gaseous fuels. The owner 

or operator of an affected unit that uses 

a certified flow monitor and a certified 

diluent gas (O2 or CO2) monitor to 

measure the unit heat input rate shall, 

during any hours in which the unit 

combusts only gaseous fuel, determine 

SO2 emissions in accordance with 

paragraph (e)(1) or (e)(3) of this section, 

as applicable. 

(1) If the gaseous fuel qualifies for a 

default SO2 emission rate under Section 

2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix 

D to this part, the owner or operator 

may determine SO2 emissions by using 

Equation F–23 in appendix F to this 

part. Substitute into Equation F–23 the 

hourly heat input, calculated using the 

certified flow monitoring system and 

the certified diluent monitor (according 

to the applicable equation in section 5.2 

of appendix F to this part), in 

conjunction with the appropriate 

default SO2 emission rate from section 

2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix 

D to this part. When this option is 

chosen, the owner or operator shall 

perform the necessary data acquisition 

and handling system tests under 

§ 75.20(c), and shall meet all quality 

control and quality assurance 

requirements in appendix B to this part 

for the flow monitor and the diluent 

monitor; or 

(2) [Reserved] 

(3) The owner or operator may 

determine SO2 mass emissions by using 

a certified SO2 continuous monitoring 

system, in conjunction with the certified 

flow rate monitoring system. However, 

if the gaseous fuel is very low sulfur fuel 

(as defined in § 72.2 of this chapter), the 

SO2 monitoring system shall meet the 

following quality assurance provisions 

when the very low sulfur fuel is 

combusted: 

* * * * * 

(4) The provisions in paragraph (e)(1) 

of this section, may also be used for the 

combustion of a solid or liquid fuel that 

meets the definition of very low sulfur 

fuel in § 72.2 of this chapter, mixtures 

of such fuels, or combinations of such 

fuels with gaseous fuel, if the owner or 

operator submits a petition under 

§ 75.66 for a default SO2 emission rate 

for each fuel, mixture or combination, 

and if the Administrator approves the 

petition. 

(f) Other units. The owner or operator 

of an affected unit that combusts wood, 

refuse, or other material in addition to 

oil or gas shall comply with the 

monitoring provisions for coal-fired 

units specified in paragraph (a) of this 

section, except where the owner or 

operator has an approved petition to use 

the provisions of paragraph (e)(1) of this 

section. 

■ 7. Section 75.12 is amended by: 

■ a. Revising the section heading; 

■ b. Removing the word ‘‘and’’ before 

the number ‘‘15.0%’’, and by adding the 

phrase ‘‘; and 18.0% for natural gas 


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(boilers, only)’’ after the word ‘‘wood’’, 

in paragraph (b); and 

■ c. Revising paragraph (e)(3). 

The revisions read as follows: 

§ 75.12 Specific provisions for monitoring 

NOX emission rate. 

* * * * * 

(e) * * * 

(3) Use the low mass emissions 

excepted methodology in § 75.19(c) for 

estimating hourly NOX emission rate 

and hourly NOX mass emissions, if 

applicable under § 75.19(a) and (b). If 

this option is selected for NOX, the LME 

methodology must also be used for SO2

and CO2 when these parameters are 

required to be monitored by applicable 

program(s). 

* * * * * 

■ 8. Section 75.13 is amended by 

revising paragraph (d)(3) to read as 

follows: 

§ 75.13 Specific provisions for monitoring 

CO2 emissions. 

* * * * * 

(d) * * * 

(3) Use the low mass emissions 

excepted methodology in § 75.19(c) for 

estimating hourly CO2 mass emissions, 

if applicable under § 75.19(a) and (b). If 

this option is selected for CO2, the LME 

methodology must also be used for NOX

and SO2 when these parameters are 

required to be monitored by applicable 

program(s). 

■ 9. Section 75.14 is amended by adding 

paragraph (e) to read as follows: 

§ 75.14 Specific provisions for monitoring 

opacity. 

* * * * * 

(e) Unit with a certified particulate 

matter (PM) monitoring system. If, for a 

particular affected unit, the owner or 

operator installs, certifies, operates, 

maintains, and quality-assures a 

continuous particulate matter (PM) 

monitoring system in accordance with 

Procedure 2 in appendix F to part 60 of 

this chapter, the unit shall be exempt 

from the opacity monitoring 

requirement of this part. 

■ 10. Section 75.15 is amended by: 

■ a. Removing the reference ‘‘(j)’’ and 

adding the reference ‘‘(l)’’ in its place in 

the introductory paragraph; 

■ b. Revising paragraph (h); and 

■ c. Adding paragraph (l). 

The revisions and additions read as 

follows: 

§ 75.15 Special provisions for measuring 

Hg mass emissions using the excepted 

sorbent trap monitoring methodology. 

* * * * * 

(h) The hourly Hg mass emissions for 

each collection period are determined 

using the results of the analyses in 

conjunction with contemporaneous 

hourly data recorded by a certified stack 

flow monitor, corrected for the stack gas 

moisture content. For each pair of 

sorbent traps analyzed, the average of 

the two Hg concentrations shall be used 

for reporting purposes under ( 75.84(f). 

Notwithstanding this requirement, if, 

due to circumstances beyond the control 

of the owner or operator, one of the 

paired traps is accidentally lost, 

damaged, or broken and cannot be 

analyzed, the results of the analysis of 

the other trap may be used for reporting 

purposes, provided that: 

(1) The other trap has met all of the 

applicable quality-assurance 

requirements of this part; and 

(2) The Hg concentration measured by 

the other trap is multiplied by a factor 

of 1.111. 

* * * * * 

(l) Whenever the type of sorbent 

material used by the traps is changed, 

the owner or operator shall conduct a 

diagnostic RATA of the modified 

sorbent trap monitoring system within 

720 unit or stack operating hours after 

the date and hour when the new sorbent 

material is first used. If the diagnostic 

RATA is passed, data from the modified 

system may be reported as qualityassured, back to the date and hour when 

the new sorbent material was first used. 

If the RATA is failed, all data from the 

modified system shall be invalidated, 

back to the date and hour when the new 

sorbent material was first used, and data 

from the system shall remain invalid 

until a subsequent RATA is passed. If 

the required RATA is not completed 

within 720 unit or stack operating 

hours, but is passed on the first attempt, 

data from the modified system shall be 

invalidated beginning with the first 

operating hour after the 720 unit or 

stack operating hour window expires 

and data from the system shall remain 

invalid until the date and hour of 

completion of the successful RATA. 

■ 11. Section 75.16 is amended by: 

■ a. Revising paragraph (b)(1)(ii); 

■ b. Adding the word ‘‘rate’’ after the 

phrase ‘‘report heat input’’ in the last 

sentence, in paragraph (e)(1); and 

■ c. In the second sentence of 

paragraphs (e)(3) by removing both 

occurrences of the phrase ‘‘steam flow’’

and adding in its place the phrase 

‘‘steam load’’ and adding the phrase ‘‘or 

mmBtu/hr thermal output’’ inside the 

parentheses, after the phrase ‘‘in 1000 

lb/hr’’, in paragraph (e)(3). 

The revisions read as follows: 

§ 75.16 Special provisions for monitoring 

emissions from common, bypass, and 

multiple stacks for SO2 emissions and heat 

input determinations. 

* * * * * 

(b) * * * 

(1) * * * 

(ii) Install, certify, operate, and 

maintain an SO2 continuous emission 

monitoring system and flow monitoring 

system in the common stack and 

combine emissions for the affected units 

for recordkeeping and compliance 

purposes. 

* * * * * 

■ 12. Section 75.17 is amended by 

revising paragraph (d)(2) to read as 

follows: 

§ 75.17 Special provisions for monitoring 

emissions from common, bypass, and 

multiple stacks for NOX emission rate. 

* * * * * 

(d) * * * 

(2) Install, certify, operate, and 

maintain a NOX-diluent CEMS only on 

the main stack. If this option is chosen, 

it is not necessary to designate the 

exhaust configuration as a multiple 

stack configuration in the monitoring 

plan required under § 75.53, with 

respect to NOX or any other parameter 

that is monitored only at the main stack. 

For each unit operating hour in which 

the bypass stack is used and the 

emissions are either uncontrolled (or the 

add-on controls are not documented to 

be operating properly), report the 

maximum potential NOX emission rate 

(as defined in § 72.2 of this chapter). 

The maximum potential NOX emission 

rate may be specific to the type of fuel 

combusted in the unit during the bypass 

(see § 75.33(c)(8)). Alternatively, for a 

unit with NOX add-on emission 

controls, for each unit operating hour in 

which the bypass stack is used and the 

add-on NOX emission controls are not 

bypassed, the owner or operator may 

report the maximum controlled NOX

emission rate (MCR) instead of the 

maximum potential NOX emission rate 

provided that the add-on controls are 

documented to be operating properly, as 

described in the quality assurance/ 

quality control program for the unit, 

required by section 1 in appendix B of 

this part. To provide the necessary 

documentation, the owner or operator 

shall record parametric data to verify 

the proper operation of the NOX add-on 

emission controls as described in 

§ 75.34(d). Furthermore, the owner or 

operator shall calculate the MCR using 

the procedure described in section 

2.1.2.1(b) of appendix A to this part 

where the words ‘‘maximum potential 

NOX emission rate (MER)’’ shall apply 

instead of the words ‘‘maximum 


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4344 Federal Register / Vol. 73, No. 16 / Thursday, January 24, 2008 / Rules and Regulations 

controlled NOX emission rate (MCR)’’

and by using the NOX MEC in the 

calculations instead of the NOX MPC. 

■ 13. Section 75.19 is amended by: 

■ a. Revising paragraph (a)(1); 

■ b. Revising paragraph (c)(1)(i); 

■ c. Revising paragraph (c)(1)(iv)(A)(3); 

■ d. Removing the words ‘‘Method 20’’

from paragraph (c)(1)(iv)(A)(4); 

■ e. Removing the words ‘‘Method 20’’

from the definition of NOX obs in the 

nomenclature for Equation LM–1a 

under paragraph (c)(1)(iv)(A); 

■ f. Adding the phrase, ‘‘that meets the 

quality assurance requirements of 

either: this part, or appendix F to part 

60 of this chapter, or a comparable State 

CEM program,’’ after the abbreviation 

‘‘CEMS’’, in paragraph (c)(1)(iv)(G); 

■ g. Adding paragraphs (c)(1)(iv)(I)(3), 

(4), (5) and (6); 

■ h. Revising paragraph (c)(3)(ii)(B)(2); 

■ i. Revising paragraph (c)(3)(ii)(H); 

■ j. Removing the words ‘‘from Table 

LM–1 of this section’’ from the first 

sentence of paragraph (c)(4)(i)(A); 

■ k. Revising the heading for paragraph 

(c)(4)(ii); and 

■ l. Adding paragraph (c)(4)(ii)(D). 

The revisions and additions read as 

follows: 

§ 75.19 Optional SO2, NOX, and CO2

emissions calculation for low mass 

emissions units. 

* * * * * 

(a) * * * 

(1) For units that meet the 

requirements of this paragraph (a)(1) 

and paragraphs (a)(2) and (b) of this 

section, the low mass emissions (LME) 

excepted methodology in paragraph (c) 

of this section may be used in lieu of 

continuous emission monitoring 

systems or, if applicable, in lieu of 

methods under appendices D, E, and G 

to this part, for the purpose of 

determining unit heat input, NOX, SO2, 

and CO2 mass emissions, and NOX

emission rate under this part. If the 

owner or operator of a qualifying unit 

elects to use the LME methodology, it 

must be used for all parameters that are 

required to be monitored by the 

applicable program(s). For example, for 

an Acid Rain Program LME unit, the 

methodology must be used to estimate 

SO2, NOX, and CO2 mass emissions, 

NOX emission rate, and unit heat input. 

* * * * * 

(c) * * * 

(1) * * * 

(i) If the unit combusts only natural 

gas and/or fuel oil, use Table LM–1 of 

this section to determine the 

appropriate SO2 emission rate for use in 

calculating hourly SO2 mass emissions 

under this section. Alternatively, for 

fuel oil combustion, a lower, fuelspecific SO2 emission factor may be 

used in lieu of the applicable emission 

factor from Table LM–1, if a federally 

enforceable permit condition is in place 

that limits the sulfur content of the oil. 

If this alternative is chosen, the fuelspecific SO2 emission rate in lb/mmBtu 

shall be calculated by multiplying the 

fuel sulfur content limit (weight percent 

sulfur) by 1.01. In addition, the owner 

or operator shall periodically determine 

the sulfur content of the oil combusted 

in the unit, using one of the oil 

sampling and analysis options described 

in section 2.2 of appendix D to this part, 

and shall keep records of these fuel 

sampling results in a format suitable for 

inspection and auditing. Alternatively, 

the required oil sampling and associated 

recordkeeping may be performed using 

a consensus standard (e.g., ASTM, API, 

etc.) that is prescribed in the unit’s 

Federally-enforceable operating permit, 

in an applicable State regulation, or in 

another applicable Federal regulation. If 

the unit combusts gaseous fuel(s) other 

than natural gas, the owner or operator 

shall use the procedures in section 2.3.6 

of appendix D to this part to document 

the total sulfur content of each such fuel 

and to determine the appropriate default 

SO2 emission rate for each such fuel. 

* * * * * 

(iv) * * * 

(A) * * * 

(3) Do not correct the NOX

concentration to 15% O2. 

* * * * * 

(I) * * * 

(3) The initial appendix E testing may 

be performed at a single load, between 

75 and 100 percent of the maximum 

sustainable load defined in the 

monitoring plan for the unit, if the 

average annual capacity factor of the 

LME unit, when calculated according to 

the definition of ‘‘capacity factor’’ in 

§ 72.2 of this chapter, is 2.5 percent or 

less for the three calendar years 

immediately preceding the year of the 

testing, and that the annual capacity 

factor does not exceed 4.0 percent in 

any of those three years. Similarly, for 

a LME unit that reports emissions data 

on an ozone season-only basis, the 

initial appendix E testing may be 

performed at a single load between 75 

and 100 percent of the maximum 

sustainable load if the 2.5 and 4.0 

percent capacity factor requirements are 

met for the three ozone seasons 

immediately preceding the date of the 

emission testing (see § 75.74(c)(11)). For 

a group of identical LME units, any 

unit(s) in the group that meet the 2.5 

and 4.0 percent capacity factor 

requirements may perform the initial 

appendix E testing at a single load 

between 75 and 100 percent of the 

maximum sustainable load. 

(4) The retest of any LME unit may be 

performed at a single load between 75 

and 100 percent of the maximum 

sustainable load if, for the three 

calendar years immediately preceding 

the year of the retest (or, if applicable, 

the three ozone seasons immediately 

preceding the date of the retest), the 

applicable capacity factor requirements 

described in paragraph (c)(1)(iv)(I)(3) of 

this section are met. 

(5) Alternatively, for combustion 

turbines, the single-load testing 

described in paragraphs (c)(1)(iv)(I)(3) 

and (c)(1)(iv)(I)(4) of this section may be 

performed at the highest attainable load 

level corresponding to the season of the 

year in which the testing is conducted. 

(6) In all cases where the alternative 

single-load testing option described in 

paragraphs (c)(1)(iv)(I)(3) through 

(c)(1)(iv)(I)(5) of this section is used, the 

owner or operator shall keep records 

documenting that the required capacity 

factor requirements were met. 

* * * * * 

(3) * * * 

(ii) * * * 

(B) * * * 

(2) American Petroleum Institute 

(API) Manual of Petroleum 

Measurement Standards, Chapter 3- 

Tank Gauging, Section 1A, Standard 

Practice for the Manual Gauging of 

Petroleum and Petroleum Products, 

Second Edition, August 2005; Section 

1B-Standard Practice for Level 

Measurement of Liquid Hydrocarbons in 

Stationary Tanks by Automatic Tank 

Gauging, Second Edition June 2001; 

Section 2-Standard Practice for Gauging 

Petroleum and Petroleum Products in 

Tank Cars, First Edition, August 1995 

(Reaffirmed March 2006); Section 3- 

Standard Practice for Level 

Measurement of Liquid Hydrocarbons in 

Stationary Pressurized Storage Tanks by 

Automatic Tank Gauging, First Edition 

June 1996 (Reaffirmed, March 2001); 

Section 4-Standard Practice for Level 

Measurement of Liquid Hydrocarbons 

on Marine Vessels by Automatic Tank 

Gauging, First Edition April 1995 

(Reaffirmed, September 2000); and 

Section 5-Standard Practice for Level 

Measurement of Light Hydrocarbon 

Liquids Onboard Marine Vessels by 

Automatic Tank Gauging, First Edition 

March 1997 (Reaffirmed, March 2003); 

for § 75.19; Shop Testing of Automatic 

Liquid Level Gages, Bulletin 2509 B, 

December 1961 (Reaffirmed August 

1987, October 1992) (all incorporated by 

reference under § 75.6 of this part); or 

* * * * * 

(H) For each low mass emissions unit 

or each low mass emissions unit in a 


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group of identical units, the owner or 

operator shall determine the cumulative 

quarterly unit load in megawatt hours or 

thousands of pounds of steam. The 

quarterly cumulative unit load shall be 

the sum of the hourly unit load values 

recorded under paragraph (c)(2) of this 

section and shall be determined using 

Equations LM–5 or LM–6. For a unit 

subject to the provisions of subpart H of 

this part, which is not required to report 

emission data on a year-round basis and 

elects to report only during the ozone 

season, the quarterly cumulative load 

for the second calendar quarter of the 

year shall include only the unit loads 

for the months of May and June. 

MW MW Eq qtr

all hours

= −

∑ . LM-5 (for MW output)

ST ST Eq qtr

all hours

= −

∑ . LM-6 (for steam output)

Where: 

MWqtr = Sum of all unit operating loads 

recorded during the quarter by the unit 

(MWh). 

STfuel-qtr = Sum of all hourly steam loads 

recorded during the quarter by the unit 

(klb of steam/hr). 

MW = Unit operating load for a particular 

unit operating hour (MWh). 

ST = Unit steam load for a particular unit 

operating hour (klb of steam). 

* * * * * 

(4) * * * 

(ii) NOX mass emissions and NOX

emission rate. 

(D) The quarterly and cumulative 

NOX emission rate in lb/mmBtu (if 

required by the applicable program(s)) 

shall be determined as follows. 

Calculate the quarterly NOX emission 

rate by taking the arithmetic average of 

all of the hourly EFNOX values. Calculate 

the cumulative (year-to-date) NOX

emission rate by taking the arithmetic 

average of the quarterly NOX emission 

rates. 

* * * * * 

■ 14. Section 75.20 is amended by: 

■ a. Adding a new sentence after the 

third sentence of paragraph (b) 

introductory text; 

■ b. Revising paragraph (c)(1)(v); and 

■ c. Removing paragraphs (f)(1) and 

(f)(2). 

The revisions and additions read as 

follows: 

§ 75.20 Initial certification and 

recertification procedures. 

* * * * * 

(b) * * * The owner or operator shall 

also recertify the continuous emission 

monitoring systems for a unit that has 

recommenced commercial operation 

following a period of long-term cold 

storage as defined in § 72.2 of this 

chapter. * * * 

* * * * * 

(c) * * * 

(1) * * * 

(v) A cycle time test, (where, for the 

NOX-diluent continuous emission 

monitoring system, the test is performed 

separately on the NOX pollutant 

concentration monitor and the diluent 

gas monitor); and 

* * * * * 

§ 75.21 [Amended] 

■ 15. Section 75.21 is amended by 

removing the words ‘‘or (e)(2)’’ at the 

end of the first sentence of paragraph 

(a)(4). 

■ 16. Section 75.22 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Revising paragraphs (a)(5), (a)(6), 

and (a)(7); 

■ c. Revising paragraph (b) introductory 

text; 

■ d. Removing the word ‘‘and’’ at the 

end of paragraph (b)(3); 

■ e. Revising paragraph (b)(5); 

■ f. Adding paragraphs (b)(6), (b)(7), and 

(b)(8); and 

■ g. Revising paragraph (c)(1) 

introductory text. 

The revisions and additions read as 

follows: 

§ 75.22 Reference test methods. 

(a) The owner or operator shall use 

the following methods, which are found 

in appendix A–4 to part 60 of this 

chapter or have been published by 

ASTM, to conduct the following tests: 

monitoring system tests for certification 

or recertification of continuous emission 

monitoring systems and excepted 

monitoring systems under appendix E to 

this part; the emission tests required 

under § 75.81(c) and (d); and required 

quality assurance and quality control 

tests: 

* * * * * 

(5) Methods 6, 6A, 6B or 6C, and 7, 

7A, 7C, 7D or 7E in appendix A–4 to 

part 60 of this chapter, as applicable, are 

the reference methods for determining 

SO2 and NOX pollutant concentrations. 

(Methods 6A and 6B in appendix A–4 

to part 60 of this chapter may also be 

used to determine SO2 emission rate in 

lb/mmBtu.) Methods 7, 7A, 7C, 7D, or 

7E in appendix A–4 to part 60 of this 

chapter must be used to measure total 

NOX emissions, both NO and NO2, for 

purposes of this part. The owner or 

operator shall not use the following 

sections, exceptions, and options of 

method 7E in appendix A–4 to part 60 

of this chapter: 

(i) Section 7.1 of the method allowing 

for use of prepared calibration gas 

mixtures that are produced in 

accordance with method 205 in 

Appendix M of 40 CFR Part 51; 

(ii) The sampling point selection 

procedures in section 8.1 of the method, 

for the emission testing of boilers and 

combustion turbines under appendix E 

to this part. The number and location of 

the sampling points for those 

applications shall be as specified in 

sections 2.1.2.1 and 2.1.2.2 of appendix 

E to this part; 

(iii) Paragraph (3) in section 8.4 of the 

method allowing for the use of a multihole probe to satisfy the multipoint 

traverse requirement of the method; 

(iv) Section 8.6 of the method 

allowing for the use of ‘‘Dynamic 

Spiking’’ as an alternative to the 

interference and system bias checks of 

the method. Dynamic spiking may be 

conducted (optionally) as an additional 

quality assurance check. 

(6) Method 3A in appendix A–2 and 

method 7E in appendix A–4 to part 60 

of this chapter are the reference 

methods for determining NOX and 

diluent emissions from stationary gas 

turbines for testing under appendix E to 

this part. 

(7) ASTM D6784–02, Standard Test 

Method for Elemental, Oxidized, 

Particle-Bound and Total Mercury in 

Flue Gas Generated from Coal-Fired 

Stationary Sources (Ontario Hydro 

Method) (incorporated by reference 

under § 75.6 of this part) is the reference 

method for determining Hg 

concentration. 

(i) Alternatively, Method 29 in 

appendix A–8 to part 60 of this chapter 

may be used, with these caveats: The 

procedures for preparation of Hg 


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standards and sample analysis in 

sections 13.4.1.1 through 13.4.1.3 ASTM 

D6784–02 (incorporated by reference 

under § 75.6 of this part) shall be 

followed instead of the procedures in 

sections 7.5.33 and 11.1.3 of Method 29 

in appendix A–8 to part 60 of this 

chapter, and the QA/QC procedures in 

section 13.4.2 of ASTM D6784–02 

(incorporated by reference under § 75.6 

of this part) shall be performed instead 

of the procedures in section 9.2.3 of 

Method 29 in appendix A–8 to part 60 

of this chapter. The tester may also opt 

to use the sample recovery and 

preparation procedures in ASTM 

D6784–02 (incorporated by reference 

under § 75.6 of this part) instead of the 

Method 29 in appendix A–8 to part 60 

of this chapter procedures, as follows: 

sections 8.2.8 and 8.2.9.1 of Method 29 

in appendix A–8 to part 60 of this 

chapter may be replaced with sections 

13.2.9.1 through 13.2.9.3 of ASTM 

D6784–02 (incorporated by reference 

under § 75.6 of this part); sections 

8.2.9.2 and 8.2.9.3 of Method 29 in 

appendix A–8 to part 60 of this chapter 

may be replaced with sections 13.2.10.1 

through 13.2.10.4 of ASTM D6784–02 

(incorporated by reference under § 75.6 

of this part); section 8.3.4 of Method 29 

in appendix A–8 to part 60 of this 

chapter may be replaced with section 

13.3.4 or 13.3.6 of ASTM D6784–02 (as 

appropriate) (incorporated by reference 

under § 75.6 of this part); and section 

8.3.5 of Method 29 in appendix A–8 to 

part 60 of this chapter may be replaced 

with section 13.3.5 or 13.3.6 of ASTM 

D6784–02 (as appropriate) (incorporated 

by reference under § 75.6 of this part). 

(ii) Whenever ASTM D6784–02 

(incorporated by reference under § 75.6 

of this part) or Method 29 in appendix 

A–8 to part 60 of this chapter is used, 

paired sampling trains are required. To 

validate a RATA run or an emission test 

run, the relative deviation (RD), 

calculated according to section 11.7 of 

appendix K to this part, must not exceed 

10 percent, when the average 

concentration is greater than 1.0 μg/m3. 

If the average concentration is ≤1.0 μg/ 

m3, the RD must not exceed 20 percent. 

The RD results are also acceptable if the 

absolute difference between the Hg 

concentrations measured by the paired 

trains does not exceed 0.03 μg/m3. If the 

RD criterion is met, the run is valid. For 

each valid run, average the Hg 

concentrations measured by the two 

trains (vapor phase, only). 

(iii) Two additional reference 

methods that may be used to measure 

Hg concentration are: Method 30A, 

‘‘Determination of Total Vapor Phase 

Mercury Emissions from Stationary 

Sources (Instrumental Analyzer 

Procedure)’’ and Method 30B, 

‘‘Determination of Total Vapor Phase 

Mercury Emissions from Coal-Fired 

Combustion Sources Using Carbon 

Sorbent Traps’’. 

(iv) When Method 29 in appendix A–

8 to part 60 of this chapter or ASTM 

D6784–02 (incorporated by reference 

under § 75.6 of this part) is used for the 

Hg emission testing required under 

§§ 75.81(c) and (d), locate the reference 

method test points according to section 

8.1 of Method 30A, and if Hg 

stratification testing is part of the test 

protocol, follow the procedures in 

sections 8.1.3 through 8.1.3.5 of Method 

30A. 

(b) The owner or operator may use 

any of the following methods, which are 

found in appendix A to part 60 of this 

chapter or have been published by 

ASTM, as a reference method backup 

monitoring system to provide qualityassured monitor data: 

* * * * * 

(5) ASTM D6784–02, Standard Test 

Method for Elemental, Oxidized, 

Particle-Bound and Total Mercury in 

Flue Gas Generated from Coal-Fired 

Stationary Sources (Ontario Hydro 

Method) (incorporated by reference 

under § 75.6 of this part) for 

determining Hg concentration; 

(6) Method 29 in appendix A–8 to 

part 60 of this chapter for determining 

Hg concentration; 

(7) Method 30A for determining Hg 

concentration; and 

(8) Method 30B for determining Hg 

concentration. 

(c)(1) Instrumental EPA Reference 

Methods 3A, 6C, and 7E in appendices 

A–2 and A–4 of part 60 of this chapter 

shall be conducted using calibration 

gases as defined in section 5 of 

appendix A to this part. Otherwise, 

performance tests shall be conducted 

and data reduced in accordance with 

the test methods and procedures of this 

part unless the Administrator: 

* * * * * 

■ 17. Section 75.31 is amended by 

adding a sentence to the end of 

paragraph (c)(3) to read as follows: 

§ 75.31 Initial missing data procedures. 

* * * * * 

(c) * * * 

(3) * * * Alternatively, where a unit 

with add-on NOX emission controls can 

demonstrate that the controls are 

operating properly during the hour, as 

provided in § 75.34(d), the owner or 

operator may substitute, as applicable, 

the maximum controlled NOX emission 

rate (MCR) or the maximum expected 

NOX concentration (MEC). 

* * * * * 

■ 18. Section 75.32 is amended by 

revising paragraph (b) to read as follows: 

§ 75.32 Determination of monitor data 

availability for standard missing data 

procedures. 

* * * * * 

(b) The monitor data availability shall 

be calculated for each hour during each 

missing data period. The owner or 

operator shall record the percent 

monitor data availability for each hour 

of each missing data period to 

implement the missing data substitution 

procedures. 

* * * * * 

■ 19. Section 75.33 is amended by: 

■ a. Revising the section heading; 

■ b. Removing the word ‘‘Whenever’’

and adding in its place the word ‘‘If’’, 

and by removing the words ‘‘each hour 

of each’’ and adding in its place the 

words ‘‘that hour of the’’, in paragraph 

(b)(1) introductory text; 

■ c. Removing the word ‘‘Whenever’’

and adding in its place the word ‘‘If’’, 

and by removing the words ‘‘each hour 

of each’’ and adding in its place the 

words ‘‘that hour of the’’, in paragraph 

(b)(2) introductory text; 

■ d. Removing the word ‘‘Whenever’’

and adding in its place the word ‘‘If’’, 

and by removing the word ‘‘each’’ and 

adding in its place the words ‘‘that hour 

of the’’, in paragraphs (b)(3) and (b)(4); 

■ e. Removing the word ‘‘Whenever’’

and adding in its place the word ‘‘If’’, 

and by removing the words ‘‘each hour 

of each’’ and adding in its place the 

words ‘‘that hour of the’’, in paragraphs 

(c)(1) introductory text, (c)(2) 

introductory text, (c)(3), and (c)(4); 

■ f. Revising paragraph (c)(8)(iii); 

■ g. Revising Tables 1 and 2 in 

paragraph (c)(8)(iv); 

■ h. Removing the word ‘‘Whenever’’

and adding in its place the word ‘‘If’’, 

and by removing the words ‘‘each hour 

of each’’ and adding in its place the 

words ‘‘that hour of the’’, in paragraphs 

(d)(1) introductory text, (d)(2) 

introductory text, (d)(3) introductory 

text, and (d)(4) introductory text. 

■ i. Revising Table 3 in paragraph (e)(3); 

and 

The revisions and additions read as 

follows: 

§ 75.33 Standard missing data procedures 

for SO2, NOX, Hg, and flow rate. 

* * * * * 

(c) * * * 

(8) * * * 

(iii) For the purposes of providing 

substitute data under paragraph (c)(4) of 

this section, a separate, fuel-specific 

maximum potential concentration 

(MPC), maximum potential NOX

emission rate (MER), or maximum 


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potential flow rate (MPF) value (as 

applicable) shall be determined for each 

type of fuel combusted in the unit, in a 

manner consistent with § 72.2 of this 

chapter and with section 2.1.2.1 or 

2.1.4.1 of appendix A to this part. For 

co-firing, the MPC, MER or MPF value 

shall be based on the fuel with the 

highest emission rate or flow rate (as 

applicable). Furthermore, for a unit with 

add-on NOX emission controls, a 

separate fuel-specific maximum 

controlled NOX emission rate (MCR) or 

maximum expected NOX concentration 

(MEC) value (as applicable) shall be 

determined for each type of fuel 

combusted in the unit. The exact 

methodology used to determine each 

fuel-specific MPC, MER, MEC, MCR or 

MPF value shall be documented in the 

monitoring plan for the unit or stack. 

(iv) * * * 

TABLE 1.—MISSING DATA PROCEDURE FOR SO2 CEMS, CO2 CEMS, MOISTURE CEMS, HG CEMS, AND DILUENT (CO2

OR O2) MONITORS FOR HEAT INPUT DETERMINATION

Trigger conditions Calculation routines 

Monitor data availability 

(percent) 

Duration (N) of CEMS 

outage 

(hours) 2

Method Lookback period 

95 or more (90 or more for Hg) ............................ N ≤ 24 .......................... Average .............................................................. HB/HA. 

N > 24 .......................... For SO2, CO2, Hg, and H2O **, the greater of: 

Average ....................................................... HB/HA. 

90th percentile ............................................. 720 hours.* 

For O2 and H2OX, the lesser of: 

10th percentile ............................................. HB/HA. 

720 hours.* 

90 or more, but below 95 (> 80 but < 90 for Hg) N ≤ 8 ............................ Average .............................................................. HB/HA. 

N > 8 ............................ For SO2, CO2, Hg, and H2O **, the greater of: 

Average ....................................................... HB/HA. 

95th percentile ............................................. 720 hours.* 

For O2 and H2OX, the lesser of: 

Average ....................................................... HB/HA. 

5th Percentile .............................................. 720 hours.* 

80 or more, but below 90 (> 70 but < 80 for Hg) N > 0 ............................ For SO2, CO2, Hg, and H2O: ** 

Maximum value 1 ......................................... 720 hours.* 

For O2 and H2OX: 

Minimum value 1 .......................................... 720 hours.* 

Below 80 (Below 70 for Hg) ................................. N > 0 ............................ Maximum potential concentration 3 or % (for 

SO2, CO2, Hg, and H2O **) or 

Minimum potential concentration or % (for O2

and H2OX).

None. 

HB/HA = hour before and hour after the CEMS outage. 

* Quality-assured, monitor operating hours, during unit operation. May be either fuel-specific or non-fuel-specific. For units that report data only 

for the ozone season, include only quality assured monitor operating hours within the ozone season in the lookback period. Use data from no 

earlier than 3 years prior to the missing data period. 1Where a unit with add-on SO2 or Hg emission controls can demonstrate that the controls are operating properly during the missing data period, as provided in § 75.34, the unit may use the maximum controlled concentration from the previous 720 quality-assured monitor operating 

hours. 2 During unit operating hours. 

3Alternatively, where a unit with add-on SO2 or Hg emission controls can demonstrate that the controls are operating properly during the missing data period, as provided in § 75.34, the unit may report the greater of: (a) the maximum expected SO2 or Hg concentration or (b) 1.25 times 

the maximum controlled value from the previous 720 quality-assured monitor operating hours. X Use this algorithm for moisture except when Equation 19–3, 19–4 or 19–8 in Method 19 in appendix A–7 to part 60 of this chapter is used for 

NOX emission rate. 

** Use this algorithm for moisture only when Equation 19–3, 19–4 or 19–8 in Method 19 in appendix A–7 to part 60 of this chapter is used for 

NOX emission rate. 

TABLE 2.—LOAD-BASED MISSING DATA PROCEDURE FOR NOX-DILUENT CEMS, NOX CONCENTRATION CEMS AND FLOW

RATE CEMS 

Trigger conditions Calculation routines 

Monitor data availability 

(percent) 

Duration (N) of CEMS outage 

(hours) 2 Method Lookback period Load ranges 

95 or more ............................. N ≤ 24 ................................... Average ................................. 2,160 hours * ......................... Yes. 

N > 24 ................................... The greater of: 

Average .......................... HB/HA ................................... No. 

90th percentile ............... 2,160 hours * ......................... Yes. 

90 or more, but below 95 ...... N ≤ 8 ..................................... Average ................................. 2,160 hours * ......................... Yes. 

N > 8 ..................................... The greater of: 

Average .......................... HB/HA ................................... No. 

95th percentile ............... 2,160 hours * ......................... Yes. 

80 or more, but below 90 ...... N > 0 ..................................... Maximum value 1 ................... 2,160 hours * ......................... Yes. 


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TABLE 2.—LOAD-BASED MISSING DATA PROCEDURE FOR NOX-DILUENT CEMS, NOX CONCENTRATION CEMS AND FLOW

RATE CEMS—Continued 

Trigger conditions Calculation routines 

Monitor data availability 

(percent) 

Duration (N) of CEMS outage 

(hours) 2 Method Lookback period Load ranges 

Below 80 ................................ N > 0 ..................................... Maximum potential NOX

emission rate 3; or maximum potential NOX concentration 3; or maximum 

potential flow rate.

None ...................................... No. 

HB/HA = hour before and hour after the CEMS outage. 

* Quality-assured, monitor operating hours, using data at the corresponding load range (‘‘load bin’’) for each hour of the missing data period. 

May be either fuel-specific or non-fuel-specific. For units that report data only for the ozone season, include only quality assured monitor operating hours within the ozone season in the lookback period. Use data from no earlier than three years prior to the missing data period. 1Where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly during the missing data period, as 

provided in § 75.34, the unit may use the maximum controlled NOX concentration or emission rate from the previous 2,160 quality-assured monitor operating hours. Units with add-on controls that report NOX mass emissions on a year-round basis under subpart H of this part may use separate ozone season and non-ozone season data pools to provide substitute data values, as described in § 75.34(a)(2). 2 During unit operating hours. 

3Alternatively, where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly during the missing 

data period, as provided in § 75.34, the unit may report the greater of: (a) the maximum expected NOX concentration (or maximum controlled 

NOX emission rate, as applicable); or (b) 1.25 times the maximum controlled value at the corresponding load bin, from the previous 2,160 quality-assured monitor operating hours. 

* * * * * 

(e) * * * 

(3) * * * 

TABLE 3.—NON-LOAD-BASED MISSING DATA PROCEDURE FOR NOX-DILUENT CEMS AND NOX CONCENTRATION CEMS 

Trigger conditions Calculation routines 

Monitor data availability 

(percent) 

Duration (N) of CEMS 

outage 

(hours) 1

Method Lookback period 

95 or more ............................................................ N ≤ 24 .......................... Average .............................................................. 2,160 hours.* 

N > 24 .......................... 90th percentile .................................................... 2,160 hours.* 

90 or more, but below 95 ..................................... N ≤ 8 ............................ Average .............................................................. 2,160 hours.* 

N > 8 ............................ 95th percentile .................................................... 2,160 hours.* 

80 or more, but below 90 ..................................... N > 0 ............................ Maximum value 3 ................................................ 2,160 hours.* 

Below 80, or operational bin indeterminable ........ N > 0 ............................ Maximum potential NOX emission rate 2 or maximum potential NOX concentration 2.None. 

* If operational bins are used, the lookback period is 2,160 quality-assured, monitor operating hours, and data at the corresponding operational 

bin are used to provide substitute data values. If operational bins are not used, the lookback period is the previous 2,160 quality-assured monitor 

operating hours. For units that report data only for the ozone season, include only quality-assured monitor operating hours within the ozone season in the lookback period. Use data from no earlier than three years prior to the missing data period. 1 During unit operation. 

2Alternatively, where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly, as provided in 

§ 75.34, the unit may report the greater of: (a) the maximum expected NOX concentration, (or maximum controlled NOX emission rate, as applicable); or (b) 1.25 times the maximum controlled value at the corresponding operational bin (if applicable), from the previous 2,160 quality-assured monitor operating hours. 3Where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly during the missing data period, as 

provided in § 75.34, the unit may use the maximum controlled NOX concentration or emission rate from the previous 2,160 quality-assured monitor operating hours. Units with add-on controls that report NOX mass emissions on a year-round basis under subpart H of this part may use separate ozone season and non-ozone season data pools to provide substitute data values, as described in § 75.34(a)(2). 

* * * * * 

■ 20. Section 75.34 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. In paragraph (a)(2)(ii) by removing 

the words ‘‘and (c)(3)’’ and adding in its 

place the words ‘‘, (c)(3) and (c)(5) of 

this section, and § 75.38(c),’’

■ c. Revising paragraph (a)(3); 

■ d. Adding paragraph (a)(5); and 

■ e. In paragraph (d) by removing the 

words ‘‘paragraphs (a)(1) and (a)(3) of 

this section,’’ and adding in its place the 

words ‘‘paragraphs (a)(1), (a)(3) and 

(a)(5) of this section; and §§ 75.31(c)(3), 

75.38(c), and 75.72(c)(3),’’. 

The revisions and additions read as 

follows: 

§ 75.34 Units with add-on emission 

controls. 

(a) The owner or operator of an 

affected unit equipped with add-on SO2

and/or NOX emission controls shall 

provide substitute data in accordance 

with paragraphs (a)(1), through (a)(5) of 

this section for each hour in which 

quality-assured data from the outlet SO2

and/or NOX monitoring system(s) are 

not obtained. 

* * * * * 

(3) For each missing data hour in 

which the percent monitor data 

availability for SO2 or NOX, calculated 

in accordance with § 75.32, is less than 

90.0 percent and is greater than or equal 

to 80.0 percent; and parametric data 

establishes that the add-on emission 

controls were operating properly (i.e. 

within the range of operating parameters 

provided in the quality assurance/ 


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quality control program) during the 

hour, the owner or operator may: 

(i) Replace the maximum SO2

concentration recorded in the 720 

quality-assured monitor operating hours 

immediately preceding the missing data 

period, with the maximum controlled 

SO2 concentration recorded in the 

previous 720 quality-assured monitor 

operating hours; or 

(ii) Replace the maximum NOX

concentration(s) or NOX emission rate(s) 

from the appropriate load bin(s) (based 

on a lookback through the 2,160 qualityassured monitor operating hours 

immediately preceding the missing data 

period), with the maximum controlled 

NOX concentration(s) or emission rate(s) 

from the appropriate load bin(s) in the 

same 2,160 quality-assured monitor 

operating hour lookback period. 

* * * * * 

(5) For each missing data hour in 

which the percent monitor data 

availability for SO2 or NOX, calculated 

in accordance with § 75.32, is below 

80.0 percent and parametric data 

establish that the add-on emission 

controls were operating properly (i.e. 

within the range of operating parameters 

provided in the quality assurance/ 

quality control program),in lieu of 

reporting the maximum potential value, 

the owner or operator may substitute, as 

applicable, the greater of: 

(i) The maximum expected SO2

concentration or 1.25 times the 

maximum hourly controlled SO2

concentration recorded in the previous 

720 quality-assured monitor operating 

hours; 

(ii) The maximum expected NOX

concentration or 1.25 times the 

maximum hourly controlled NOX

concentration recorded in the previous 

2,160 quality-assured monitor operating 

hours at the corresponding unit load 

range or operational bin; 

(iii) The maximum controlled hourly 

NOX emission rate (MCR) or 1.25 times 

the maximum hourly controlled NOX

emission rate recorded in the previous 

2,160 quality-assured monitor operating 

hours at the corresponding unit load 

range or operational bin; 

(iv) For the purposes of implementing 

the missing data options in paragraphs 

(a)(5)(i) through (a)(5)(iii) of this section, 

the maximum expected SO2 and NOX

concentrations shall be determined, 

respectively, according to sections 

2.1.1.2 and 2.1.2.2 of appendix A to this 

part. The MCR shall be calculated 

according to the basic procedure 

described in section 2.1.2.1(b) of 

appendix A to this part, except that the 

words ‘‘maximum potential NOX

emission rate (MER)’’ shall be replaced 

with the words ‘‘maximum controlled 

NOX emission rate (MCR)’’ and the NOX

MEC shall be used instead of the NOX

MPC. 

* * * * * 

■ 20. Section 75.38 is amended by 

revising paragraphs (a) and (c) to read as 

follows. 

§ 75.38 Standard missing data procedures 

for Hg CEMS. 

(a) Once 720 quality assured monitor 

operating hours of Hg concentration 

data have been obtained following 

initial certification, the owner or 

operator shall provide substitute data 

for Hg concentration in accordance with 

the procedures in ( 75.33(b)(1) through 

(b)(4), except that the term ‘‘Hg 

concentration’’ shall apply rather than 

‘‘SO2 concentration,’’ the term ‘‘Hg 

concentration monitoring system’’ shall 

apply rather than ‘‘SO2 pollutant 

concentration monitor,’’ the term 

‘‘maximum potential Hg concentration, 

as defined in section 2.1.7 of appendix 

A to this part’’ shall apply, rather than 

‘‘maximum potential SO2

concentration’’, and the percent monitor 

data availability trigger conditions 

prescribed for Hg in Table 1 of § 75.33 

shall apply rather than the trigger 

conditions prescribed for SO2. 

* * * * * 

(c) For units with FGD systems or 

add-on Hg emission controls, when the 

percent monitor data availability is less 

than 80.0 percent and is greater than or 

equal to 70.0 percent, and a missing 

data period occurs, consistent with 

§ 75.34(a)(3), for each missing data hour 

in which the FGD or Hg emission 

controls are documented to be operating 

properly, the owner or operator may 

report the maximum controlled Hg 

concentration recorded in the previous 

720 quality-assured monitor operating 

hours. In addition, when the percent 

monitor data availability is less than 

70.0 percent and a missing data period 

occurs, consistent with § 75.34(a)(5), for 

each missing data hour in which the 

FGD or Hg emission controls are 

documented to be operating properly, 

the owner or operator may report the 

greater of the maximum expected Hg 

concentration (MEC) or 1.25 times the 

maximum controlled Hg concentration 

recorded in the previous 720 qualityassured monitor operating hours. The 

MEC shall be determined in accordance 

with section 2.1.7.1 of appendix A to 

this part. 

■ 21. Section 75.39 is amended by: 

■ a. Revising paragraph (a); 

■ b. Revising paragraph (b); 

■ c. Revising paragraph (c); 

■ d. Revising paragraph (d); and 

■ e. Adding paragraph (f). 

The revisions and additions read as 

follows: 

§ 75.39 Missing data procedures for 

sorbent trap monitoring systems. 

(a) If a primary sorbent trap 

monitoring system has not been 

certified by the applicable compliance 

date specified under a State or Federal 

Hg mass emission reduction program 

that adopts the requirements of subpart 

I of this part, and if quality-assured Hg 

concentration data from a certified 

backup Hg monitoring system, reference 

method, or approved alternative 

monitoring system are unavailable, the 

owner or operator shall report the 

maximum potential Hg concentration, 

as defined in section 2.1.7 of appendix 

A to this part, until the primary system 

is certified. 

(b) For a certified sorbent trap system, 

a missing data period will occur in the 

following circumstances, unless qualityassured Hg concentration data from a 

certified backup Hg CEMS, sorbent trap 

system, reference method, or approved 

alternative monitoring system are 

available: 

(1) A gas sample is not extracted from 

the stack during unit operation (e.g., 

during a monitoring system malfunction 

or when the system undergoes 

maintenance); or 

(2) The results of the Hg analysis for 

the paired sorbent traps are missing or 

invalid (as determined using the quality 

assurance procedures in appendix K to 

this part). The missing data period 

begins with the hour in which the 

paired sorbent traps for which the Hg 

analysis is missing or invalid were put 

into service. The missing data period 

ends at the first hour in which valid Hg 

concentration data are obtained with 

another pair of sorbent traps (i.e., the 

hour at which this pair of traps was 

placed in service), or with a certified 

backup Hg CEMS, reference method, or 

approved alternative monitoring system. 

(c) Initial missing data procedures. 

Use the missing data procedures in 

§ 75.31(b) until 720 hours of qualityassured Hg concentration data have 

been collected with the sorbent trap 

monitoring system(s), following initial 

certification. 

(d) Standard missing data procedures. 

Once 720 quality-assured hours of data 

have been obtained with the sorbent 

trap system(s), begin reporting the 

percent monitor data availability in 

accordance with § 75.32 and switch 

from the initial missing data procedures 

in paragraph (c) of this section to the 

standard missing data procedures in 

§ 75.38. 

* * * * * 


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(f) In cases where the owner or 

operator elects to use a primary Hg 

CEMS and a certified redundant (or 

non-redundant) backup sorbent trap 

monitoring system (or vice-versa), when 

both the primary and backup 

monitoring systems are out-of-service 

and quality-assured Hg concentration 

data from a temporary like-kind 

replacement analyzer, reference method, 

or approved alternative monitoring 

system are unavailable, the previous 720 

quality-assured monitor operating hours 

reported in the electronic quarterly 

report under § 75.64 shall be used for 

the required missing data lookback, 

irrespective of whether these data were 

recorded by the Hg CEMS, the sorbent 

trap system, a temporary like-kind 

replacement analyzer, a reference 

method, or an approved alternative 

monitoring system. 

■ 22. Section 75.53 is amended by: 

■ a. Revising paragraph (a)(1); 

■ b. Removing the phrase ‘‘(d) or (f)’’

and adding in its place the phrase ‘‘(f) 

or (h)’’ in the second sentence of 

paragraph (a)(2); 

■ c. Adding paragraph (e)(1)(xiv); and 

■ d. Adding paragraphs (g) and (h). 

The revisions and additions read as 

follows: 

§ 75.53 Monitoring plan. 

(a) * * * 

(1) The provisions of paragraphs (e) 

and (f) of this section shall be met 

through December 31, 2008. The owner 

or operator shall meet the requirements 

of paragraphs (a), (b), (e), and (f) of this 

section through December 31, 2008, 

except as otherwise provided in 

paragraph (g) of this section. On and 

after January 1, 2009, the owner or 

operator shall meet the requirements of 

paragraphs (a), (b), (g), and (h) of this 

section only. In addition, the provisions 

in paragraphs (g) and (h) of this section 

that support a regulatory option 

provided in another section of this part 

must be followed if the regulatory 

option is used prior to January 1, 2009. 

* * * * * 

(e) * * * 

(1) * * * 

(xiv) For each unit with a flow 

monitor installed on a rectangular stack 

or duct, if a wall effects adjustment 

factor (WAF) is determined and applied 

to the hourly flow rate data: 

(A) Stack or duct width at the test 

location, ft; 

(B) Stack or duct depth at the test 

location, ft; 

(C) Wall effects adjustment factor 

(WAF), to the nearest 0.0001; 

(D) Method of determining the WAF; 

(E) WAF Effective date and hour; 

(F) WAF no longer effective date and 

hour (if applicable); 

(G) WAF determination date; 

(H) Number of WAF test runs; 

(I) Number of Method 1 traverse 

points in the WAF test; 

(J) Number of test ports in the WAF 

test; and 

(K) Number of Method 1 traverse 

points in the reference flow RATA. 

* * * * * 

(g) Contents of the monitoring plan. 

The requirements of paragraphs (g) and 

(h) of this section shall be met on and 

after January 1, 2009. Notwithstanding 

this requirement, the provisions of 

paragraphs (g) and (h) of this section 

may be implemented prior to January 1, 

2009, as follows. In 2008, the owner or 

operator may opt to record and report 

the monitoring plan information in 

paragraphs (g) and (h) of this section, in 

lieu of recording and reporting the 

information in paragraphs (e) and (f) of 

this section. Each monitoring plan shall 

contain the information in paragraph 

(g)(1) of this section in electronic format 

and the information in paragraph (g)(2) 

of this section in hardcopy format. 

Electronic storage of all monitoring plan 

information, including the hardcopy 

portions, is permissible provided that a 

paper copy of the information can be 

furnished upon request for audit 

purposes. 

(1) Electronic. (i) The facility ORISPL 

number developed by the Department of 

Energy and used in the National 

Allowance Data Base (or equivalent 

facility ID number assigned by EPA, if 

the facility does not have an ORISPL 

number). Also provide the following 

information for each unit and (as 

applicable) for each common stack and/ 

or pipe, and each multiple stack and/or 

pipe involved in the monitoring plan: 

(A) A representation of the exhaust 

configuration for the units in the 

monitoring plan. Provide the ID number 

of each unit and assign a unique ID 

number to each common stack, common 

pipe multiple stack and/or multiple 

pipe associated with the unit(s) 

represented in the monitoring plan. For 

common and multiple stacks and/or 

pipes, provide the activation date and 

deactivation date (if applicable) of each 

stack and/or pipe; 

(B) Identification of the monitoring 

system location(s) (e.g., at the unit-level, 

on the common stack, at each multiple 

stack, etc.). Provide an indicator (‘‘flag’’) 

if the monitoring location is at a bypass 

stack or in the ductwork (breeching); 

(C) The stack exit height (ft) above 

ground level and ground level elevation 

above sea level, and the inside crosssectional area (ft2) at the flue exit and 

at the flow monitoring location (for 

units with flow monitors, only). Also 

use appropriate codes to indicate the 

material(s) of construction and the 

shape(s) of the stack or duct crosssection(s) at the flue exit and (if 

applicable) at the flow monitor location; 

(D) The type(s) of fuel(s) fired by each 

unit. Indicate the start and (if 

applicable) end date of combustion for 

each type of fuel, and whether the fuel 

is the primary, secondary, emergency, or 

startup fuel; 

(E) The type(s) of emission controls 

that are used to reduce SO2, NOX, Hg, 

and particulate emissions from each 

unit. Also provide the installation date, 

optimization date, and retirement date 

(if applicable) of the emission controls, 

and indicate whether the controls are an 

original installation; 

(F) Maximum hourly heat input 

capacity of each unit; and 

(G) A non-load based unit indicator (if 

applicable) for units that do not produce 

electrical or thermal output. 

(ii) For each monitored parameter 

(e.g., SO2, NOX, flow, etc.) at each 

monitoring location, specify the 

monitoring methodology and the 

missing data approach for the 

parameter. If the unmonitored bypass 

stack approach is used for a particular 

parameter, indicate this by means of an 

appropriate code. Provide the activation 

date/hour, and deactivation date/hour 

(if applicable) for each monitoring 

methodology and each missing data 

approach. 

(iii) For each required continuous 

emission monitoring system, each fuel 

flowmeter system, each continuous 

opacity monitoring system, and each 

sorbent trap monitoring system (as 

defined in § 72.2 of this chapter), 

identify and describe the major 

monitoring components in the 

monitoring system (e.g., gas analyzer, 

flow monitor, opacity monitor, moisture 

sensor, fuel flowmeter, DAHS software, 

etc.). Other important components in 

the system (e.g., sample probe, PLC, 

data logger, etc.) may also be 

represented in the monitoring plan, if 

necessary. Provide the following 

specific information about each 

component and monitoring system: 

(A) For each required monitoring 

system: 

(1) Assign a unique, 3-character 

alphanumeric identification code to the 

system; 

(2) Indicate the parameter monitored 

by the system; 

(3) Designate the system as a primary, 

redundant backup, non-redundant 

backup, data backup, or reference 

method backup system, as provided in 

§ 75.10(e); and 


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(4) Indicate the system activation 

date/hour and deactivation date/hour 

(as applicable). 

(B) For each component of each 

monitoring system represented in the 

monitoring plan: 

(1) Assign a unique, 3-character 

alphanumeric identification code to the 

component; 

(2) Indicate the manufacturer, model 

and serial number; 

(3) Designate the component type; 

(4) For dual-span applications, 

indicate whether the analyzer 

component ID represents a high 

measurement scale, a low scale, or a 

dual range; 

(5) For gas analyzers, indicate the 

moisture basis of measurement; 

(6) Indicate the method of sample 

acquisition or operation, (e.g., extractive 

pollutant concentration monitor or 

thermal flow monitor); and 

(7) Indicate the component activation 

date/hour and deactivation date/hour 

(as applicable). 

(iv) Explicit formulas, using the 

component and system identification 

codes for the primary monitoring 

system, and containing all constants and 

factors required to derive the required 

mass emissions, emission rates, heat 

input rates, etc. from the hourly data 

recorded by the monitoring systems. 

Formulas using the system and 

component ID codes for backup 

monitoring systems are required only if 

different formulas for the same 

parameter are used for the primary and 

backup monitoring systems (e.g., if the 

primary system measures pollutant 

concentration on a different moisture 

basis from the backup system). Provide 

the equation number or other 

appropriate code for each emissions 

formula (e.g., use code F–1 if Equation 

F–1 in appendix F to this part is used 

to calculate SO2 mass emissions). Also 

identify each emissions formula with a 

unique three character alphanumeric 

code. The formula effective start date/ 

hour and inactivation date/hour (as 

applicable) shall be included for each 

formula. The owner or operator of a unit 

for which the optional low mass 

emissions excepted methodology in 

§ 75.19 is being used is not required to 

report such formulas. 

(v) For each parameter monitored 

with CEMS, provide the following 

information: 

(A) Measurement scale (high or low); 

(B) Maximum potential value (and 

method of calculation). If NOX emission 

rate in lb/mmBtu is monitored, calculate 

and provide the maximum potential 

NOX emission rate in addition to the 

maximum potential NOX concentration; 

(C) Maximum expected value (if 

applicable) and method of calculation; 

(D) Span value(s) and full-scale 

measurement range(s); 

(E) Daily calibration units of measure; 

(F) Effective date/hour, and (if 

applicable) inactivation date/hour of 

each span value; 

(G) An indication of whether dual 

spans are required; and 

(H) The default high range value (if 

applicable) and the maximum allowable 

low-range value for this option. 

(vi) If the monitoring system or 

excepted methodology provides for the 

use of a constant, assumed, or default 

value for a parameter under specific 

circumstances, then include the 

following information for each such 

value for each parameter: 

(A) Identification of the parameter; 

(B) Default, maximum, minimum, or 

constant value, and units of measure for 

the value; 

(C) Purpose of the value; 

(D) Indicator of use, i.e., during 

controlled hours, uncontrolled hours, or 

all operating hours; 

(E) Type of fuel; 

(F) Source of the value; 

(G) Value effective date and hour; 

(H) Date and hour value is no longer 

effective (if applicable); and 

(I) For units using the excepted 

methodology under § 75.19, the 

applicable SO2 emission factor. 

(vii) Unless otherwise specified in 

section 6.5.2.1 of appendix A to this 

part, for each unit or common stack on 

which hardware CEMS are installed: 

(A) Maximum hourly gross load (in 

MW, rounded to the nearest MW, or 

steam load in 1000 lb/hr (i.e., klb/hr), 

rounded to the nearest klb/hr, or 

thermal output in mmBtu/hr, rounded 

to the nearest mmBtu/hr), for units that 

produce electrical or thermal output; 

(B) The upper and lower boundaries 

of the range of operation (as defined in 

section 6.5.2.1 of appendix A to this 

part), expressed in megawatts, 

thousands of lb/hr of steam, mmBtu/hr 

of thermal output, or ft/sec (as 

applicable); 

(C) Except for peaking units, identify 

the most frequently and second most 

frequently used load (or operating) 

levels (i.e., low, mid, or high) in 

accordance with section 6.5.2.1 of 

appendix A to this part, expressed in 

megawatts, thousands of lb/hr of steam, 

mmBtu/hr of thermal output, or ft/sec 

(as applicable); 

(D) Except for peaking units, an 

indicator of whether the second most 

frequently used load (or operating) level 

is designated as normal in section 

6.5.2.1 of appendix A to this part; 

(E) The date of the data analysis used 

to determine the normal load (or 

operating) level(s) and the two most 

frequently-used load (or operating) 

levels (as applicable); and 

(F) Activation and deactivation dates 

and hours, when the maximum hourly 

gross load, boundaries of the range of 

operation, normal load (or operating) 

level(s) or two most frequently-used 

load (or operating) levels change and are 

updated. 

(viii) For each unit for which CEMS 

are not installed: 

(A) Maximum hourly gross load (in 

MW, rounded to the nearest MW, or 

steam load in klb/hr, rounded to the 

nearest klb/hr, or steam load in mmBtu/ 

hr, rounded to the nearest mmBtu/hr); 

(B) The upper and lower boundaries 

of the range of operation (as defined in 

section 6.5.2.1 of appendix A to this 

part), expressed in megawatts, mmBtu/ 

hr of thermal output, or thousands of lb/ 

hr of steam; 

(C) Except for peaking units and units 

using the low mass emissions excepted 

methodology under § 75.19, identify the 

load level designated as normal, 

pursuant to section 6.5.2.1 of appendix 

A to this part, expressed in megawatts, 

mmBtu/hr of thermal output, or 

thousands of lb/hr of steam; 

(D) The date of the load analysis used 

to determine the normal load level (as 

applicable); and 

(E) Activation and deactivation dates 

and hours, when the maximum hourly 

gross load, boundaries of the range of 

operation, or normal load level change 

and are updated. 

(ix) For each unit with a flow monitor 

installed on a rectangular stack or duct, 

if a wall effects adjustment factor (WAF) 

is determined and applied to the hourly 

flow rate data: 

(A) Stack or duct width at the test 

location, ft; 

(B) Stack or duct depth at the test 

location, ft; 

(C) Wall effects adjustment factor 

(WAF), to the nearest 0.0001; 

(D) Method of determining the WAF; 

(E) WAF Effective date and hour; 

(F) WAF no longer effective date and 

hour (if applicable); 

(G) WAF determination date; 

(H) Number of WAF test runs; 

(I) Number of Method 1 traverse 

points in the WAF test; 

(J) Number of test ports in the WAF 

test; and 

(K) Number of Method 1 traverse 

points in the reference flow RATA. 

(2) Hardcopy. (i) Information, 

including (as applicable): Identification 

of the test strategy; protocol for the 

relative accuracy test audit; other 

relevant test information; calibration gas 

levels (percent of span) for the 

calibration error test and linearity 


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check; calculations for determining 

maximum potential concentration, 

maximum expected concentration (if 

applicable), maximum potential flow 

rate, maximum potential NOX emission 

rate, and span; and apportionment 

strategies under §§ 75.10 through 75.18. 

(ii) Description of site locations for 

each monitoring component in the 

continuous emission or opacity 

monitoring systems, including 

schematic diagrams and engineering 

drawings specified in paragraphs 

(e)(2)(iv) and (e)(2)(v) of this section and 

any other documentation that 

demonstrates each monitor location 

meets the appropriate siting criteria. 

(iii) A data flow diagram denoting the 

complete information handling path 

from output signals of CEMS 

components to final reports. 

(iv) For units monitored by a 

continuous emission or opacity 

monitoring system, a schematic diagram 

identifying entire gas handling system 

from boiler to stack for all affected units, 

using identification numbers for units, 

monitoring systems and components, 

and stacks corresponding to the 

identification numbers provided in 

paragraphs (g)(1)(i) and (g)(1)(iii) of this 

section. The schematic diagram must 

depict stack height and the height of any 

monitor locations. Comprehensive 

and/or separate schematic diagrams 

shall be used to describe groups of units 

using a common stack. 

(v) For units monitored by a 

continuous emission or opacity 

monitoring system, stack and duct 

engineering diagrams showing the 

dimensions and location of fans, turning 

vanes, air preheaters, monitor 

components, probes, reference method 

sampling ports, and other equipment 

that affects the monitoring system 

location, performance, or quality control 

checks. 

(h) Contents of monitoring plan for 

specific situations. The following 

additional information shall be included 

in the monitoring plan for the specific 

situations described: 

(1) For each gas-fired unit or oil-fired 

unit for which the owner or operator 

uses the optional protocol in appendix 

D to this part for estimating heat input 

and/or SO2 mass emissions, or for each 

gas-fired or oil-fired peaking unit for 

which the owner/operator uses the 

optional protocol in appendix E to this 

part for estimating NOX emission rate 

(using a fuel flowmeter), the designated 

representative shall include the 

following additional information for 

each fuel flowmeter system in the 

monitoring plan: 

(i) Electronic. (A) Parameter 

monitored; 

(B) Type of fuel measured, maximum 

fuel flow rate, units of measure, and 

basis of maximum fuel flow rate (i.e., 

upper range value or unit maximum) for 

each fuel flowmeter; 

(C) Test method used to check the 

accuracy of each fuel flowmeter; 

(D) Monitoring system identification 

code; 

(E) The method used to demonstrate 

that the unit qualifies for monthly GCV 

sampling or for daily or annual fuel 

sampling for sulfur content, as 

applicable; and 

(F) Activation date/hour and (if 

applicable) inactivation date/hour for 

the fuel flowmeter system; 

(ii) Hardcopy. (A) A schematic 

diagram identifying the relationship 

between the unit, all fuel supply lines, 

the fuel flowmeter(s), and the stack(s). 

The schematic diagram must depict the 

installation location of each fuel 

flowmeter and the fuel sampling 

location(s). Comprehensive and/or 

separate schematic diagrams shall be 

used to describe groups of units using 

a common pipe; 

(B) For units using the optional 

default SO2 emission rate for ‘‘pipeline 

natural gas’’ or ‘‘natural gas’’ in 

appendix D to this part, the information 

on the sulfur content of the gaseous fuel 

used to demonstrate compliance with 

either section 2.3.1.4 or 2.3.2.4 of 

appendix D to this part; 

(C) For units using the 720 hour test 

under 2.3.6 of Appendix D of this part 

to determine the required sulfur 

sampling requirements, report the 

procedures and results of the test; and 

(D) For units using the 720 hour test 

under 2.3.5 of Appendix D of this part 

to determine the appropriate fuel GCV 

sampling frequency, report the 

procedures used and the results of the 

test. 

(2) For each gas-fired peaking unit 

and oil-fired peaking unit for which the 

owner or operator uses the optional 

procedures in appendix E to this part for 

estimating NOX emission rate, the 

designated representative shall include 

in the monitoring plan: 

(i) Electronic. Unit operating and 

capacity factor information 

demonstrating that the unit qualifies as 

a peaking unit, as defined in § 72.2 of 

this chapter for the current calendar 

year or ozone season, including: 

capacity factor data for three calendar 

years (or ozone seasons) as specified in 

the definition of peaking unit in § 72.2 

of this chapter; the method of 

qualification used; and an indication of 

whether the data are actual or projected 

data. 

(ii) Hardcopy. (A) A protocol 

containing methods used to perform the 

baseline or periodic NOX emission test; 

and 

(B) Unit operating parameters related 

to NOX formation by the unit. 

(3) For each gas-fired unit and dieselfired unit or unit with a wet flue gas 

pollution control system for which the 

designated representative claims an 

opacity monitoring exemption under 

§ 75.14, the designated representative 

shall include in the hardcopy 

monitoring plan the information 

specified under § 75.14(b), (c), or (d), 

demonstrating that the unit qualifies for 

the exemption. 

(4) For each unit using the low mass 

emissions excepted methodology under 

§ 75.19 the designated representative 

shall include the following additional 

information in the monitoring plan that 

accompanies the initial certification 

application: 

(i) Electronic. For each low mass 

emissions unit, report the results of the 

analysis performed to qualify as a low 

mass emissions unit under § 75.19(c). 

This report will include either the 

previous three years actual or projected 

emissions. The following items should 

be included: 

(A) Current calendar year of 

application; 

(B) Type of qualification; 

(C) Years one, two, and three; 

(D) Annual and/or ozone season 

measured, estimated or projected NOX

mass emissions for years one, two, and 

three; 

(E) Annual measured, estimated or 

projected SO2 mass emissions (if 

applicable) for years one, two, and 

three; and 

(F) Annual or ozone season operating 

hours for years one, two, and three. 

(ii) Hardcopy. (A) A schematic 

diagram identifying the relationship 

between the unit, all fuel supply lines 

and tanks, any fuel flowmeter(s), and 

the stack(s). Comprehensive and/or 

separate schematic diagrams shall be 

used to describe groups of units using 

a common pipe; 

(B) For units which use the long term 

fuel flow methodology under 

§ 75.19(c)(3), the designated 

representative must provide a diagram 

of the fuel flow to each affected unit or 

group of units and describe in detail the 

procedures used to determine the long 

term fuel flow for a unit or group of 

units for each fuel combusted by the 

unit or group of units; 

(C) A statement that the unit burns 

only gaseous fuel(s) and/or fuel oil and 

a list of the fuels that are burned or a 

statement that the unit is projected to 

burn only gaseous fuel(s) and/or fuel oil 

and a list of the fuels that are projected 

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(D) A statement that the unit meets 

the applicability requirements in 

§ 75.19(a) and (b); and 

(E) Any unit historical actual, 

estimated and projected emissions data 

and calculated emissions data 

demonstrating that the affected unit 

qualifies as a low mass emissions unit 

under § 75.19(a) and 75.19(b). 

(5) For qualification as a gas-fired 

unit, as defined in § 72.2 of this part, the 

designated representative shall include 

in the monitoring plan, in electronic 

format, the following: Current calendar 

year, fuel usage data for three calendar 

years (or ozone seasons) as specified in 

the definition of gas-fired in § 72.2 of 

this part, the method of qualification 

used, and an indication of whether the 

data are actual or projected data. 

(6) For each monitoring location with 

a stack flow monitor that is exempt from 

performing 3-load flow RATAs (peaking 

units, bypass stacks, or by petition) the 

designated representative shall include 

in the monitoring plan an indicator of 

exemption from 3-load flow RATA 

using the appropriate exemption code. 

■ 23. Section 75.57 is amended by: 

■ a. Adding the phrase ‘‘, or mmBtu/hr 

of thermal output, rounded to the 

nearest mmBtu/hr’’ after the phrase 

‘‘rounded to the nearest 1000 lb/hr’’, in 

paragraph (b)(3); 

■ b. Revising Table 4a in paragraph 

(c)(4)(iv); 

■ c. Removing the word ‘‘hundredth’’

and adding in its place the word ‘‘tenth’’

in paragraph (i)(1)(iv); and 

■ d. Removing the words ‘‘, § 75.12(b),’’

from paragraphs (i)(2) and (j)(2). 

The revisions read as follows: 

§ 75.57 General recordkeeping provisions. 

* * * * * 

(c) * * * 

(4) * * * 

(iv) * * * 

TABLE 4A.—CODES FOR METHOD OF EMISSIONS AND FLOW DETERMINATION

Code Hourly emissions/flow measurement or estimation method 

1 ...... Certified primary emission/flow monitoring system. 

2 ...... Certified backup emission/flow monitoring system. 

3 ...... Approved alternative monitoring system. 

4 ...... Reference method: 

SO2: Method 6C. 

Flow: Method 2 or its allowable alternatives under appendix A to part 60 of this chapter. 

NOX: Method 7E. 

CO2 or O2: Method 3A. 

5 ...... For units with add-on SO2 and/or NOX emission controls: SO2 concentration or NOX emission rate estimate from Agency preapproved 

parametric monitoring method. 

6 ...... Average of the hourly SO2 concentrations, CO2 concentrations, O2 concentrations, NOX concentrations, flow rates, moisture percentages 

or NOX emission rates for the hour before and the hour following a missing data period. 

7 ...... Initial missing data procedures used. Either: (a) the average of the hourly SO2 concentration, CO2 concentration, O2 concentration, or 

moisture percentage for the hour before and the hour following a missing data period; or (b) the arithmetic average of all NOX concentration, NOX emission rate, or flow rate values at the corresponding load range (or a higher load range), or at the corresponding 

operational bin (non-load-based units, only); or (c) the arithmetic average of all previous NOX concentration, NOX emission rate, or 

flow rate values (non-load-based units, only). 

8 ...... 90th percentile hourly SO2 concentration, CO2 concentration, NOX concentration, flow rate, moisture percentage, or NOX emission rate 

or 10th percentile hourly O2 concentration or moisture percentage in the applicable lookback period (moisture missing data algorithm 

depends on which equations are used for emissions and heat input). 

9 ...... 95th percentile hourly SO2 concentration, CO2 concentration, NOX concentration, flow rate, moisture percentage, or NOX emission rate 

or 5th percentile hourly O2 concentration or moisture percentage in the applicable lookback period (moisture missing data algorithm 

depends on which equations are used for emissions and heat input). 

10 .... Maximum hourly SO2 concentration, CO2 concentration, NOX concentration, flow rate, moisture percentage, or NOX emission rate or 

minimum hourly O2 concentration or moisture percentage in the applicable lookback period (moisture missing data algorithm depends 

on which equations are used for emissions and heat input). 

11 .... Average of hourly flow rates, NOX concentrations or NOX emission rates in corresponding load range, for the applicable lookback period. 

For non-load-based units, report either the average flow rate, NOX concentration or NOX emission rate in the applicable lookback period, or the average flow rate or NOX value at the corresponding operational bin (if operational bins are used). 

12 .... Maximum potential concentration of SO2, maximum potential concentration of CO2, maximum potential concentration of NOX maximum 

potential flow rate, maximum potential NOX emission rate, maximum potential moisture percentage, minimum potential O2 concentration or minimum potential moisture percentage, as determined using § 72.2 of this chapter and section 2.1 of appendix A to this part 

(moisture missing data algorithm depends on which equations are used for emissions and heat input). 

13 .... Maximum expected concentration of SO2, maximum expected concentration of NOX, maximum expected Hg concentration, or maximum 

controlled NOX emission rate. (See § 75.34(a)(5)). 

14 .... Diluent cap value (if the cap is replacing a CO2 measurement, use 5.0 percent for boilers and 1.0 percent for turbines; if it is replacing 

an O2 measurement, use 14.0 percent for boilers and 19.0 percent for turbines). 

15 .... 1.25 times the maximum hourly controlled SO2 concentration, Hg concentration, NOX concentration at the corresponding load or operational bin, or NOX emission rate at the corresponding load or operational bin, in the applicable lookback period (See § 75.34(a)(5)). 

16 .... SO2 concentration value of 2.0 ppm during hours when only ‘‘very low sulfur fuel’’, as defined in § 72.2 of this chapter, is combusted. 

17 .... Like-kind replacement non-redundant backup analyzer. 

19 .... 200 percent of the MPC; default high range value. 

20 .... 200 percent of the full-scale range setting (full-scale exceedance of high range). 

21 .... Negative hourly CO2 concentration, SO2 concentration, NOX concentration, percent moisture, or NOX emission rate replaced with zero. 

22 .... Hourly average SO2 or NOX concentration, measured by a certified monitor at the control device inlet (units with add-on emission controls only). 

23 .... Maximum potential SO2 concentration, NOX concentration, CO2 concentration, NOX emission rate or flow rate, or minimum potential O2

concentration or moisture percentage, for an hour in which flue gases are discharged through an unmonitored bypass stack. 

24 .... Maximum expected NOX concentration, or maximum controlled NOX emission rate for an hour in which flue gases are discharged downstream of the NOX emission controls through an unmonitored bypass stack, and the add-on NOX emission controls are confirmed to 

be operating properly. 

25 .... Maximum potential NOX emission rate (MER). (Use only when a NOX concentration full-scale exceedance occurs and the diluent monitor 

is unavailable.) 


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TABLE 4A.—CODES FOR METHOD OF EMISSIONS AND FLOW DETERMINATION—Continued 

Code Hourly emissions/flow measurement or estimation method 

26 .... 1.0 mmBtu/hr substituted for Heat Input Rate for an operating hour in which the calculated Heat Input Rate is zero or negative. 

32 .... Hourly Hg concentration determined from analysis of a single trap multiplied by a factor of 1.111 when one of the paired traps is invalidated or damaged (See Appendix K, section 8). 

33 .... Hourly Hg concentration determined from the trap resulting in the higher Hg concentration when the relative deviation criterion for the 

paired traps is not met (See Appendix K, section 8). 

40 .... Fuel specific default value (or prorated default value) used for the hour. 

54 .... Other quality assured methodologies approved through petition. These hours are included in missing data lookback and are treated as 

unavailable hours for percent monitor availability calculations. 

55 .... Other substitute data approved through petition. These hours are not included in missing data lookback and are treated as unavailable 

hours for percent monitor availability calculations. 

* * * * * 

■ 24. Section 75.58 is amended by: 

■ a. Revising paragraph (b)(3) 

introductory text; 

■ b. Removing paragraphs (b)(3)(iii) and 

(b)(3)(iv); 

■ c. Removing the word ‘‘and’’ from 

paragraph (c)(1)(xii); 

■ d. Removing the period and adding in 

its place a semicolon and adding the 

word ‘‘and’’ to the end of the paragraph, 

in paragraph (c)(1)(xiii); 

■ e. Adding paragraph (c)(1)(xiv); 

■ f. Removing the period and adding in 

its place a semicolon and adding the 

word ‘‘and’’ to the end of the paragraph, 

in paragraph (c)(4)(x); 

■ g. Adding paragraph (c)(4)(xi); 

■ h. Removing the words ‘‘rounded to 

the nearest hundredth for diesel fuel’’

and adding in its place the words 

‘‘rounded to either the nearest 

hundredth, or nearest ten-thousandth 

for diesel fuels’’ in paragraph (c)(5)(ii); 

■ i. Removing the word ‘‘and’’ after the 

semicolon in paragraph (d)(1)(ix). 

■ j. Removing the period and adding in 

its place a semicolon and adding the 

word ‘‘and’’ to the end of the paragraph, 

in paragraph (d)(1)(x); 

■ k. Adding paragraph (d)(1)(xi); 

■ l. Removing the word ‘‘and’’ after the 

semicolon in paragraph (d)(2)(ix); 

■ m. Removing the period and adding in 

its place a semicolon and adding the 

word ‘‘and’’ to the end of the paragraph, 

in paragraph (d)(2)(x); 

■ n. Adding paragraph (d)(2)(xi); 

■ o. Revising paragraph (f)(1)(iii); 

■ p. Removing the word ‘‘and’’ at the 

end of paragraph (f)(1)(xi); 

■ q. Removing the period and adding in 

its place a semicolon at the end of 

paragraph (f)(1)(xii); 

■ r. Adding paragraphs (f)(1)(xiii) and 

(f)(1)(xiv); and 

■ s. Removing the word ‘‘Component’’

and adding in its place the word 

‘‘Monitoring’’, in paragraph (f)(2)(x). 

The revisions and additions read as 

follows: 

§ 75.58 General recordkeeping provisions 

for specific situations. 

* * * * * 

(b) * * * 

(3) Except as otherwise provided in 

§ 75.34(d), for units with add-on SO2 or 

NOX emission controls following the 

provisions of § 75.34(a)(1), (a)(2), (a)(3) 

or (a)(5), and for units with add-on Hg 

emission controls, the owner or operator 

shall record: 

* * * * * 

(c) * * * 

(1) * * * 

(xiv) Heat input formula ID and SO2

Formula ID (required beginning January 

1, 2009). 

* * * * * 

(4) * * * 

(xi) Heat input formula ID and SO2

Formula ID (required beginning January 

1, 2009). 

* * * * * 

(d) * * * 

(1) * * * 

(xi) Heat input rate formula ID 

(required beginning January 1, 2009). 

(2) * * * 

(xi) Heat input rate formula ID 

(required beginning January 1, 2009). 

* * * * * 

(f) * * * 

(1) * * * 

(iii) Fuel type (pipeline natural gas, 

natural gas, other gaseous fuel, residual 

oil, or diesel fuel). If more than one type 

of fuel is combusted in the hour, either: 

(A) Indicate the fuel type which 

results in the highest emission factors 

for NOX (this option is in effect through 

December 31, 2008); or 

(B) Indicate the fuel type resulting in 

the highest emission factor for each 

parameter (SO2, NOX emission rate, and 

CO2) separately (this option is required 

on and after January 1, 2009); 

* * * * * 

(xiii) Base or peak load indicator (as 

applicable); and 

(xiv) Multiple fuel flag. 

* * * * * 

■ 25. Section 75.59 is amended by: 

■ a. Adding the phrase ‘‘(on and after 

January 1, 2009, only the component 

identification code is required)’’ after 

the word ‘‘code’’, in paragraph (a)(1)(i); 

■ b. Revising paragraph (a)(1)(viii); 

■ c. Removing the phrase ‘‘For the 

qualifying test for off-line calibration, 

the owner or operator shall indicate’’

and adding in its place the phrase 

‘‘Indication of’’, in paragraph (a)(1)(xi); 

■ d. Adding the phrase ‘‘(after January 1, 

2009, only the component identification 

code is required)’’ after the word 

‘‘code’’, in paragraph (a)(2)(i); 

■ e. Adding the phrase ‘‘(on and after 

January 1, 2009, only the component 

identification code is required)’’ after 

the word ‘‘code’’, in paragraph (a)(3)(i); 

■ f. Adding the phrase ‘‘(only span scale 

is required on and after January 1, 

2009)’’ after the word ‘‘scale’’, in 

paragraph (a)(3)(ii); 

■ g. Adding the phrase ‘‘(on and after 

January 1, 2009, only the system 

identification code is required)’’ after 

the word ‘‘code’’, in paragraph (a)(4)(i); 

■ h. Removing the word ‘‘and’’ after the 

semicolon at the end of paragraph 

(a)(4)(vi)(L); 

■ i. Removing the period and adding in 

its place a semicolon and adding the 

word ‘‘and’’ at the end of paragraph 

(a)(4)(vi)(M); 

■ j. Adding paragraph (a)(4)(vi)(N); 

■ k. Removing the word ‘‘and’’ after the 

semicolon, at the end of paragraph 

(a)(4)(vii)(K); 

■ l. Removing the period and adding in 

its place a semicolon and adding the 

word ‘‘and’’ at the end of paragraph 

(a)(4)(vii)(L); 

■ m. Adding paragraph (a)(4)(vii)(M); 

■ n. Revising paragraph (a)(6) 

introductory text; 

■ o. Adding the phrase ‘‘(on and after 

January 1, 2009, only the component 

identification code is required)’’ after 

the word ‘‘code’’, in paragraph (a)(6)(i); 

■ p. Removing the phrase ‘‘Cycle time 

result for the entire system’’ and adding 

in its place the phrase ‘‘Total cycle 

time’’, in paragraph (a)(6)(ix); 

■ q. Revising the heading of reserved 

paragraph (a)(7)(viii); 

■ r. Adding paragraphs (a)(7)(ix) and 

(a)(7)(x); 

■ s. Revising paragraph (a)(8); 


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■ t. Removing and reserving paragraph 

(a)(12)(iii); 

■ u. Removing the number ‘‘(2)’’ from 

the paragraph identifier ‘‘§ 75.64(a)(2)’’

in the second sentence of paragraph 

(a)(13); 

■ v. Adding the phrase ‘‘(on and after 

January 1, 2009, only the component 

identification code is required)’’ after 

the word ‘‘tested’’, in paragraphs 

(b)(1)(ii) and (b)(2)(i); 

■ w. Adding the phrase ‘‘(on and after 

January 1, 2009, only the monitoring 

system identification code is required)’’

after the word ‘‘code’’, in paragraph 

(b)(4)(i)(A); 

■ x. Removing the word ‘‘and’’ after the 

semicolon at the end of paragraph 

(b)(4)(i)(H); 

■ y. Removing the period and adding in 

its place a semicolon and adding the 

word ‘‘and’’ at the end of paragraph 

(b)(4)(i)(I); 

■ z. Adding paragraph (b)(4)(i)(J); 

■ aa. Revising paragraphs (b)(4)(ii)(A), 

(b)(4)(ii)(B), and (b)(4)(ii)(F); 

■ bb. Removing the word ‘‘and’’ after 

the semicolon at the end of paragraph 

(b)(4)(ii)(L); 

■ cc. Removing the period and adding 

in its place a semicolon and adding the 

word ‘‘and’’ at the end of paragraph 

(b)(4)(ii)(M); 

■ dd. Adding paragraph (b)(4)(ii)(N); 

■ ee. Adding the phrase ‘‘(on and after 

January 1, 2009, component 

identification codes shall be reported in 

addition to the monitoring system 

identification code)’’ after the second 

occurrence of the word ‘‘system’’ in 

paragraphs (b)(5)(i)(B), (b)(5)(ii)(B), and 

(b)(5)(iii)(B); 

■ ff. Adding the phrase ‘‘This 

requirement remains in effect through 

December 31, 2008’’ after the word 

‘‘run;’’, in paragraph (b)(5)(i)(H); 

■ gg. Adding the phrase ‘‘(as 

applicable). This requirement remains 

in effect through December 31, 2008’’

after the word ‘‘level’’, in paragraph 

(b)(5)(iv)(A); 

■ hh. Removing the word ‘‘and’’ after 

the semicolon at the end of paragraph 

(b)(5)(iv)(G); 

■ ii. Removing the period and adding in 

its place a semicolon and adding the 

word ‘‘and’’ at the end of paragraph 

(b)(5)(iv)(H); 

■ jj. Adding paragraph (b)(5)(iv)(I); 

■ kk. Removing the word ‘‘and’’ after 

the semicolon at the end of paragraph 

(d)(1)(xi); 

■ ll. Removing the period and adding in 

its place a semicolon and adding the 

word ‘‘and’’ at the end of paragraph 

(d)(1)(xii); 

■ mm. Adding paragraph (d)(1)(xiii); 

■ nn. Removing the phrase ‘‘, multiplied 

by 1.15, if appropriate’’ from paragraph 

(d)(2)(iii); 

■ oo. Removing the word ‘‘and’’ after 

the semicolon at the end of paragraph 

(d)(2)(iv); 

■ pp. Removing the period and adding 

in its place a semicolon at the end of 

paragraph (d)(2)(v); and 

■ qq. Adding paragraphs (d)(2)(vi), 

(d)(2)(vii), (e) and (f). 

The revisions and additions read as 

follows: 

§ 75.59 Certification, quality, assurance, 

and quality control record provisions. 

* * * * * 

(a) * * * 

(1) * * * 

(viii) For 7-day calibration error tests, 

a test number and reason for test; 

* * * * * 

(4) * * * 

(vi) * * * 

(N) Test number. 

(vii) * * * 

(M) An indicator (‘‘flag’’) if separate 

reference ratios are calculated for each 

multiple stack. 

* * * * * 

(6) For each SO2, NOX, Hg, or CO2

pollutant concentration monitor, each 

component of a NOX-diluent continuous 

emission monitoring system, and each 

CO2 or O2 monitor used to determine 

heat input, the owner or operator shall 

record the following information for the 

cycle time test: 

* * * * * 

(7) * * * 

(viii) Data elements for Methods 30A 

and 30B. [Reserved] 

(ix) For a unit with a flow monitor 

installed on a rectangular stack or duct, 

if a site-specific default or measured 

wall effects adjustment factor (WAF) is 

used to correct the stack gas volumetric 

flow rate data to account for velocity 

decay near the stack or duct wall, the 

owner or operator shall keep records of 

the following for each flow RATA 

performed with EPA Method 2 in 

appendices A–1 and A–2 to part 60 of 

this chapter, subsequent to the WAF 

determination: 

(A) Monitoring system ID; 

(B) Test number; 

(C) Operating level; 

(D) RATA end date and time; 

(E) Number of Method 1 traverse 

points; and 

(F) Wall effects adjustment factor 

(WAF), to the nearest 0.0001. 

(x) For each RATA run using Method 

29 in appendix A–8 to part 60 of this 

chapter to determine Hg concentration: 

(A) Percent CO2 and O2 in the stack 

gas, dry basis; 

(B) Moisture content of the stack gas 

(percent H2O); 

(C) Average stack gas temperature 

(°F); 

(D) Dry gas volume metered (dscm); 

(E) Percent isokinetic; 

(F) Particulate Hg collected in the 

front half of the sampling train, 

corrected for the front-half blank value 

(μg); and 

(G) Total vapor phase Hg collected in 

the back half of the sampling train, 

corrected for the back-half blank value 

(μg). 

(8) For each certified continuous 

emission monitoring system, continuous 

opacity monitoring system, excepted 

monitoring system, or alternative 

monitoring system, the date and 

description of each event which 

requires certification, recertification, or 

certain diagnostic testing of the system 

and the date and type of each test 

performed. If the conditional data 

validation procedures of § 75.20(b)(3) 

are to be used to validate and report 

data prior to the completion of the 

required certification, recertification, or 

diagnostic testing, the date and hour of 

the probationary calibration error test 

shall be reported to mark the beginning 

of conditional data validation. 

* * * * * 

(b) * * * 

(4) * * * 

(i) * * * 

(J) Test number. 

(ii) * * * 

(A) Completion date and hour of most 

recent primary element inspection or 

test number of the most recent primary 

element inspection (as applicable); (on 

and after January 1, 2009, the test 

number of the most recent primary 

element inspection is required in lieu of 

the completion date and hour for the 

most recent primary element 

inspection); 

(B) Completion date and hour of most 

recent flow meter of transmitter 

accuracy test or test number of the most 

recent flowmeter or transmitter accuracy 

test (as applicable); (on and after 

January 1, 2009, the test number of the 

most recent flowmeter or transmitter 

accuracy test is required in lieu of the 

completion date and hour for the most 

recent flowmeter or transmitter accuracy 

test); 

* * * * * 

(F) Average load, in megawatts, 1000 

lb/hr of steam, or mmBtu/hr thermal 

output; 

* * * * * 

(N) Monitoring system identification 

code. 

* * * * * 

(5) * * * 

(iv) * * * 

(I) Component identification code 

(required on and after January 1, 2009). 

* * * * * 


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(d) * * * 

(1) * * * 

(xiii) An indicator (‘‘flag’’) if the run 

is used to calculate the highest 3-run 

average NOX emission rate at any load 

level. 

(2) * * * 

(vi) Indicator of whether the testing 

was done at base load, peak load or both 

(if appropriate); and 

(vii) The default NOX emission rate 

for peak load hours (if applicable). 

* * * * * 

(e) Excepted monitoring for Hg low 

mass emission units under § 75.81(b). 

For qualifying coal-fired units using the 

alternative low mass emission 

methodology under § 75.81(b), the 

owner or operator shall record the data 

elements described in § 75.59(a)(7)(vii), 

§ 75.59(a)(7)(viii), or § 75.59(a)(7)(x), as 

applicable, for each run of each Hg 

emission test and re-test required under 

§ 75.81(c)(1) or § 75.81(d)(4)(iii). 

(f) DAHS Verification. For each DAHS 

(missing data and formula) verification 

that is required for initial certification, 

recertification, or for certain diagnostic 

testing of a monitoring system, record 

the date and hour that the DAHS 

verification is successfully completed. 

(This requirement only applies to units 

that report monitoring plan data in 

accordance with § 75.53(g) and (h).) 

* * * * * 

■ 26. Section 75.60 is amended by 

adding paragraph (b)(8) to read as 

follows: 

§ 75.60 General provisions. 

* * * * * 

(b) * * * 

(8) Routine retest reports for Hg low 

mass emissions units. If requested in 

writing (or by electronic mail) by the 

applicable EPA Regional Office, 

appropriate State, and/or appropriate 

local air pollution control agency, the 

designated representative shall submit a 

hardcopy report for a semiannual or 

annual retest required under 

§ 75.81(d)(4)(iii) for a Hg low mass 

emissions unit, within 45 days after 

completing the test or within 15 days of 

receiving the request, whichever is later. 

The designated representative shall 

report, at a minimum, the following 

hardcopy information to the applicable 

EPA Regional Office, appropriate State, 

and/or appropriate local air pollution 

control agency that requested the 

hardcopy report: a summary of the test 

results; the raw reference method data 

for each test run; the raw data and 

results of all pretest, post-test, and postrun quality-assurance checks of the 

reference method; the raw data and 

results of moisture measurements made 

during the test runs (if applicable); 

diagrams illustrating the test and sample 

point locations; a copy of the test 

protocol used; calibration certificates for 

the gas standards or standard solutions 

used in the testing; laboratory 

calibrations of the source sampling 

equipment; and the names of the key 

personnel involved in the test program, 

including test team members, plant 

contact persons, agency representatives 

and test observers. 

* * * * * 

■ 27. Section 75.61 is amended by: 

■ a. Revising the first sentence of 

paragraph (a)(1) introductory text; 

■ b. Revising paragraph (a)(3); 

■ c. Revising the first sentence of 

paragraph (a)(5) introductory text; and 

■ d. Adding paragraphs (a)(7) and (a)(8) 

The revisions and additions read as 

follows: 

§ 75.61 Notifications. 

(a) * * * 

(1) * * * The owner or operator or 

designated representative for an affected 

unit shall submit written notification of 

initial certification tests and revised test 

dates as specified in § 75.20 for 

continuous emission monitoring 

systems, for the excepted Hg monitoring 

methodology under § 75.81(b), for 

alternative monitoring systems under 

subpart E of this part, or for excepted 

monitoring systems under appendix E to 

this part, except as provided in 

paragraphs (a)(1)(iii), (a)(1)(iv) and (a)(4) 

of this section. * * * 

* * * * * 

(3) Unit shutdown and 

recommencement of commercial 

operation. For an affected unit that will 

be shut down on the relevant 

compliance date specified in § 75.4 or in 

a State or Federal pollutant mass 

emissions reduction program that 

adopts the monitoring and reporting 

requirements of this part, if the owner 

or operator is relying on the provisions 

in § 75.4(d) to postpone certification 

testing, the designated representative for 

the unit shall submit notification of unit 

shutdown and recommencement of 

commercial operation as follows: 

(i) For planned unit shutdowns (e.g., 

extended maintenance outages), written 

notification of the planned shutdown 

date shall be provided at least 21 days 

prior to the applicable compliance date, 

and written notification of the planned 

date of recommencement of commercial 

operation shall be provided at least 21 

days in advance of unit restart. If the 

actual shutdown date or the actual date 

of recommencement of commercial 

operation differs from the planned date, 

written notice of the actual date shall be 

submitted no later than 7 days following 

the actual date of shutdown or of 

recommencement of commercial 

operation, as applicable; 

(ii) For unplanned unit shutdowns 

(e.g., forced outages), written 

notification of the actual shutdown date 

shall be provided no more than 7 days 

after the shutdown, and written 

notification of the planned date of 

recommencement of commercial 

operation shall be provided at least 21 

days in advance of unit restart. If the 

actual date of recommencement of 

commercial operation differs from the 

expected date, written notice of the 

actual date shall be submitted no later 

than 7 days following the actual date of 

recommencement of commercial 

operation. 

* * * * * 

(5) * * * The owner or operator or 

designated representative of an affected 

unit shall submit written notice of the 

date of periodic relative accuracy testing 

performed under section 2.3.1 of 

appendix B to this part, of periodic 

retesting performed under section 2.2 of 

appendix E to this part, of periodic 

retesting of low mass emissions units 

performed under § 75.19(c)(1)(iv)(D), 

and of periodic retesting of Hg low mass 

emissions units performed under 

§ 75.81(d)(4)(iii), no later than 21 days 

prior to the first scheduled day of 

testing. * * * 

(7) Long-term cold storage and 

recommencement of commercial 

operation. The designated 

representative for an affected unit that is 

placed into long-term cold storage that 

is relying on the provisions in § 75.4(d) 

or § 75.64(a), either to postpone 

certification testing or to discontinue 

the submittal of quarterly reports during 

the period of long-term cold storage, 

shall provide written notification of 

long-term cold storage status and 

recommencement of commercial 

operation as follows: 

(i) Whenever an affected unit has been 

placed into long-term cold storage, 

written notification of the date and hour 

that the unit was shutdown and a 

statement from the designated 

representative stating that the shutdown 

is expected to last for at least two years 

from that date, in accordance with the 

definition for long-term cold storage of 

a unit as provided in § 72.2 of this 

chapter. 

(ii) Whenever an affected unit that has 

been placed into long-term cold storage 

is expected to resume operation, written 

notification shall be submitted 45 

calendar days prior to the planned date 

of recommencement of commercial 

operation. If the actual date of 


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recommencement of commercial 

operation differs from the expected date, 

written notice of the actual date shall be 

submitted no later than 7 days following 

the actual date of recommencement of 

commercial operation. 

(8) Certification deadline date for new 

or newly affected units. The designated 

representative of a new or newly 

affected unit shall provide notification 

of the date on which the relevant 

deadline for initial certification is 

reached, either as provided in § 75.4(b) 

or § 75.4(c), or as specified in a State or 

Federal SO2, NOX, or Hg mass emission 

reduction program that incorporates by 

reference, or otherwise adopts, the 

monitoring, recordkeeping, and 

reporting requirements of subpart F, G, 

H, or I of this part. The notification shall 

be submitted no later than 7 calendar 

days after the applicable certification 

deadline is reached. 

* * * * * 

■ 28. Section 75.62 is amended by: 

■ a. Revising paragraph (a)(1); and 

■ b. Removing the number ‘‘45’’ and 

adding in its place the number ‘‘21’’

before the phrase ‘‘days prior’’, in 

paragraph (a)(2). 

The revisions read as follows: 

§ 75.62 Monitoring plan submittals. 

(a) * * * 

(1) Electronic. Using the format 

specified in paragraph (c) of this 

section, the designated representative 

for an affected unit shall submit a 

complete, electronic, up-to-date 

monitoring plan file (except for 

hardcopy portions identified in 

paragraph (a)(2) of this section) to the 

Administrator as follows: no later than 

21 days prior to the initial certification 

tests; at the time of each certification or 

recertification application submission; 

and (prior to or concurrent with) the 

submittal of the electronic quarterly 

report for a reporting quarter where an 

update of the electronic monitoring plan 

information is required, either under 

§ 75.53(b) or elsewhere in this part. 

* * * * * 

■ 29. Section 75.63 is amended by: 

■ a. Removing the phrase ‘‘and a 

hardcopy certification application form 

(EPA form 7610–14)’’ from paragraph 

(a)(1)(i)(A); 

■ b. Revising paragraph (a)(1)(ii)(A); 

■ c. Adding the phrase ‘‘or 

§ 75.53(h)(4)(ii) (as applicable)’’ after the 

identifier ‘‘§ 75.53(f)(5)(ii)’’, in 

paragraph (a)(1)(ii)(B); 

■ d. Removing the phrase ‘‘and a 

hardcopy certification application form 

(EPA form 7610–14)’’ after the word 

‘‘section’’, in paragraph (a)(2)(i); 

■ e. Revising paragraph (a)(2)(iii); 

■ f. Removing and reserving paragraph 

(b)(2)(iii); 

■ g. Revising paragraph (b)(2)(iv). 

The revisions read as follows: 

§ 75.63 Initial certification or recertification 

application. 

(a) * * * 

(1) * * * 

(ii) * * * 

(A) To the Administrator, the 

electronic low mass emission 

qualification information required by 

§ 75.53(f)(5)(i) or § 75.53(h)(4)(i) (as 

applicable) and paragraph (b)(1)(i) of 

this section; and 

* * * * * 

(2) * * * 

(iii) Notwithstanding the 

requirements of paragraphs (a)(2)(i) and 

(a)(2)(ii) of this section, for an event for 

which the Administrator determines 

that only diagnostic tests (see § 75.20(b)) 

are required rather than recertification 

testing, no hardcopy submittal is 

required; however, the results of all 

diagnostic test(s) shall be submitted 

prior to or concurrent with the 

electronic quarterly report required 

under § 75.64. Notwithstanding the 

requirement of § 75.59(e), for DAHS 

(missing data and formula) verifications, 

no hardcopy submittal is required; the 

owner or operator shall keep these test 

results on-site in a format suitable for 

inspection. 

* * * * * 

(b) * * * 

(2) * * * 

(iv) Designated representative 

signature certifying the accuracy of the 

submission. 

* * * * * 

■ 30. Section 75.64 is amended by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Redesignate paragraph (a)(2)(xiv) as 

paragraph (a)(2)(xiii); 

■ c. Revise newly designated paragraph 

(a)(2)(xiii); 

■ d. Removing paragraph (a)(8); 

■ e. Redesignating paragraphs (a)(9) 

through (a)(11) as paragraphs (a)(13) 

through (a)(15), and redesignating 

paragraphs (a)(3) through (a)(7) as 

paragraphs (a)(8) through (a)(12); 

■ f. Adding new paragraphs (a)(3) 

through (a)(7); and 

■ g. Removing the citation ‘‘§ 75.59’’, 

and adding in its place ‘‘§ 75.58(f)(2)’’ at 

the end of newly designated paragraph 

(a)(14). 

The revisions and additions read as 

follows: 

§ 75.64 Quarterly reports. 

(a) Electronic submission. The 

designated representative for an affected 

unit shall electronically report the data 

and information in paragraphs (a), (b), 

and (c) of this section to the 

Administrator quarterly, beginning with 

the data from the earlier of the calendar 

quarter corresponding to the date of 

provisional certification or the calendar 

quarter corresponding to the relevant 

deadline for initial certification in 

§ 75.4(a), (b), or (c). The initial quarterly 

report shall contain hourly data 

beginning with the hour of provisional 

certification or the hour corresponding 

to the relevant certification deadline, 

whichever is earlier. For an affected unit 

subject to § 75.4(d) that is shutdown on 

the relevant compliance date in § 75.4(a) 

or has been placed in long-term cold 

storage (as defined in § 72.2 of this 

chapter), quarterly reports are not 

required. In such cases, the owner or 

operator shall submit quarterly reports 

for the unit beginning with the data 

from the quarter in which the unit 

recommences commercial operation 

(where the initial quarterly report 

contains hourly data beginning with the 

first hour of recommenced commercial 

operation of the unit). For units placed 

into long-term cold storage during a 

reporting quarter, the exemption from 

submitting quarterly reports begins with 

the calendar quarter following the date 

that the unit is placed into long-term 

cold storage. For any provisionallycertified monitoring system, 

§ 75.20(a)(3) shall apply for initial 

certifications, and § 75.20(b)(5) shall 

apply for recertifications. Each 

electronic report must be submitted to 

the Administrator within 30 days 

following the end of each calendar 

quarter. Prior to January 1, 2008, each 

electronic report shall include for each 

affected unit (or group of units using a 

common stack), the information 

provided in paragraphs (a)(1), (a)(2), and 

(a)(8) through (a)(15) of this section. 

During the time period of January 1, 

2008 to January 1, 2009, each electronic 

report shall include, either the 

information provided in paragraphs 

(a)(1), (a)(2), and (a)(8) through (a)(15) of 

this section or the information provided 

in paragraphs (a)(3) through (a)(15) of 

this section. On and after January 1, 

2009, the owner or operator shall meet 

the requirements of paragraphs (a)(3) 

through (a)(15) of this section only. Each 

electronic report shall also include the 

date of report generation. 

* * * * * 

(2) * * * 

(xiii) Supplementary RATA 

information required under 

§ 75.59(a)(7), except that: 

(A) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 


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and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for flow RATAs at 

circular or rectangular stacks (or ducts) 

in which angular compensation for yaw 

and/or pitch angles is used (i.e., Method 

2F or 2G in appendices A–1 and A–2 to 

part 60 of this chapter), with or without 

wall effects adjustments; 

(B) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for any flow RATA 

run at a circular stack in which Method 

2 in appendices A–1 and A–2 to part 60 

of this chapter is used and a wall effects 

adjustment factor is determined by 

direct measurement; 

(C) The data under § 75.59(a)(7)(ii)(T) 

shall be reported for all flow RATAs at 

circular stacks in which Method 2 in 

appendices A–1 and A–2 to part 60 of 

this chapter is used and a default wall 

effects adjustment factor is applied; and 

(D) The data under § 75.59(a)(7)(ix)(A) 

through (F) shall be reported for all flow 

RATAs at rectangular stacks or ducts in 

which Method 2 in appendices A–1 and 

A–2 to part 60 of this chapter is used 

and a wall effects adjustment factor is 

applied. 

(3) Facility identification information, 

including: 

(i) Facility/ORISPL number; 

(ii) Calendar quarter and year for the 

data contained in the report; and 

(iii) Version of the electronic data 

reporting format used for the report. 

(4) In accordance with § 75.62(a)(1), if 

any monitoring plan information 

required in § 75.53 requires an update, 

either under § 75.53(b) or elsewhere in 

this part, submission of the electronic 

monitoring plan update shall be 

completed prior to or concurrent with 

the submittal of the quarterly electronic 

data report for the appropriate quarter in 

which the update is required. 

(5) Except for the daily calibration 

error test data, daily interference check, 

and off-line calibration demonstration 

information required in § 75.59(a)(1) 

and (2), which must always be 

submitted with the quarterly report, the 

certification, quality assurance, and 

quality control information required in 

§ 75.59 shall either be submitted prior to 

or concurrent with the submittal of the 

relevant quarterly electronic data report. 

(6) The information and hourly data 

required in §§ 75.57 through 75.59, and 

daily calibration error test data, daily 

interference check, and off-line 

calibration demonstration information 

required in § 75.59(a)(1) and (2). 

(7) Notwithstanding the requirements 

of paragraphs (a)(4) through (a)(6) of this 

section, the following information is 

excluded from electronic reporting: 

(i) Descriptions of adjustments, 

corrective action, and maintenance; 

(ii) Information which is incompatible 

with electronic reporting (e.g., field data 

sheets, lab analyses, quality control 

plan); 

(iii) Opacity data listed in § 75.57(f), 

and in § 75.59(a)(8); 

(iv) For units with SO2 or NOX addon emission controls that do not elect to 

use the approved site-specific 

parametric monitoring procedures for 

calculation of substitute data, the 

information in § 75.58(b)(3); 

(v) Information required by § 75.57(h) 

concerning the causes of any missing 

data periods and the actions taken to 

cure such causes; 

(vi) Hardcopy monitoring plan 

information required by § 75.53 and 

hardcopy test data and results required 

by § 75.59; 

(vii) Records of flow monitor and 

moisture monitoring system polynomial 

equations, coefficients, or ‘‘K’’ factors 

required by § 75.59(a)(5)(vi) or 

§ 75.59(a)(5)(vii); 

(viii) Daily fuel sampling information 

required by § 75.58(c)(3)(i) for units 

using assumed values under appendix D 

of this part; 

(ix) Information required by 

§§ 75.59(b)(1)(vi), (vii), (viii), (ix), and 

(xiii), and (b)(2)(iii) and (iv) concerning 

fuel flowmeter accuracy tests and 

transmitter/transducer accuracy tests; 

(x) Stratification test results required 

as part of the RATA supplementary 

records under § 75.59(a)(7); 

(xi) Data and results of RATAs that 

are aborted or invalidated due to 

problems with the reference method or 

operational problems with the unit and 

data and results of linearity checks that 

are aborted or invalidated due to 

problems unrelated to monitor 

performance; and 

(xii) Supplementary RATA 

information required under 

§ 75.59(a)(7)(i) through § 75.59(a)(7)(v), 

except that: 

(A) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for flow RATAs at 

circular or rectangular stacks (or ducts) 

in which angular compensation for yaw 

and/or pitch angles is used (i.e., Method 

2F or 2G in appendices A–1 and A–2 to 

part 60 of this chapter), with or without 

wall effects adjustments; 

(B) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for any flow RATA 

run at a circular stack in which Method 

2 in appendices A–1 and A–2 to part 60 

of this chapter is used and a wall effects 

adjustment factor is determined by 

direct measurement; 

(C) The data under § 75.59(a)(7)(ii)(T) 

shall be reported for all flow RATAs at 

circular stacks in which Method 2 in 

appendices A–1 and A–2 to part 60 of 

this chapter is used and a default wall 

effects adjustment factor is applied; and 

(D) The data under 

§ 75.59(a)(7)(vii)(A) through (F) shall be 

reported for all flow RATAs at 

rectangular stacks or ducts in which 

Method 2 in appendices A–1 and A–2 

to part 60 of this chapter is used and a 

wall effects adjustment factor is applied. 

* * * * * 

§ 75.66 [Amended] 

■ 31. Section 75.66 is amended by 

removing and reserving paragraph (f). 

■ 32. Section 75.71 is amended by: 

■ a. Revising the section heading; 

■ b. In paragraph (a)(1), by removing the 

second occurrence of the phrase ‘‘CO2

diluent gas monitor’’ and adding in its 

place the phrase ‘‘CO2 diluent gas 

monitoring system’’; 

■ c. Removing the phrase ‘‘O2 or CO2

diluent gas monitor’’ and adding in its 

place the phrase ‘‘O2 or CO2 monitoring 

system’’, in paragraph (a)(2); and 

■ d. Revising paragraph (e). 

The revision reads as follows: 

§ 75.71 Specific provisions for monitoring 

NOX and heat input for the purpose of 

calculating NOX mass emissions. 

* * * * * 

(e) Low mass emissions units. 

Notwithstanding the requirements of 

paragraphs (c) and (d) of this section, for 

an affected unit using the low mass 

emissions (LME) unit under § 75.19 to 

estimate hourly NOX emission rate, heat 

input and NOX mass emissions, the 

owner or operator shall calculate the 

ozone season NOX mass emissions by 

summing all of the estimated hourly 

NOX mass emissions in the ozone 

season, as determined under § 75.19 

(c)(4)(ii)(A), and dividing this sum by 

2000 lb/ton. 

* * * * * 

■ 33. Section 75.72 is amended by: 

■ a. Revising the section heading and 

the introductory text; 

■ b. Revising paragraph (c)(3); and 

■ c. Removing and reserving paragraph 

(f). 

The revisions read as follows: 

§ 75.72 Determination of NOX mass 

emissions for common stack and multiple 

stack configurations. 

The owner or operator of an affected 

unit shall either: calculate hourly NOX

mass emissions (in lbs) by multiplying 

the hourly NOX emission rate (in lbs/ 


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mmBtu) by the hourly heat input rate 

(in mmBtu/hr) and the unit or stack 

operating time (as defined in § 72.2), or, 

as provided in paragraph (e) of this 

section, calculate hourly NOX mass 

emissions from the hourly NOX

concentration (in ppm) and the hourly 

stack flow rate (in scfh). Only one 

methodology for determining NOX mass 

emissions shall be identified in the 

monitoring plan for each monitoring 

location at any given time. The owner 

or operator shall also calculate quarterly 

and cumulative year-to-date NOX mass 

emissions and cumulative NOX mass 

emissions for the ozone season (in tons) 

by summing the hourly NOX mass 

emissions according to the procedures 

in section 8 of appendix F to this part. 

* * * * * 

(c) * * * 

(3) Install, certify, operate, and 

maintain a NOX-diluent CEMS and a 

flow monitoring system only on the 

main stack. If this option is chosen, it 

is not necessary to designate the exhaust 

configuration as a multiple stack 

configuration in the monitoring plan 

required under § 75.53, since only the 

main stack is monitored. For each unit 

operating hour in which the bypass 

stack is used and the emissions are 

either uncontrolled (or the add-on 

controls are not documented to be 

operating properly), report NOX mass 

emissions as follows. If the unit heat 

input is determined using a flow 

monitor and a diluent monitor, report 

NOX mass emissions using the 

maximum potential NOX emission rate, 

the maximum potential flow rate, and 

either the maximum potential CO2

concentration or the minimum potential 

O2 concentration (as applicable). The 

maximum potential NOX emission rate 

may be specific to the type of fuel 

combusted in the unit during the bypass 

(see § 75.33(c)(8)). If the unit heat input 

is determined using a fuel flowmeter, in 

accordance with appendix D to this 

part, report NOX mass emissions as the 

product of the maximum potential NOX

emission rate and the actual measured 

hourly heat input rate. Alternatively, for 

a unit with NOX add-on emission 

controls, for each unit operating hour in 

which the bypass stack is used but the 

add-on NOX emission controls are not 

bypassed, the owner or operator may 

report the maximum controlled NOX

emission rate (MCR) instead of the 

maximum potential NOX emission rate 

provided that the add-on controls are 

documented to be operating properly, as 

described in the quality assurance/ 

quality control program for the unit, 

required by section 1 in appendix B of 

this part. To provide the necessary 

documentation, the owner or operator 

shall record parametric data to verify 

the proper operation of the NOX add-on 

emission controls as described in 

§ 75.34(d). Furthermore, the owner or 

operator shall calculate the MCR using 

the procedure described in section 

2.1.2.1(b) of appendix A to this part by 

replacing the words ‘‘maximum 

potential NOX emission rate (MER)’’

with the words ‘‘maximum controlled 

NOX emission rate (MCR)’’ and by using 

the NOX MEC in the calculations 

instead of the NOX MPC. 

* * * * * 

(f) [Reserved] 

* * * * * 

■ 34. Section 75.73 is amended by: 

■ a. Revising paragraph (c)(3); 

■ b. Removing the number ‘‘45’’ and 

adding in its place the number ‘‘21’’ in 

paragraphs (e)(1) and (e)(2); 

■ c. Revising paragraph (f)(1) 

introductory text; 

■ d. Removing the phrase ‘‘paragraph 

(a)’’ and adding in its place the phrase 

‘‘paragraphs (a) and (b)’’ in paragraph 

(f)(1)(ii) introductory text; and 

■ e. Revising paragraph (f)(1)(ii)(K). 

The revisions read as follows: 

§ 75.73 Recordkeeping and reporting. 

* * * * * 

(c) * * * 

(3) Contents of the monitoring plan 

for units not subject to an Acid Rain 

emissions limitation. Prior to January 1, 

2009, each monitoring plan shall 

contain the information in § 75.53(e)(1) 

or § 75.53(g)(1) in electronic format and 

the information in § 75.53(e)(2) or 

§ 75.53(g)(2) in hardcopy format. On and 

after January 1, 2009, each monitoring 

plan shall contain the information in 

§ 75.53(g)(1) in electronic format and the 

information in § 75.53(g)(2) in hardcopy 

format, only. In addition, to the extent 

applicable, prior to January 1, 2009, 

each monitoring plan shall contain the 

information in § 75.53(f)(1)(i), (f)(2)(i), 

and (f)(4) or § 75.53(h)(1)(i), and (h)(2)(i) 

in electronic format and the information 

in § 75.53(f)(1)(ii) and (f)(2)(ii) or 

§ 75.53(h)(1)(ii) and (h)(2)(ii) in 

hardcopy format. On and after January 

1, 2009, each monitoring plan shall 

contain the information in 

§ 75.53(h)(1)(i), and (h)(2)(i) in 

electronic format and the information in 

§ 75.53(h)(1)(ii) and (h)(2)(ii) in 

hardcopy format, only. For units using 

the low mass emissions excepted 

methodology under § 75.19, prior to 

January 1, 2009, the monitoring plan 

shall include the additional information 

in § 75.53(f)(5)(i) and (f)(5)(ii) or 

§ 75.53(h)(4)(i) and (h)(4)(ii). On and 

after January 1, 2009, for units using the 

low mass emissions excepted 

methodology under § 75.19 the 

monitoring plan shall include the 

additional information in § 75.53(h)(4)(i) 

and (h)(4)(ii), only. Prior to January 1, 

2008, the monitoring plan shall also 

identify, in electronic format, the 

reporting schedule for the affected unit 

(ozone season or quarterly), and the 

beginning and end dates for the 

reporting schedule. The monitoring plan 

also shall include a seasonal controls 

indicator, and an ozone season fuelswitching flag. 

* * * * * 

(f) * * * 

(1) Electronic submission. The 

designated representative for an affected 

unit shall electronically report the data 

and information in this paragraph (f)(1) 

and in paragraphs (f)(2) and (3) of this 

section to the Administrator quarterly, 

unless the unit has been placed in longterm cold storage (as defined in § 72.2 

of this chapter). For units placed into 

long-term cold storage during a 

reporting quarter, the exemption from 

submitting quarterly reports begins with 

the calendar quarter following the date 

that the unit is placed into long-term 

cold storage. In such cases, the owner or 

operator shall submit quarterly reports 

for the unit beginning with the data 

from the quarter in which the unit 

recommences operation (where the 

initial quarterly report contains hourly 

data beginning with the first hour of 

recommenced operation of the unit). 

Each electronic report must be 

submitted to the Administrator within 

30 days following the end of each 

calendar quarter. Except as otherwise 

provided in § 75.64(a)(4) and (a)(5), each 

electronic report shall include the 

information provided in paragraphs 

(f)(1)(i) through (1)(vi) of this section, 

and shall also include the date of report 

generation. Prior to January 1, 2009, 

each report shall include the facility 

information provided in paragraphs 

(f)(1)(i)(A) and (B) of this section, for 

each affected unit or group of units 

monitored at a common stack. On and 

after January 1, 2009, only the facility 

identification information provided in 

paragraph (f)(1)(i)(A) of this section is 

required. 

* * * * * 

(ii) * * * 

(K) Supplementary RATA information 

required under § 75.59(a)(7), except that: 

(1) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for flow RATAs at 

circular or rectangular stacks (or ducts) 

in which angular compensation for yaw 

and/or pitch angles is used (i.e., Method 


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2F or 2G in appendices A–1 and A–2 to 

part 60 of this chapter), with or without 

wall effects adjustments; 

(2) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for any flow RATA 

run at a circular stack in which Method 

2 in appendices A–1 and A–2 to part 60 

of this chapter is used and a wall effects 

adjustment factor is determined by 

direct measurement; 

(3) The data under § 75.59(a)(7)(ii)(T) 

shall be reported for all flow RATAs at 

circular stacks in which Method 2 in 

appendices A–1 and A–2 to part 60 of 

this chapter is used and a default wall 

effects adjustment factor is applied; and 

(4) The data under § 75.59(a)(7)(ix)(A) 

through (F) shall be reported for all flow 

RATAs at rectangular stacks or ducts in 

which Method 2 in appendices A–1 and 

A–2 to part 60 of this chapter is used 

and a wall effects adjustment factor is 

applied. 

* * * * * 

■ 35. Section 75.74 is amended by: 

■ a. Removing the phrase ‘‘In the time 

period prior to the start of the current 

ozone season (i.e., in the period 

extending from October 1 of the 

previous calendar year through April 30 

of the current calendar year), the’’, and 

adding in its place the word ‘‘The’’, in 

paragraph (c)(2) introductory text; 

■ b. Adding the words ‘‘in the second 

calendar quarter no later than April 30’’

to the end of paragraph (c)(2)(i) 

introductory text; 

■ c. Removing the phrase ‘‘of the current 

calendar year’’ from the first sentence, 

and removing the last sentence of 

paragraph (c)(2)(i)(C); 

■ d. Revising paragraph (c)(2)(i)(D); 

■ e. Adding the words ‘‘in the first or 

second calendar quarter, but no later 

than April 30’’ to the end of the first 

sentence, and by removing the second 

sentence of paragraph (c)(2)(ii) 

introductory text; 

■ f. Removing the words ‘‘of the current 

calendar year’’ from paragraph 

(c)(2)(ii)(E); 

■ g. Revising paragraph (c)(2)(ii)(F); 

■ h. Removing paragraphs (c)(2)(ii)(G) 

and (c)(2)(ii)(H); 

■ i. Revising paragraph (c)(3)(ii); 

■ j. Removing and reserving paragraphs 

(c)(3)(vi) through (viii); 

■ k. Removing all occurrences of the 

words ‘‘§ 75.31, § 75.33, or § 75.37’’ and 

adding in their place the words 

‘‘§§ 75.31 through 75.37’’ in paragraphs 

(c)(3)(xi), (c)(3)(xii)(A), and (c)(3)(xii)(B); 

■ l. Revising paragraph (c)(6)(iii); 

■ m. Removing the words ‘‘October 1 of 

the previous calendar year’’ and adding 

in its place the words ‘‘January 1’’ in 

paragraph (c)(6)(v); 

■ n. Revising paragraph (c)(7)(iii)(L); 

■ o. Revising paragraph (c)(8)(ii); and 

■ p. Revising paragraph (c)(11). 

The revisions read as follows: 

§ 75.74 Annual and ozone season 

monitoring and reporting requirements. 

* * * * * 

(c) * * * 

(2) * * * 

(i) * * * 

(D) If the linearity check is not 

completed by April 30, data validation 

shall be determined in accordance with 

paragraph (c)(3)(ii)(E) of this section. 

(ii) * * * 

(F) Data Validation. For each RATA 

that is performed by April 30, data 

validation shall be done according to 

sections 2.3.2(a)–(j) of appendix B to 

this part. However, if a required RATA 

is not completed by April 30, data from 

the monitoring system shall be invalid, 

beginning with the first unit operating 

hour on or after May 1. The owner or 

operator shall continue to invalidate all 

data from the CEMS until either: 

(1) The required RATA of the CEMS 

has been performed and passed; or 

(2) A probationary calibration error 

test of the CEMS is passed in 

accordance with § 75.20(b)(3)(ii). Once 

the probationary calibration error test 

has been passed, the owner or operator 

shall perform the required RATA in 

accordance with the conditional data 

validation provisions and within the 

720 unit or stack operating hour time 

frame specified in § 75.20(b)(3) (subject 

to the restrictions in paragraph 

(c)(3)(xii) of this section), and the term 

‘‘quality assurance’’ shall apply instead 

of the term ‘‘recertification.’’ However, 

in lieu of the provisions in 

§ 75.20(b)(3)(ix), the owner or operator 

shall follow the applicable provisions in 

paragraphs (c)(3)(xi) and (c)(3)(xii) of 

this section. 

(3) * * * 

(ii) For each gas monitor required by 

this subpart, linearity checks shall be 

performed in the second and third 

calendar quarters, as follows: 

(A) For the second calendar quarter, 

the pre-ozone season linearity check 

required under paragraph (c)(2)(i) of this 

section shall be performed by April 30. 

(B) For the third calendar quarter, a 

linearity check shall be performed and 

passed no later than July 30. 

(C) Conduct each linearity check in 

accordance with the general procedures 

in section 6.2 of appendix A to this part, 

except that the data validation 

procedures in sections 6.2(a) through (f) 

of appendix A do not apply. 

(D) Each linearity check shall be done 

‘‘hands-off,’’ as described in section 

2.2.3(c) of appendix B to this part. 

(E) Data Validation. For second and 

third quarter linearity checks performed 

by the applicable deadline (i.e., April 30 

or July 30), data validation shall be done 

in accordance with sections 2.2.3(a), (b), 

(c), (e), and (h) of Appendix B to this 

part. However, if a required linearity 

check for the second calendar quarter is 

not completed by April 30, or if a 

required linearity check for the third 

calendar quarter is not completed by 

July 30, data from the monitoring 

system (or range) shall be invalid, 

beginning with the first unit operating 

hour on or after May 1 or July 31, 

respectively. The owner or operator 

shall continue to invalidate all data 

from the CEMS until either: 

(1) The required linearity check of the 

CEMS has been performed and passed; 

or 

(2) A probationary calibration error 

test of the CEMS is passed in 

accordance with § 75.20(b)(3)(ii). Once 

the probationary calibration error test 

has been passed, the owner or operator 

shall perform the required linearity 

check in accordance with the 

conditional data validation provisions 

and within the 168 unit or stack 

operating hour time frame specified in 

§ 75.20(b)(3) (subject to the restrictions 

in paragraph (c)(3)(xii) of this section), 

and the term ‘‘quality assurance’’ shall 

apply instead of the term 

‘‘recertification.’’ However, in lieu of the 

provisions in § 75.20(b)(3)(ix), the 

owner or operator shall follow the 

applicable provisions in paragraphs 

(c)(3)(xi) and (c)(3)(xii) of this section. 

(F) A pre-season linearity check 

performed and passed in April satisfies 

the linearity check requirement for the 

second quarter. 

(G) The third quarter linearity check 

requirement in paragraph (c)(3)(ii)(B) of 

this section is waived if: 

(1) Due to infrequent unit operation, 

the 168 operating hour conditional data 

validation period associated with a preseason linearity check extends into the 

third quarter; and 

(2) A linearity check is performed and 

passed within that conditional data 

validation period. 

* * * * * 

(6) * * * 

(iii) For the time periods described in 

paragraphs (c)(2)(i)(C) and (c)(2)(ii)(E) of 

this section, hourly emission data and 

the results of all daily calibration error 

tests and flow monitor interference 

checks shall be recorded. The owner or 

operator may opt to report unit 

operating data, daily calibration error 

test and flow monitor interference check 

results, and hourly emission data in the 

time period from April 1 through April 


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30. However, only the data recorded in 

the time period from May 1 through 

September 30 shall be used for NOX

mass compliance determination; 

* * * * * 

(7) * * * 

(iii) * * * 

(L) In § 75.34(a)(3) and (a)(5), the 

phrases ‘‘720 quality-assured monitor 

operating hours within the ozone 

season’’ and ‘‘2160 quality-assured 

monitor operating hours within the 

ozone season’’ apply instead of ‘‘720 

quality-assured monitor operating 

hours’’ and ‘‘2160 quality-assured 

monitor operating hours’’, respectively. 

(8) * * * 

(ii) For units with add-on emission 

controls, using the missing data options 

in §§ 75.34(a)(1) through 75.34(a)(5), the 

range of operating parameters for add-on 

emission controls (as defined in the 

quality assurance/quality control 

program for the unit required by section 

1 in appendix B to this part) and 

information for verifying proper 

operation of the add-on emission 

controls during missing data periods, as 

described in § 75.34(d). 

* * * * * 

(11) Units may qualify to use the 

optional NOX mass emissions 

estimation protocol for gas-fired and oilfired peaking units in appendix E to this 

part on an ozone season basis. In order 

to be allowed to use this methodology, 

the unit must meet the definition of 

‘‘peaking unit’’ in § 72.2 of this chapter, 

except that the words ‘‘year’’, ‘‘calendar 

year’’ and ‘‘calendar years’’ in that 

definition shall be replaced by the 

words ‘‘ozone season’’, ‘‘ozone season’’, 

and ‘‘ozone seasons’’, respectively. In 

addition, in the definition of the term 

‘‘capacity factor’’ in § 72.2 of this 

chapter, the word ‘‘annual’’ shall be 

replaced by the words ‘‘ozone season’’

and the number ‘‘8,760’’ shall be 

replaced by the number ‘‘3,672’’. 

§ 75.80 [Amended] 

■ 36. Section 75.80(f)(1)(iii) is amended 

by removing the words ‘‘or § 75.12(b),’’. 

■ 37. Section 75.81 is amended by: 

■ a. Removing the words ‘‘or § 75.12(b)’’

and ‘‘or § 75.12,’’ from paragraph (a)(3); 

■ b. Revising paragraph (a)(4); 

■ c. Revising paragraph (c)(1); 

■ d. Revising paragraph (c)(2); 

■ e. Removing Eq. 1 from paragraph 

(d)(1); 

■ f. Revising paragraph (d)(2); 

■ g. Adding paragraph (d)(4)(iv); and 

■ h. Revising paragraphs (d)(5) and 

(e)(1). 

The revisions and additions read as 

follows: 

§ 75.81 Monitoring of Hg mass emissions 

and heat input at the unit level. 

* * * * * 

(a) * * * 

(4) If heat input is required to be 

reported under the applicable State or 

Federal Hg mass emission reduction 

program that adopts the requirements of 

this subpart, the owner or operator must 

meet the general operating requirements 

for a flow monitoring system and an O2

or CO2 monitoring system to measure 

heat input rate. 

* * * * * 

(c) * * * 

(1) The owner or operator must 

perform Hg emission testing one year or 

less before the compliance date in 

§ 75.80(b), to determine the Hg 

concentration (i.e., total vapor phase Hg) 

in the effluent. 

(i) The testing shall be performed 

using one of the Hg reference methods 

listed in § 75.22(a)(7), and shall consist 

of a minimum of 3 runs at the normal 

unit operating load, while combusting 

coal. The coal combusted during the 

testing shall be representative of the 

coal that will be combusted at the start 

of the Hg mass emissions reduction 

program (preferably from the same 

source(s) of supply). 

(ii) The minimum time per run shall 

be 1 hour if Method 30A is used. If 

either Method 29 in appendix A–8 to 

part 60 of this chapter, ASTM D6784–

02 (the Ontario Hydro method) 

(incorporated by reference under § 75.6 

of this part), or Method 30B is used, 

paired samples are required for each test 

run and the runs must be long enough 

to ensure that sufficient Hg is collected 

to analyze. When Method 29 in 

appendix A–8 to part 60 of this chapter 

or the Ontario Hydro method is used, 

the test results shall be based on the 

vapor phase Hg collected in the backhalf of the sampling trains (i.e., the nonfilterable impinger catches). For each 

Method 29 in appendix A–8 to part 60 

of this chapter, Method 30B, or Ontario 

Hydro method test run, the paired trains 

must meet the relative deviation (RD) 

requirement specified in § 75.22(a)(7) or 

Method 30B, as applicable. If the RD 

specification is met, the results of the 

two samples shall be averaged 

arithmetically. 

(iii) If the unit is equipped with flue 

gas desulfurization or add-on Hg 

emission controls, the controls must be 

operating normally during the testing, 

and, for the purpose of establishing 

proper operation of the controls, the 

owner or operator shall record 

parametric data or SO2 concentration 

data in accordance with § 75.58(b)(3)(i). 

(iv) If two or more of units of the same 

type qualify as a group of identical units 

in accordance with § 75.19(c)(1)(iv)(B), 

the owner or operator may test a subset 

of these units in lieu of testing each unit 

individually. If this option is selected, 

the number of units required to be 

tested shall be determined from Table 

LM–4 in § 75.19. For the purposes of the 

required retests under paragraph (d)(4) 

of this section, EPA strongly 

recommends that (to the extent 

practicable) the same subset of the units 

not be tested in two successive retests, 

and that every effort be made to ensure 

that each unit in the group of identical 

units is tested in a timely manner. 

(2)(i) Based on the results of the 

emission testing, Equation 1 of this 

section shall be used to provide a 

conservative estimate of the annual Hg 

mass emissions from the unit: 

E N Eq = K C Q 1 Hg max ( ) .

Where: 

E = Estimated annual Hg mass emissions 

from the affected unit, (ounces/year) 

K = Units conversion constant, 9.978 x 10¥10

oz-scm/μg-scf 

N = Either 8,760 (the number of hours in a 

year) or the maximum number of 

operating hours per year (if less than 

8,760) allowed by the unit’s Federallyenforceable operating permit. 

CHg = The highest Hg concentration (μg/scm) 

from any of the test runs or 0.50 μg/scm, 

whichever is greater 

Qmax = Maximum potential flow rate, 

determined according to section 2.1.4.1 

of appendix A to this part, (scfh) 

(ii) Equation 1 of this section assumes 

that the unit operates at its maximum 

potential flow rate, either year-round or 

for the maximum number of hours 

allowed by the operating permit (if unit 

operation is restricted to less than 8,760 

hours per year). If the permit restricts 

the annual unit 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’’ in Equation 1. Also, note 

that if the highest Hg concentration 


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measured in any test run is less than 

0.50 μg/scm, a default value of 0.50 μg/ 

scm must be used in the calculations. 

* * * * * 

(d) * * * 

(2) Following initial certification, the 

same default Hg concentration value 

that was used to estimate the unit’s 

annual Hg mass emissions under 

paragraph (c) of this section shall be 

reported for each unit operating hour, 

except as otherwise provided in 

paragraph (d)(4)(iv) or (d)(6) of this 

section. The default Hg concentration 

value shall be updated as appropriate, 

according to paragraph (d)(5) of this 

section. 

* * * * * 

(4) * * * 

(iv) An additional retest is required 

when there is a change in the coal rank 

of the primary fuel (e.g., when the 

primary fuel is switched from 

bituminous coal to lignite). Use ASTM 

D388–99 (incorporated by reference 

under § 75.6 of this part) to determine 

the coal rank. The four principal coal 

ranks are anthracitic, bituminous, 

subbituminous, and lignitic. The ranks 

of anthracite coal refuse (culm) and 

bituminous coal refuse (gob) shall be 

anthracitic and bituminous, 

respectively. The retest shall be 

performed within 720 unit operating 

hours of the change. 

(5) The default Hg concentration used 

for reporting under § 75.84 shall be 

updated after each required retest. This 

includes retests that are required prior 

to the compliance date in § 75.80(b). 

The updated value shall either be the 

highest Hg concentration measured in 

any of the test runs or 0.50 μg/scm, 

whichever is greater. The updated value 

shall be applied beginning with the first 

unit operating hour in which Hg 

emissions data are required to be 

reported after completion of the retest, 

except as provided in paragraph 

(d)(4)(iv) of this section, where the need 

to retest is triggered by a change in the 

coal rank of the primary fuel. In that 

case, apply the updated default Hg 

concentration beginning with the first 

unit operating hour in which Hg 

emissions are required to be reported 

after the date and hour of the fuel 

switch. 

* * * * * 

(e) * * * 

(1) The methodology may not be used 

for reporting Hg mass emissions at a 

common stack unless all of the units 

using the common stack are affected 

units and the units’ combined potential 

to emit does not exceed 464 ounces of 

Hg per year times the number of units 

sharing the stack, in accordance with 

paragraphs (c) and (d) of this section. If 

the test results demonstrate that the 

units sharing the common stack qualify 

as low mass emitters, the default Hg 

concentration used for reporting Hg 

mass emissions at the common stack 

shall either be the highest value 

obtained in any test run or 0.50 μg/scm, 

whichever is greater. 

(i) The initial emission testing 

required under paragraph (c) of this 

section may be performed at the 

common stack if the following 

conditions are met. Otherwise, testing of 

the individual units (or a subset of the 

units, if identical, as described in 

paragraph (c)(1)(iv) of this section) is 

required: 

(A) The testing must be done at a 

combined load corresponding to the 

designated normal load level (low, mid, 

or high) for the units sharing the 

common stack, in accordance with 

section 6.5.2.1 of appendix A to this 

part; 

(B) 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. 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); 

(C) If flue gas desulfurization and/or 

add-on Hg emission controls are used to 

reduce level the emissions exiting from 

the common stack, these emission 

controls must be operating normally 

during the emission testing and, for the 

purpose of establishing proper operation 

of the controls, the owner or operator 

shall record parametric data or SO2

concentration data in accordance with 

§ 75.58(b)(3)(i); 

(D) When calculating E, the estimated 

maximum potential annual Hg mass 

emissions from the stack, substitute the 

maximum potential flow rate through 

the common stack (as defined in the 

monitoring plan) and the highest 

concentration from any test run (or 0.50 

μg/scm, if greater) into Equation 1; 

(E) The calculated value of E shall be 

divided by the number of units sharing 

the stack. If the result, when rounded to 

the nearest ounce, does not exceed 464 

ounces, the units qualify to use the low 

mass emission methodology; and 

(F) If the units qualify to use the 

methodology, the default Hg 

concentration used for reporting at the 

common stack shall be the highest value 

obtained in any test run or 0.50 μg/scm, 

whichever is greater; or 

(ii) The retests required under 

paragraph (d)(4) of this section may also 

be done at the common stack. If this 

testing option is chosen, the testing 

shall be done at a combined load 

corresponding to the designated normal 

load level (low, mid, or high) for the 

units sharing the common stack, in 

accordance with section 6.5.2.1 of 

appendix A to this part. 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 either: 

(A) Perform the retest with all units in 

normal operation; or 

(B) 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. Use the Hg 

concentration obtained in the retest for 

reporting purposes under this part if the 

concentration is greater than or equal to 

the value obtained in the most recent 

test. If the retested value is lower than 

the Hg concentration from the previous 

test, continue using the higher value 

from the previous test for reporting 

purposes and use that same higher Hg 

concentration value in Equation 1 to 

determine the due date for the next 

retest, as described in paragraph 

(e)(1)(iii) of this section. 

(iii) If testing is done at the common 

stack, the due date for the next 

scheduled retest shall be determined as 

follows: 

(A) Substitute the maximum potential 

flow rate for the common stack (as 

defined in the monitoring plan) and the 

highest Hg concentration from any test 

run (or 0.50 μg/scm, if greater) into 

Equation 1; 

(B) If the value of E obtained from 

Equation 1, rounded to the nearest 

ounce, is greater than 144 times the 

number of units sharing the common 

stack, but less than or equal to 464 times 

the number of units sharing the stack, 

the next retest is due in two QA 

operating quarters; 

(C) If the value of E obtained from 

Equation 1, rounded to the nearest 

ounce, is less than or equal to 144 times 

the number of units sharing the 

common stack, the next retest is due in 

four QA operating quarters. 

* * * * * 

■ 38. Section 75.82 is amended by: 

■ a. Adding paragraph (b)(3); 

■ b. Removing the word ‘‘or’’ at the end 

of paragraph (c)(2); 


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■ c. Removing the period at the end of 

paragraph (c)(3), and adding in its place 

the phrase ‘‘; or’’; 

■ d. Adding paragraph (c)(4); 

■ e. Removing the word ‘‘or’’ at the end 

of paragraph (d)(1); 

■ f. Removing the period at the end of 

paragraph (d)(2), and adding in its place 

the phrase ‘‘; or’’; and 

■ g. Adding paragraph (d)(3). 

The revisions and additions read as 

follows: 

§ 75.82 Monitoring of Hg mass emissions 

and heat input at common and multiple 

stacks. 

* * * * * 

(b) * * * 

(3) If the monitoring option in 

paragraph (b)(2) of this section is 

selected, and if heat input is required to 

be reported under the applicable State 

or Federal Hg mass emission reduction 

program that adopts the requirements of 

this subpart, the owner or operator shall 

either: 

(i) Apportion the common stack heat 

input rate to the individual units 

according to the procedures in 

§ 75.16(e)(3); or 

(ii) Install a flow monitoring system 

and a diluent gas (O2 or CO2) monitoring 

system in the duct leading from each 

affected unit to the common stack, and 

measure the heat input rate in each 

duct, according to section 5.2 of 

appendix F to this part. 

(c) * * * 

(4) If the monitoring option in 

paragraph (c)(1) or (c)(2) of this section 

is selected, and if heat input is required 

to be reported under the applicable 

State or Federal Hg mass emission 

reduction program that adopts the 

requirements of this subpart, the owner 

or operator shall: 

(i) Use the installed flow and diluent 

monitors to determine the hourly heat 

input rate at each stack (mmBtu/hr), 

according to section 5.2 of appendix F 

to this part; and 

(ii) Calculate the hourly heat input at 

each stack (in mmBtu) by multiplying 

the measured stack heat input rate by 

the corresponding stack operating time; 

and 

(iii) Determine the hourly unit heat 

input by summing the hourly stack heat 

input values. 

(d) * * * 

(3) If the monitoring option in 

paragraph (d)(1) or (d)(2) of this section 

is selected, and if heat input is required 

to be reported under the applicable 

State or Federal Hg mass emission 

reduction program that adopts the 

requirements of this subpart, the owner 

or operator shall: 

(i) Use the installed flow and diluent 

monitors to determine the hourly heat 

input rate at each stack or duct (mmBtu/ 

hr), according to section 5.2 of appendix 

F to this part; and 

(ii) Calculate the hourly heat input at 

each stack or duct (in mmBtu) by 

multiplying the measured stack (or 

duct) heat input rate by the 

corresponding stack (or duct) operating 

time; and 

(iii) Determine the hourly unit heat 

input by summing the hourly stack (or 

duct) heat input values. 

■ 39. Section 75.84 is amended by: 

■ a. Removing ‘‘§ 75.53(e)(1)’’ and 

‘‘§ 75.53(e)(2)’’ and adding in their place 

‘‘§ 75.53(g)(1)’’ and ‘‘§ 75.53(g)(2)’’, in 

paragraph (c)(3); 

■ b. Removing the number ‘‘45’’ and 

adding in its place the number ‘‘21’’ in 

paragraphs (e)(1) and (e)(2); 

■ c. Revising paragraph (f)(1) 

introductory text; 

■ d. Removing ‘‘§ 75.64(a)(1)’’ and 

adding in its place ‘‘§ 75.64(a)(3)’’ in 

paragraph (f)(1)(i); 

■ e. Removing the phrase ‘‘paragraph 

(a)’’ and adding in its place the phrase 

‘‘paragraphs (a) and (b)’’ in paragraph 

(f)(1)(ii) introductory text; and 

■ f. Revising paragraph (f)(1)(ii)(I). 

The revisions read as follows: 

§ 75.84 Recordkeeping and reporting. 

* * * * * 

(f) * * * 

(1) Electronic submission. Electronic 

quarterly reports shall be submitted, 

beginning with the calendar quarter 

containing the compliance date in 

§ 75.80(b), unless otherwise specified in 

the final rule implementing a State or 

Federal Hg mass emissions reduction 

program that adopts the requirements of 

this subpart. The designated 

representative for an affected unit shall 

report the data and information in this 

paragraph (f)(1) and the applicable 

compliance certification information in 

paragraph (f)(2) of this section to the 

Administrator quarterly, except as 

otherwise provided in § 75.64(a) for 

units in long-term cold storage. Each 

electronic report must be submitted to 

the Administrator within 30 days 

following the end of each calendar 

quarter. Except as otherwise provided in 

§ 75.64(a)(4) and (a)(5), each electronic 

report shall include the date of report 

generation and the following 

information for each affected unit or 

group of units monitored at a common 

stack: 

* * * * * 

(ii) * * * 

(I) Supplementary RATA information 

required under § 75.59(a)(7), except that: 

(1) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for flow RATAs at 

circular or rectangular stacks (or ducts) 

in which angular compensation for yaw 

and/or pitch angles is used (i.e., Method 

2F or 2G in appendices A–1 and A–2 to 

part 60 of this chapter), with or without 

wall effects adjustments; 

(2) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for any flow RATA 

run at a circular stack in which Method 

2 in appendices A–1 and A–2 to part 60 

of this chapter is used and a wall effects 

adjustment factor is determined by 

direct measurement; 

(3) The data under § 75.59(a)(7)(ii)(T) 

shall be reported for all flow RATAs at 

circular stacks in which Method 2 in 

appendices A–1 and A–2 to part 60 of 

this chapter is used and a default wall 

effects adjustment factor is applied; and 

(4) The data under § 75.59(a)(7)(ix)(A) 

through (F) shall be reported for all flow 

RATAs at rectangular stacks or ducts in 

which Method 2 in appendices A–1 and 

A–2 to part 60 of this chapter is used 

and a wall effects adjustment factor is 

applied. 

* * * * * 

■ 40. Appendix A to Part 75 is amended 

by: 

■ a. Revising paragraph (c) of section 

2.1.1.1; 

■ b. Revising paragraph (b)(2) of section 

2.1.1.5; 

■ c. Revising paragraph (b)(2) of section 

2.1.2.5; 

■ d. Adding a new fourth sentence after 

the third sentence of section 2.1.3; 

■ e. Revising paragraph (3) of section 

3.2; 

■ f. Removing the phrase ‘‘continuous 

emission monitoring system(s)’’ and 

adding in its place the phrase 

‘‘monitoring component of a continuous 

emission monitoring system that is’’ in 

section 3.5; 

■ g. Adding the words ‘‘that meet the 

definition for a NIST Traceable 

Reference Material (NTRM) provided in 

§ 72.2.’’ after the word ‘‘gases’’ in 

section 5.1.3; 

■ h. Revising sections 5.1.4 and 5.1.9; 

■ i. Redesignating section 6.1 as section 

6.1.1 and adding a new heading for 6.1; 

■ j. Adding section 6.1.2; 

■ k. Revising the second and third 

sentences and adding a new fourth 

sentence to section 6.2, introductory 

text; 

■ l. Revising section 6.2(g); 

■ m. Adding paragraph (h) to section 

6.2; 

■ n. Adding a new fourth sentence to 

section 6.3.1, introductory text; 

■ o. Revising the introductory text of 

section 6.4; 


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■ p. Revising paragraph (e) in section 

6.5; 

■ q. Removing the words ‘‘that uses 

CEMS to account for its emissions and 

for each unit that uses the optional fuel 

flow-to-load quality assurance test in 

section 2.1.7 of appendix D to this part’’

from paragraph (a) of section 6.5.2.1; 

■ r. Adding the words ‘‘or mmBtu/hr’’

after the words ‘‘klb/hr of steam 

production’’, and by adding the words 

‘‘or mmBtu/hr of thermal output’’ after 

the words ‘‘thousands of lb/hr of steam 

load’’ in paragraph (a)(1) of section 

6.5.2.1; 

■ s. Adding the words ‘‘and units using 

the low mass emissions (LME) excepted 

methodology under § 75.19’’ after the 

words ‘‘(except for peaking units’’ in the 

second sentence in paragraph (c) of 

section 6.5.2.1; 

■ t. Adding the words ‘‘and LME units’’

after the words ‘‘For peaking units’’ in 

the third sentence in paragraph (d)(1) of 

section 6.5.2.1; 

■ u. Revising paragraph (e) of section 

6.5.2.1; 

■ v. Revising paragraph (c) in section 

6.5.6; 

■ w. Removing all occurrences of the 

words ‘‘section 3.2’’ and adding in its 

place the words ‘‘section 8.1.3’’ in 

paragraph (b)(3) of section 6.5.6, 

paragraph (a) of section 6.5.6.2, and 

paragraph (a) of section 6.5.6.3; 

■ x. Revising section 6.5.10; 

■ y. Adding two sentences at the end of 

section 7.6.1; 

■ z. Revising the terms Rref and Lavg, in 

paragraph (a) of section 7.7; 

■ aa. Revising the terms (GHR)ref and 

Lavg, in paragraph (c) of section 7.7; and 

■ bb. Removing Figure 6 and adding in 

its place Figures 6a and 6b and revising 

A through F and adding G at the end of 

appendix A. 

The revisions and additions read as 

follows: 

Appendix A to Part 75—Specifications 

and Procedures 

* * * * * 

2. Equipment Specifications 

2.1.1.1 Maximum Potential Concentration 

* * * * * 

(c) When performing fuel sampling to 

determine the MPC, use ASTM Methods: 

ASTM D3177–02 (Reapproved 2007), 

Standard Test Methods for Total Sulfur in the 

Analysis Sample of Coal and Coke; ASTM 

D4239–02, Standard Test Methods for Sulfur 

in the Analysis Sample of Coal and Coke 

Using High-Temperature Tube Furnace 

Combustion Methods; ASTM D4294–98, 

Standard Test Method for Sulfur in 

Petroleum and Petroleum Products by 

Energy-Dispersive X-ray Fluorescence 

Spectrometry; ASTM D1552–01, Standard 

Test Method for Sulfur in Petroleum 

Products (High-Temperature Method); ASTM 

D129–00, Standard Test Method for Sulfur in 

Petroleum Products (General Bomb Method); 

ASTM D2622–98, Standard Test Method for 

Sulfur in Petroleum Products by Wavelength 

Dispersive X-ray Fluorescence Spectrometry, 

for sulfur content of solid or liquid fuels; 

ASTM D3176–89 (Reapproved 2002), 

Standard Practice for Ultimate Analysis of 

Coal and Coke; ASTM D240–00, Standard 

Test Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter; or ASTM D5865–01a, Standard 

Test Method for Gross Calorific Value of Coal 

and Coke (all incorporated by reference 

under § 75.6 of this part). 

* * * * * 

2.1.1.5 * * * 

(b) * * * 

(2) For units with two SO2 spans and 

ranges, if the low range is exceeded, no 

further action is required, provided that the 

high range is available and its most recent 

calibration error test and linearity check have 

not expired. However, if either of these 

quality assurance tests has expired and the 

high range is not able to provide quality 

assured data at the time of the low range 

exceedance or at any time during the 

continuation of the exceedance, report the 

MPC as the SO2 concentration until the 

readings return to the low range or until the 

high range is able to provide quality assured 

data (unless the reason that the high-scale 

range is not able to provide quality assured 

data is because the high-scale range has been 

exceeded; if the high-scale range is exceeded 

follow the procedures in paragraph (b)(1) of 

this section). 

* * * * * 

2.1.2.5 * * * 

(b) * * * 

(2) For units with two NOX spans and 

ranges, if the low range is exceeded, no 

further action is required, provided that the 

high range is available and its most recent 

calibration error test and linearity check have 

not expired. However, if either of these 

quality assurance tests has expired and the 

high range is not able to provide quality 

assured data at the time of the low range 

exceedance or at any time during the 

continuation of the exceedance, report the 

MPC as the NOX concentration until the 

readings return to the low range or until the 

high range is able to provide quality assured 

data (unless the reason that the high-scale 

range is not able to provide quality assured 

data is because the high-scale range has been 

exceeded; if the high-scale range is exceeded, 

follow the procedures in paragraph (b)(1) of 

this section). 

* * * * * 

2.1.3 CO2 and O2 Monitors 

* * * An alternative CO2 span value below 

6.0 percent may be used if an appropriate 

technical justification is included in the 

hardcopy monitoring plan. 

* * * * * 

3.2 * * * 

(3) For the linearity check and the 3-level 

system integrity check of an Hg monitor, 

which are required, respectively, under 

§ 75.20(c)(1)(ii) and (c)(1)(vi), the 

measurement error shall not exceed 10.0 

percent of the reference value at any of the 

three gas levels. To calculate the 

measurement error at each level, take the 

absolute value of the difference between the 

reference value and mean CEM response, 

divide the result by the reference value, and 

then multiply by 100. Alternatively, the 

results at any gas level are acceptable if the 

absolute value of the difference between the 

average monitor response and the average 

reference value, i.e., |R¥A| in Equation A–4 

of this appendix, does not exceed 0.8 μg/m3. 

The principal and alternative performance 

specifications in this section also apply to the 

single-level system integrity check described 

in section 2.6 of appendix B to this part. 

* * * * * 

5.1 Reference Gases 

* * * * * 

5.1.4 EPA Protocol Gases 

(a) An EPA Protocol Gas is a calibration gas 

mixture prepared and analyzed according to 

Section 2 of the ‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 1997, 

EPA–600/R–97/121 or such revised 

procedure as approved by the Administrator 

(EPA Traceability Protocol). 

(b) An EPA Protocol Gas must have a 

specialty gas producer-certified uncertainty 

(95-percent confidence interval) that must 

not be greater than 2.0 percent of the certified 

concentration (tag value) of the gas mixture. 

The uncertainty must be calculated using the 

statistical procedures (or equivalent 

statistical techniques) that are listed in 

Section 2.1.8 of the EPA Traceability 

Protocol. 

(c) On and after January 1, 2009, a specialty 

gas producer advertising calibration gas 

certification with the EPA Traceability 

Protocol or distributing calibration gases as 

‘‘EPA Protocol Gas’’ must participate in the 

EPA Protocol Gas Verification Program 

(PGVP) described in Section 2.1.10 of the 

EPA Traceability Protocol or it cannot use 

‘‘EPA’’ in any form of advertising for these 

products, unless approved by the 

Administrator. A specialty gas producer not 

participating in the PGVP may not certify a 

calibration gas as an EPA Protocol Gas, 

unless approved by the Administrator. 

(d) A copy of EPA–600/R–97/121 is 

available from the National Technical 

Information Service, 5285 Port Royal Road, 

Springfield, VA, 703–605–6585 or http:// 

www.ntis.gov, and from http://www.epa.gov/ 

ttn/emc/news.html or http://www.epa.gov/ 

appcdwww/tsb/index.html. 

* * * * * 

5.1.9 Mercury Standards 

For 7-day calibration error tests of Hg 

concentration monitors and for daily 

calibration error tests of Hg monitors, either 

NIST-traceable elemental Hg standards (as 

defined in § 72.2 of this chapter) or a NISTtraceable source of oxidized Hg (as defined 

in § 72.2 of this chapter) may be used. For 

linearity checks, NIST-traceable elemental Hg 

standards shall be used. For 3-level and 

single-point system integrity checks under 

§ 75.20(c)(1)(vi), sections 6.2(g) and 6.3.1 of 

this appendix, and sections 2.1.1, 2.2.1 and 

2.6 of appendix B to this part, a NISTtraceable source of oxidized Hg shall be used. 


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Alternatively, other NIST-traceable standards 

may be used for the required checks, subject 

to the approval of the Administrator. 

Notwithstanding these requirements, Hg 

calibration standards that are not NISTtraceable may be used for the tests described 

in this section until December 31, 2009. 

However, on and after January 1, 2010, only 

NIST-traceable calibration standards shall be 

used for these tests. 

* * * * * 

6.1 General Requirements 

* * * * * 

6.1.2 Requirements for Air Emission 

Testing Bodies 

(a) On and after January 1, 2009, any Air 

Emission Testing Body (AETB) conducting 

relative accuracy test audits of CEMS and 

sorbent trap monitoring systems under this 

part must conform to the requirements of 

ASTM D7036–04 (incorporated by reference 

under § 75.6 of this part). This section is not 

applicable to daily operation, daily 

calibration error checks, daily flow 

interference checks, quarterly linearity 

checks or routine maintenance of CEMS. 

(b) The AETB shall provide to the affected 

source(s) certification that the AETB operates 

in conformance with, and that data submitted 

to the Agency has been collected in 

accordance with, the requirements of ASTM 

D7036–04 (incorporated by reference under 

§ 75.6 of this part). This certification may be 

provided in the form of: 

(1) A certificate of accreditation of relevant 

scope issued by a recognized, national 

accreditation body; or 

(2) A letter of certification signed by a 

member of the senior management staff of the 

AETB. 

(c) The AETB shall either provide a 

Qualified Individual on-site to conduct or 

shall oversee all relative accuracy testing 

carried out by the AETB as required in ASTM 

D7036–04 (incorporated by reference under 

§ 75.6 of this part). The Qualified Individual 

shall provide the affected source(s) with 

copies of the qualification credentials 

relevant to the scope of the testing 

conducted. 

* * * * * 

6.2 Linearity Check (General Procedures) 

* * * Notwithstanding these 

requirements, if the SO2 or NOX span value 

for a particular monitor range is ≤ 30 ppm, 

that range is exempted from the linearity 

check requirements of this part, for initial 

certification, recertification, and for on-going 

quality-assurance. For units with two 

measurement ranges (high and low) for a 

particular parameter, perform a linearity 

check on both the low scale (except for SO2

or NOX span values ≤ 30 ppm) and the high 

scale. Note that for a NOX-diluent monitoring 

system with two NOX measurement ranges, if 

the low NOX scale has a span value ≤ 30 ppm 

and is exempt from linearity checks, this 

does not exempt either the diluent monitor 

or the high NOX scale (if the span is > 30 

ppm) from linearity check requirements. 

* * * * * 

(g) For Hg monitors, follow the guidelines 

in section 2.2.3 of this appendix in addition 

to the applicable procedures in section 6.2 

when performing the system integrity checks 

described in § 75.20(c)(1)(vi) and in sections 

2.1.1, 2.2.1 and 2.6 of appendix B to this part. 

(h) For Hg concentration monitors, if 

moisture is added to the calibration gas 

during the required linearity checks or 

system integrity checks, the moisture content 

of the calibration gas must be accounted for. 

Under these circumstances, the dry basis 

concentration of the calibration gas shall be 

used to calculate the linearity error or 

measurement error (as applicable). 

* * * * * 

6.3.1 Gas Monitor 7-day Calibration Error 

Test 

* * * Also for Hg monitors, if moisture is 

added to the calibration gas, the added 

moisture must be accounted for and the drybasis concentration of the calibration gas 

shall be used to calculate the calibration 

error. 

* * * * * 

6.4. Cycle Time Test 

Perform cycle time tests for each pollutant 

concentration monitor and continuous 

emission monitoring system while the unit is 

operating, according to the following 

procedures. Use a zero-level and a high-level 

calibration gas (as defined in section 5.2 of 

this appendix) alternately. For Hg monitors, 

the calibration gas used for this test may 

either be the elemental or oxidized form of 

Hg. To determine the downscale cycle time, 

measure the concentration of the flue gas 

emissions until the response stabilizes. 

Record the stable emissions value. Inject a 

zero-level concentration calibration gas into 

the probe tip (or injection port leading to the 

calibration cell, for in situ systems with no 

probe). Record the time of the zero gas 

injection, using the data acquisition and 

handling system (DAHS). Next, allow the 

monitor to measure the concentration of the 

zero gas until the response stabilizes. Record 

the stable ending calibration gas reading. 

Determine the downscale cycle time as the 

time it takes for 95.0 percent of the step 

change to be achieved between the stable 

stack emissions value and the stable ending 

zero gas reading. Then repeat the procedure, 

starting with stable stack emissions and 

injecting the high-level gas, to determine the 

upscale cycle time, which is the time it takes 

for 95.0 percent of the step change to be 

achieved between the stable stack emissions 

value and the stable ending high-level gas 

reading. Use the following criteria to assess 

when a stable reading of stack emissions or 

calibration gas concentration has been 

attained. A stable value is equivalent to a 

reading with a change of less than 2.0 percent 

of the span value for 2 minutes, or a reading 

with a change of less than 6.0 percent from 

the measured average concentration over 6 

minutes. Alternatively, the reading is 

considered stable if it changes by no more 

than 0.5 ppm, 0.5 μg/m3 (for Hg), or 0.2% 

CO2 or O2 (as applicable) for two minutes. 

(Owners or operators of systems which do 

not record data in 1-minute or 3-minute 

intervals may petition the Administrator 

under § 75.66 for alternative stabilization 

criteria). For monitors or monitoring systems 

that perform a series of operations (such as 

purge, sample, and analyze), time the 

injections of the calibration gases so they will 

produce the longest possible cycle time. 

Refer to Figures 6a and 6b in this appendix 

for example calculations of upscale and 

downscale cycle times. Report the slower of 

the two cycle times (upscale or downscale) 

as the cycle time for the analyzer. Prior to 

January 1, 2009 for the NOX-diluent 

continuous emission monitoring system test, 

either record and report the longer cycle time 

of the two component analyzers as the 

system cycle time or record the cycle time for 

each component analyzer separately (as 

applicable). On and after January 1, 2009, 

record the cycle time for each component 

analyzer separately. For time-shared systems, 

perform the cycle time tests at each probe 

locations that will be polled within the same 

15-minute period during monitoring system 

operations. To determine the cycle time for 

time-shared systems, at each monitoring 

location, report the sum of the cycle time 

observed at that monitoring location plus the 

sum of the time required for all purge cycles 

(as determined by the continuous emission 

monitoring system manufacturer) at each of 

the probe locations of the time-shared 

systems. For monitors with dual ranges, 

report the test results for each range 

separately. Cycle time test results are 

acceptable for monitor or monitoring system 

certification, recertification or diagnostic 

testing if none of the cycle times exceed 15 

minutes. The status of emissions data from a 

monitor prior to and during a cycle time test 

period shall be determined as follows: 

* * * * * 

6.5 * * * 

(e) Complete each single-load relative 

accuracy test audit within a period of 168 

consecutive unit operating hours, as defined 

in § 72.2 of this chapter (or, for CEMS 

installed on common stacks or bypass stacks, 

168 consecutive stack operating hours, as 

defined in § 72.2 of this chapter). 

Notwithstanding this requirement, up to 336 

consecutive unit or stack operating hours 

may be taken to complete the RATA of a Hg 

monitoring system, when ASTM 6784–02 

(incorporated by reference under § 75.6 of 

this part) or Method 29 in appendix A–8 to 

part 60 of this chapter is used as the 

reference method. For 2-level and 3-level 

flow monitor RATAs, complete all of the 

RATAs at all levels, to the extent practicable, 

within a period of 168 consecutive unit (or 

stack) operating hours; however, if this is not 

possible, up to 720 consecutive unit (or 

stack) operating hours may be taken to 

complete a multiple-load flow RATA. 

* * * * * 

6.5.2.1 * * * 

(e) The owner or operator shall report the 

upper and lower boundaries of the range of 

operation for each unit (or combination of 

units, for common stacks), in units of 

megawatts or thousands of lb/hr or mmBtu/ 

hr of steam production or ft/sec (as 

applicable), in the electronic monitoring plan 

required under § 75.53. Except for peaking 

units and LME units, the owner or operator 

shall indicate, in the electronic monitoring 

plan, the load level (or levels) designated as 

normal under this section and shall also 

indicate the two most frequently used load 

levels. 

* * * * * 


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6.5.6 * * * 

(c) For Hg monitoring systems, use the 

same basic approach for traverse point 

selection that is used for the other gas 

monitoring system RATAs, except that the 

stratification test provisions in sections 8.1.3 

through 8.1.3.5 of Method 30A shall apply, 

rather than the provisions of sections 6.5.6.1 

through 6.5.6.3 of this appendix. 

6.5.10 Reference Methods 

The following methods are from appendix 

A to part 60 of this chapter or have been 

published by ASTM, and are the reference 

methods for performing relative accuracy test 

audits under this part: Method 1 or 1A in 

appendix A–1 to part 60 of this chapter for 

siting; Method 2 in appendices A–1 and A–

2 to part 60 of this chapter or its allowable 

alternatives in appendix A to part 60 of this 

chapter (except for Methods 2B and 2E in 

appendix A–1 to part 60 of this chapter) for 

stack gas velocity and volumetric flow rate; 

Methods 3, 3A or 3B in appendix A–2 to part 

60 of this chapter for O2 and CO2; Method 4 

in appendix A–3 to part 60 of this chapter 

for moisture; Methods 6, 6A or 6C in 

appendix A–4 to part 60 of this chapter for 

SO2; Methods 7, 7A, 7C, 7D or 7E in 

appendix A–4 to part 60 of this chapter for 

NOX, excluding the exceptions of Method 7E 

in appendix A–4 to part 60 of this chapter 

identified in § 75.22(a)(5); and for Hg, either 

ASTM D6784–02 (the Ontario Hydro 

Method) (incorporated by reference under 

§ 75.6 of this part), Method 29 in appendix 

A–8 to part 60 of this chapter, Method 30A, 

or Method 30B When using Method 7E in 

appendix A–4 to part 60 of this chapter for 

measuring NOX concentration, total NOX, 

both NO and NO2, must be measured. 

* * * * * 

7.6 Bias Test and Adjustment Factor 

* * * * * 

7.6.1 * * * To calculate bias for a Hg 

monitoring system when using the Ontario 

Hydro Method or Method 29 in appendix A–

8 to part 60 of this chapter, ‘‘d’’ is, for each 

data point, the difference between the 

average Hg concentration value (in μg/m3) 

from the paired Ontario Hydro or Method 29 

in appendix A–8 to part 60 of this chapter 

sampling trains and the concentration 

measured by the monitoring system. For 

sorbent trap monitoring systems, use the 

average Hg concentration measured by the 

paired traps in the calculation of ‘‘d’’. 

* * * * * 

7.7 * * * 

(a) * * * 

Rref = Reference value of the flow-to-load 

ratio, from the most recent normal-load 

flow RATA, scfh/megawatts, scfh/1000 

lb/hr of steam, or scfh/(mmBtu/hr of 

steam output). 

* * * * * 

Lavg = Average unit load during the normalload flow RATA, megawatts, 1000 lb/hr 

of steam, or mmBtu/hr of thermal output. 

* * * * * 

(c) * * * 

(GHR)ref = Reference value of the gross heat 

rate at the time of the most recent 

normal-load flow RATA, Btu/kwh, Btu/ 

lb steam load, or Btu heat input/mmBtu 

steam output. 

* * * * * 

Lavg = Average unit load during the normalload flow RATA, megawatts, 1000 lb/hr 

of steam, or mmBtu/hr thermal output. 


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A. To determine the upscale cycle time 

(Figure 6a), measure the flue gas emissions 

until the response stabilizes. Record the 

stabilized value (see section 6.4 of this 

appendix for the stability criteria). 

B. Inject a high-level calibration gas into 

the port leading to the calibration cell or 

thimble (Point B). Allow the analyzer to 

stabilize. Record the stabilized value. 

C. Determine the step change. The step 

change is equal to the difference between the 

final stable calibration gas value (Point D) 

and the stabilized stack emissions value 

(Point A). 

D. Take 95% of the step change value and 

add the result to the stabilized stack 

emissions value (Point A). Determine the 

time at which 95% of the step change 

occurred (Point C). 

E. Calculate the upscale cycle time by 

subtracting the time at which the calibration 

gas was injected (Point B) from the time at 

which 95% of the step change occurred 

(Point C). In this example, upscale cycle time 

= (11¥5) = 6 minutes. 

F. To determine the downscale cycle time 

(Figure 6b) repeat the procedures above, 

except that a zero gas is injected when the 

flue gas emissions have stabilized, and 95% 

of the step change in concentration is 

subtracted from the stabilized stack 

emissions value. 

G. Compare the upscale and downscale 

cycle time values. The longer of these two 

times is the cycle time for the analyzer. 

■ 41. Appendix B to Part 75 is amended 

by: 

■ a. Adding section 1.1.4; 

■ b. Revising section 2.1.1; 

■ c. Revising paragraph (2) of section 

2.1.1.2; 

■ d. Revising paragraph (2) of section 

2.1.5.1; 

■ e. Adding paragraph (3) to section 

2.1.5.1; 

■ f. Adding a new fourth sentence to 

paragraph (e) of section 2.2.3; 

■ g. Revising the terms ‘‘Rh’’ and ‘‘Lh’’ in 

paragraph (a) of section 2.2.5; 

■ h. Revising the terms ‘‘(GHR)h’’ and 

‘‘Lh’’ in paragraph (a)(2) of section 2.2.5; 

■ i. Removing the word ‘‘five’’ and 

adding in its place the word ‘‘twenty’’, 

and by removing the word ‘‘years’’ and 

adding in its place the word ‘‘quarters’’, 

in paragraph (c)(4) of section 2.3.1.3; 

■ j. Revising paragraphs (d) and (g) of 

section 2.3.2; 

■ k. Revising paragraphs (a)(2) and (c) of 

section 2.3.3; 

■ l. Adding paragraph (d) to section 

2.3.3; 

■ m. Revising section 2.6; 

■ n. Revising Figure 1; and 

■ o. Revising Figure 2. 

The revisions and additions read as 

follows: 

Appendix B to Part 75—Quality 

Assurance and Quality Control 

Procedures 

1. Quality Assurance/Quality Control 

Program 

* * * * * 

1.1.4 The requirements in section 6.1.2 of 

appendix A to this part shall be met by any 

Air Emissions Testing Body (AETB) 

performing the semiannual/annual RATAs 

described in section 2.3 of this appendix and 

the Hg emission tests described in §§ 75.81(c) 

and 75.81(d)(4). 

* * * * * 

2. Frequency of Testing 

* * * * * 

2.1.1 Calibration Error Test 

Except as provided in section 2.1.1.2 of 

this appendix, perform the daily calibration 

error test of each gas monitoring system 

(including moisture monitoring systems 

consisting of wet- and dry-basis O2 analyzers) 

according to the procedures in section 6.3.1 

of appendix A to this part, and perform the 

daily calibration error test of each flow 

monitoring system according to the 

procedure in section 6.3.2 of appendix A to 

this part. When two measurement ranges 

(low and high) are required for a particular 

parameter, perform sufficient calibration 

error tests on each range to validate the data 

recorded on that range, according to the 

criteria in section 2.1.5 of this appendix. 

* * * * * 


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2.1.1.2 * * * 

(2) For each monitoring system that has 

passed the off-line calibration demonstration, 

off-line calibration error tests may be used on 

a limited basis to validate data, in accordance 

with paragraph (2) in section 2.1.5.1 of this 

appendix. 

* * * * * 

2.1.5.1 * * * 

(2) For a monitor that has passed the offline calibration demonstration, a 

combination of on-line and off-line 

calibration error tests may be used to validate 

data from the monitor, as follows. For a 

particular unit (or stack) operating hour, data 

from a monitor may be validated using a 

successful off-line calibration error test if: (a) 

An on-line calibration error test has been 

passed within the previous 26 unit (or stack) 

operating hours; and (b) the 26 clock hour 

data validation window for the off-line 

calibration error test has not expired. If either 

of these conditions is not met, then the data 

from the monitor are invalid with respect to 

the daily calibration error test requirement. 

Data from the monitor shall remain invalid 

until the appropriate on-line or off-line 

calibration error test is successfully 

completed so that both conditions (a) and (b) 

are met. 

(3) For units with two measurement ranges 

(low and high) for a particular parameter, 

when separate analyzers are used for the low 

and high ranges, a failed or expired 

calibration on one of the ranges does not 

affect the quality-assured data status on the 

other range. For a dual-range analyzer (i.e., a 

single analyzer with two measurement 

scales), a failed calibration error test on either 

the low or high scale results in an out-ofcontrol period for the monitor. Data from the 

monitor remain invalid until corrective 

actions are taken and ‘‘hands-off’’ calibration 

error tests have been passed on both ranges. 

However, if the most recent calibration error 

test on the high scale was passed but has 

expired, while the low scale is up-to-date on 

its calibration error test requirements (or 

vice-versa), the expired calibration error test 

does not affect the quality-assured status of 

the data recorded on the other scale. 

* * * * * 

2.2.3 * * * 

(e) * * * For a dual-range analyzer, 

‘‘hands-off’’ linearity checks must be passed 

on both measurement scales to end the outof-control period. * * * 

* * * * * 

2.2.5 * * * 

(a) * * * 

Rh = Hourly value of the flow-to-load ratio, 

scfh/megawatts, scfh/1000 lb/hr of 

steam, or scfh/(mmBtu/hr thermal 

output). 

* * * * * 

Lh = Hourly unit load, megawatts, 1000 lb/ 

hr of steam, or mmBtu/hr thermal 

output; must be within + 10.0 percent of 

Lavg during the most recent normal-load 

flow RATA. 

* * * * * 

(2) * * * 

(GHR)h = Hourly value of the gross heat rate, 

Btu/kwh, Btu/lb steam load, or 1000 

mmBtu heat input/mmBtu thermal 

output. 

* * * * * 

Lh = Hourly unit load, megawatts, 1000 lb/ 

hr of steam, or mmBtu/hr thermal output; 

must be within + 10.0 percent of Lavg during 

the most recent normal-load flow RATA. 

* * * * * 

2.3.2 * * * 

(d) For single-load (or single-level) RATAs, 

if a daily calibration error test is failed during 

a RATA test period, prior to completing the 

test, the RATA must be repeated. Data from 

the monitor are invalidated prospectively 

from the hour of the failed calibration error 

test until the hour of completion of a 

subsequent successful calibration error test. 

The subsequent RATA shall not be 

commenced until the monitor has 

successfully passed a calibration error test in 

accordance with section 2.1.3 of this 

appendix. Notwithstanding these 

requirements, when ASTM D6784–02 

(incorporated by reference under § 75.6 of 

this part) or Method 29 in appendix A–8 to 

part 60 of this chapter is used as the 

reference method for the RATA of a Hg 

CEMS, if a calibration error test of the CEMS 

is failed during a RATA test period, any test 

run(s) completed prior to the failed 

calibration error test need not be repeated; 

however, the RATA may not continue until 

a subsequent calibration error test of the Hg 

CEMS has been passed. For multiple-load (or 

multiple-level) flow RATAs, each load level 

(or operating level) is treated as a separate 

RATA (i.e., when a calibration error test is 

failed prior to completing the RATA at a 

particular load level (or operating level), only 

the RATA at that load level (or operating 

level) must be repeated; the results of any 

previously-passed RATA(s) at the other load 

level(s) (or operating level(s)) are unaffected, 

unless re-linearization of the monitor is 

required to correct the problem that caused 

the calibration failure, in which case a 

subsequent 3-load (or 3-level) RATA is 

required), except as otherwise provided in 

section 2.3.1.3(c)(5) of this appendix. 

* * * * * 

(g) Data validation for failed RATAs for a 

CO2 pollutant concentration monitor (or an 

O2 monitor used to measure CO2 emissions), 

a NOX pollutant concentration monitor, and 

a NOX-diluent monitoring system shall be 

done according to paragraphs (g)(1) and (g)(2) 

of this section: 

(1) For a CO2 pollutant concentration 

monitor (or an O2 monitor used to measure 

CO2 emissions) which also serves as the 

diluent component in a NOX-diluent 

monitoring system, if the CO2 (or O2) RATA 

is failed, then both the CO2 (or O2) monitor 

and the associated NOX-diluent system are 

considered out-of-control, beginning with the 

hour of completion of the failed CO2 (or O2) 

monitor RATA, and continuing until the 

hour of completion of subsequent hands-off 

RATAs which demonstrate that both systems 

have met the applicable relative accuracy 

specifications in sections 3.3.2 and 3.3.3 of 

appendix A to this part, unless the option in 

paragraph (b)(3) of this section to use the data 

validation procedures and associated 

timelines in § 75.20(b)(3)(ii) through (b)(3)(ix) 

has been selected, in which case the 

beginning and end of the out-of-control 

period shall be determined in accordance 

with § 75.20(b)(3)(vii)(A) and (B). 

(2) This paragraph (g)(2) applies only to a 

NOX pollutant concentration monitor that 

serves both as the NOX component of a NOX

concentration monitoring system (to measure 

NOX mass emissions) and as the NOX

component in a NOX-diluent monitoring 

system (to measure NOX emission rate in lb/ 

mmBtu). If the RATA of the NOX

concentration monitoring system is failed, 

then both the NOX concentration monitoring 

system and the associated NOX-diluent 

monitoring system are considered out-ofcontrol, beginning with the hour of 

completion of the failed NOX concentration 

RATA, and continuing until the hour of 

completion of subsequent hands-off RATAs 

which demonstrate that both systems have 

met the applicable relative accuracy 

specifications in sections 3.3.2 and 3.3.7 of 

appendix A to this part, unless the option in 

paragraph (b)(3) of this section to use the data 

validation procedures and associated 

timelines in § 75.20(b)(3)(ii) through (b)(3)(ix) 

has been selected, in which case the 

beginning and end of the out-of-control 

period shall be determined in accordance 

with § 75.20(b)(3)(vii)(A) and (B). 

* * * * * 

2.3.3 RATA Grace Period 

(a) * * * 

(2) A required 3-load flow RATA has not 

been performed by the end of the calendar 

quarter in which it is due; or 

* * * * * 

(c) If, at the end of the 720 unit (or stack) 

operating hour grace period, the RATA has 

not been completed, data from the 

monitoring system shall be invalid, 

beginning with the first unit operating hour 

following the expiration of the grace period. 

Data from the CEMS remain invalid until the 

hour of completion of a subsequent hands-off 

RATA. The deadline for the next test shall be 

either two QA operating quarters (if a 

semiannual RATA frequency is obtained) or 

four QA operating quarters (if an annual 

RATA frequency is obtained) after the quarter 

in which the RATA is completed, not to 

exceed eight calendar quarters. 

* * * * * 

(d) When a RATA is done during a grace 

period in order to satisfy a RATA 

requirement from a previous quarter, the 

deadline for the next RATA shall determined 

as follows: 

(1) If the grace period RATA qualifies for 

a reduced, (i.e., annual), RATA frequency the 

deadline for the next RATA shall be set at 

three QA operating quarters after the quarter 

in which the grace period test is completed. 

(2) If the grace period RATA qualifies for 

the standard, (i.e., semiannual), RATA 

frequency the deadline for the next RATA 

shall be set at two QA operating quarters after 

the quarter in which the grace period test is 

completed. 

(3) Notwithstanding these requirements, no 

more than eight successive calendar quarters 

shall elapse after the quarter in which the 

grace period test is completed, without a 

subsequent RATA having been conducted. 

* * * * * 


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2.6 System Integrity Checks for Hg 

Monitors 

For each Hg concentration monitoring 

system (except for a Hg monitor that does not 

have a converter), perform a single-point 

system integrity check weekly, i.e., at least 

once every 168 unit or stack operating hours, 

using a NIST-traceable source of oxidized Hg. 

Perform this check using a mid- or high-level 

gas concentration, as defined in section 5.2 

of appendix A to this part. The performance 

specifications in paragraph (3) of section 3.2 

of appendix A to this part must be met, 

otherwise the monitoring system is 

considered out-of-control, from the hour of 

the failed check until a subsequent system 

integrity check is passed. If a required system 

integrity check is not performed and passed 

within 168 unit or stack operating hours of 

last successful check, the monitoring system 

shall also be considered out of control, 

beginning with the 169th unit or stack 

operating hour after the last successful check, 

and continuing until a subsequent system 

integrity check is passed. This weekly check 

is not required if the daily calibration 

assessments in section 2.1.1 of this appendix 

are performed using a NIST-traceable source 

of oxidized Hg. 

* * * * * 

FIGURE 1 TO APPENDIX B OF PART 75.—QUALITY ASSURANCE TEST REQUIREMENTS

Test 

Basic QA test frequency requirements * 

Daily * Weekly Quarterly * Semiannual * Annual 

Calibration Error Test (2 pt.) ................................................................ ✔ .................... .................... .................... ....................

Interference Check (flow) ..................................................................... ✔ .................... .................... .................... ....................

Flow-to-Load Ratio ............................................................................... .................... .................... ✔ .................... ....................

Leak Check (DP flow monitors) ........................................................... .................... .................... ✔ .................... ....................

Linearity Check or System Integrity Check ** (3 pt.) ............................ .................... .................... ✔ .................... ....................

Single-point System Integrity Check ** ................................................. .................... ✔ .................... .................... ....................

RATA (SO2, NOX, CO2, O2, H2O) 1 ...................................................... .................... .................... .................... ✔ ....................

RATA (All Hg monitoring systems) ...................................................... .................... .................... .................... .................... ✔ 

RATA (flow) 1 2 ...................................................................................... .................... .................... .................... ✔ ....................

*‘‘Daily’’ means operating days, only. ‘‘Weekly’’ means once every 168 unit or stack operating hours. ‘‘Quarterly’’ means once every QA operating quarter. ‘‘Semiannual’’ means once every two QA operating quarters. ‘‘Annual’’ means once every four QA operating quarters. 

** The system integrity check applies only to Hg monitors with converters. The single-point weekly system integrity check is not required if daily 

calibrations are performed using a NIST-traceable source of oxidized Hg. The 3-point quarterly system integrity check is not required if a linearity 

check is performed. 1 Conduct RATA annually (i.e., once every four QA operating quarters), if monitor meets accuracy requirements to qualify for less frequent testing. 2For flow monitors installed on peaking units, bypass stacks, or units that qualify for single-level RATA testing under section 6.5.2(e) of this 

part, conduct all RATAs at a single, normal load (or operating level). For other flow monitors, conduct annual RATAs at two load levels (or operating levels). Alternating single-load and 2-load (or single-level and 2-level) RATAs may be done if a monitor is on a semiannual frequency. A 

single-load (or single-level) RATA may be done in lieu of a 2-load (or 2-level) RATA if, since the last annual flow RATA, the unit has operated at 

one load level (or operating level) for ≥85.0 percent of the time. A 3-level RATA is required at least once every five calendar years and whenever 

a flow monitor is re-linearized, except for flow monitors exempted from 3-level RATA testing under section 6.5.2(b) or 6.5.2(e) of appendix A to 

this part. 

FIGURE 2 TO APPENDIX B OF PART 75.—RELATIVE ACCURACY TEST FREQUENCY INCENTIVE SYSTEM

RATA Semiannual W

(percent) Annual W

SO2 or NOXY ....................... 7.5% <RA ≤10.0% or ±15.0 ppm X ................................. RA ≤ 7.5% or ±12.0 ppm X. 

SO2-diluent ........................... 7.5% <RA ≤10.0% or ±0.030 lb/mmBtu X ....................... RA ≤7.5% or ±0.025 lb/mmBtu =G5X. 

NOX-diluent .......................... 7.5% <RA ≤10.0% or ±0.020 lb/mmBtu X ....................... RA ≤ 7.5% or ±0. 015 lb/mmBtu X. 

Flow ...................................... 7.5% < RA ≤ 10.0% or ±2.0 fps X ................................... RA ≤ 7.5% or ±1.5 fps X. 

CO2 or O2 ............................. 7.5% < RA ≤ 10.0% or ±1.0% CO2/O2 X ......................... RA ≤ 7.5% or ±0.7% CO2/O2

X. 

Hg X ...................................... N/A .................................................................................. RA < 20.0% or ± 1.0 μg/scm X. 

Moisture ............................... 7.5% <RA ≤10.0% or ±1.5% H2O X ................................ RA ≤7.5% or ±1.0% H2O X. 

W The deadline for the next RATA is the end of the second (if semiannual) or fourth (if annual) successive QA operating quarter following the 

quarter in which the CEMS was last tested. Exclude calendar quarters with fewer than 168 unit operating hours (or, for common stacks and bypass stacks, exclude quarters with fewer than 168 stack operating hours) in determining the RATA deadline. For SO2 monitors, QA operating 

quarters in which only very low sulfur fuel as defined in § 72.2, is combusted may also be excluded. However, the exclusion of calendar quarters 

is limited as follows: the deadline for the next RATA shall be no more than 8 calendar quarters after the quarter in which a RATA was last performed. X The difference between monitor and reference method mean values applies to moisture monitors, CO2, and O2 monitors, low emitters of 

SO2, NOX, or Hg, or and low flow, only. The specifications for Hg monitors also apply to sorbent trap monitoring systems. Y A NOX concentration monitoring system used to determine NOX mass emissions under § 75.71. 

■ 42. Appendix D to Part 75 is amended 

by: 

■ a. Revising section 2.1.5.1; 

■ b. Removing all ‘‘±’’ symbols from 

paragraph (c) of section 2.1.6.1; 

■ c. Revising the Rbase and Lavg variable 

definitions in paragraph (a) of section 

2.1.7.1; 

■ d. Revising the terms ‘‘(GHR) base’’ and 

‘‘Lavg’’ in paragraph (c) of section 

2.1.7.1; 

■ e. Revising the terms ‘‘Rh’’ and ‘‘Lh’’ in 

paragraph (a) of section 2.1.7.2; 

■ f. Revising the terms ‘‘(GHR) h’’ and 

‘‘Lh’’ in paragraph (c) of section 2.1.7.2; 

■ g. Removing ‘‘D4177–82 (Reapproved 

1990)’’ and adding in its place ‘‘D4177–

95 (Reapproved 2000)’’, in the first 

sentence of section 2.2.3; 

■ h. Removing ‘‘D4057–88 ‘Standard 

Practice for Manual Sampling of 

Petroleum and Petroleum Products’

(incorporated by reference under 

§ 75.6)’’ and adding in its place, ‘‘ASTM 

D4057–95 (Reapproved 2000), Standard 

Practice for Manual Sampling of 

Petroleum and Petroleum Products 


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(incorporated by reference under § 75.6 

of this part)’’, in sections 2.2.4.1 and 

2.2.4.2, and in paragraph (c) of section 

2.2.4.3; 

■ i. Revising sections 2.2.5, 2.2.6, and 

2.2.7; 

■ j. Revising paragraphs (a)(2) and (e) of 

section 2.3.1.4; 

■ k. Revising section 2.3.3.1.2; 

■ l. Revising section 2.3.4; 

■ m. Adding two sentences at the end of 

section 2.3.4.1; 

■ n. Revising paragraphs (b)(2) and (c) of 

section 2.3.7; 

■ o. Revising section 3.2.2; and 

■ p. Revising section 3.5.1. 

The revisions and additions read as 

follows: 

Appendix D to Part 75—Optional SO2

Emissions Data Protocol for Gas-Fired 

and Oil-Fired Units. 

* * * * * 

2. Procedure 

* * * * * 

2.1.5.1 Use the procedures in the 

following standards to verify flowmeter 

accuracy or design, as appropriate to the type 

of flowmeter: ASME MFC–3M–2004, 

Measurement of Fluid Flow in Pipes Using 

Orifice, Nozzle, and Venturi; ASME MFC–

4M–1986 (Reaffirmed 1997), Measurement of 

Gas Flow by Turbine Meters; American Gas 

Association Report No. 3, Orifice Metering of 

Natural Gas and Other Related Hydrocarbon 

Fluids Part 1: General Equations and 

Uncertainty Guidelines (October 1990 

Edition), Part 2: Specification and 

Installation Requirements (February 1991 

Edition), and Part 3: Natural Gas 

Applications (August 1992 edition) 

(excluding the modified flow-calculation 

method in part 3); Section 8, Calibration from 

American Gas Association Transmission 

Measurement Committee Report No. 7: 

Measurement of Gas by Turbine Meters 

(Second Revision, April 1996); ASME–MFC–

5M–1985, (Reaffirmed 1994), Measurement of 

Liquid Flow in Closed Conduits Using 

Transit-Time Ultrasonic Flowmeters; ASME 

MFC–6M–1998, Measurement of Fluid Flow 

in Pipes Using Vortex Flowmeters; ASME 

MFC–7M–1987 (Reaffirmed 1992), 

Measurement of Gas Flow by Means of 

Critical Flow Venturi Nozzles; ISO 8316: 

1987(E) Measurement of Liquid Flow in 

Closed Conduits-Method by Collection of the 

Liquid in a Volumetric Tank; American 

Petroleum Institute (API) Manual of 

Petroleum Measurement Standards, Chapter 

4—Proving Systems, Section 2—Pipe Provers 

(Provers Accumulating at Least 10,000 

Pulses), Second Edition, March 2001, and 

Section 5—Master-Meter Provers, Second 

Edition, May 2000; American Petroleum 

Institute (API) Manual of Petroleum 

Measurement Standards, Chapter 22—

Testing Protocol, Section 2—Differential 

Pressure Flow Measurement Devices, First 

Edition, August 2005; or ASME MFC–9M–

1988 (Reaffirmed 2001), Measurement of 

Liquid Flow in Closed Conduits by Weighing 

Method, for all other flowmeter types (all 

incorporated by reference under § 75.6 of this 

part). The Administrator may also approve 

other procedures that use equipment 

traceable to National Institute of Standards 

and Technology standards. Document such 

procedures, the equipment used, and the 

accuracy of the procedures in the monitoring 

plan for the unit, and submit a petition 

signed by the designated representative 

under § 75.66(c). If the flowmeter accuracy 

exceeds 2.0 percent of the upper range value, 

the flowmeter does not qualify for use under 

this part. 

* * * * * 

2.1.7.1 

(a) * * * 

Where: 

Rbase = Value of the fuel flow rate-to-load 

ratio during the baseline period; 100 

scfh/MWe, 100 scfh/klb per hour steam 

load, or 100 scfh/mmBtu per hour 

thermal output for gas-firing; (lb/hr)/ 

MWe, (lb/hr)/klb per hour steam load, or 

(lb/hr)/mmBtu per hour thermal output 

for oil-firing. 

* * * * * 

Lavg = Arithmetic average unit load during 

the baseline period, megawatts, 1000 lb/ 

hr of steam, or mmBtu/hr thermal 

output. 

* * * * * 

(c) * * * 

Where: 

(GHR)base = Baseline value of the gross heat 

rate during the baseline period, Btu/kwh, 

Btu/lb steam load, or 1000mmBtu heat 

input/mmBtu thermal output. 

* * * * * 

Lavg = Average (mean) unit load during the 

baseline period, megawatts, 1000 lb/hr of 

steam, or mmBtu/hr thermal output. 

* * * * * 

2.1.7.2 

(a) * * * 

Where: 

Rh = Hourly value of the fuel flow rate-toload ratio; 100 scfh/MWe, (lb/hr)/MWe, 

100 scfh/1000 lb/hr of steam load, (lb/ 

hr)/1000 lb/hr of steam load, 100 scfh/ 

(mmBtu/hr of steam load), or (lb/hr)/ 

(mmBtu/hr thermal output). 

* * * * * 

Lh = Hourly unit load, megawatts, 1000 lb/ 

hr of steam, or mmBtu/hr thermal 

output. 

* * * * * 

(c) * * * 

Where: 

(GHR)h = Hourly value of the gross heat rate, 

Btu/kwh, Btu/lb steam load, or mmBtu 

heat input/mmBtu thermal output. 

* * * * * 

Lh = Hourly unit load, megawatts, 1000 lb/ 

hr of steam, or mmBtu/hr thermal 

output. 

* * * * * 

2.2.5 For each oil sample that is taken onsite at the affected facility, split and label the 

sample and maintain a portion (at least 200 

cc) of it throughout the calendar year and in 

all cases for not less than 90 calendar days 

after the end of the calendar year allowance 

accounting period. This requirement does not 

apply to oil samples taken from the fuel 

supplier’s storage container, as described in 

section 2.2.4.3 of this appendix. Analyze oil 

samples for percent sulfur content by weight 

in accordance with ASTM D129–00, 

Standard Test Method for Sulfur in 

Petroleum Products (General Bomb Method), 

ASTM D1552–01, Standard Test Method for 

Sulfur in Petroleum Products (HighTemperature Method), ASTM D2622–98, 

Standard Test Method for Sulfur in 

Petroleum Products by Wavelength 

Dispersive X-ray Fluorescence Spectrometry, 

ASTM D4294–98, Standard Test Method for 

Sulfur in Petroleum and Petroleum Products 

by Energy-Dispersive X-ray Fluorescence 

Spectrometry, or 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 (all 

incorporated by reference under § 75.6 of this 

part). Alternatively, the oil samples may be 

analyzed for percent sulfur by any consensus 

standard method prescribed for the affected 

unit under part 60 of this chapter. 

2.2.6 Where the flowmeter records 

volumetric flow rate rather than mass flow 

rate, analyze oil samples to determine the 

density or specific gravity of the oil. 

Determine the density or specific gravity of 

the oil sample in accordance with ASTM 

D287–92 (Reapproved 2000), Standard Test 

Method for API Gravity of Crude Petroleum 

and Petroleum Products (Hydrometer 

Method), ASTM D1217–93 (Reapproved 

1998), Standard Test Method for Density and 

Relative Density (Specific Gravity) of Liquids 

by Bingham Pycnometer, ASTM D1481–93 

(Reapproved 1997), Standard Test Method for 

Density and Relative Density (Specific 

Gravity) of Viscous Materials by Lipkin 

Bicapillary Pycnometer, ASTM D1480–93 

(Reapproved 1997), Standard Test Method for 

Density and Relative Density (Specific 

Gravity) of Viscous Materials by Bingham 

Pycnometer, ASTM D1298–99, Standard Test 

Method for Density, Relative Density 

(Specific Gravity), or API Gravity of Crude 

Petroleum and Liquid Petroleum Products by 

Hydrometer Method, or ASTM D4052–96 

(Reapproved 2002), Standard Test Method for 

Density and Relative Density of Liquids by 

Digital Density Meter (all incorporated by 

reference under § 75.6 of this part). 

Alternatively, the oil samples may be 

analyzed for density or specific gravity by 

any consensus standard method prescribed 

for the affected unit under part 60 of this 

chapter. 

2.2.7 Analyze oil samples to determine 

the heat content of the fuel. Determine oil 

heat content in accordance with ASTM 

D240–00, Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by 

Bomb Calorimeter, ASTM D4809–00, 

Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by 

Bomb Calorimeter (Precision Method), or 

ASTM D5865–01a, Standard Test Method for 

Gross Calorific Value of Coal and Coke (all 

incorporated by reference under § 75.6 of this 

part) or any other procedures listed in section 

5.5 of appendix F of this part. Alternatively, 


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the oil samples may be analyzed for heat 

content by any consensus standard method 

prescribed for the affected unit under part 60 

of this chapter. 

* * * * * 

2.3.1.4 * * * 

(a) * * * 

(2) Historical fuel sampling data for the 

previous 12 months, documenting the total 

sulfur content of the fuel and the GCV and/ 

or percentage by volume of methane. The 

results of all sample analyses obtained by or 

provided to the owner or operator in the 

previous 12 months shall be used in the 

demonstration, and each sample result must 

meet the definition of pipeline natural gas in 

§ 72.2 of this chapter, except where the 

results of at least 100 daily (or more frequent) 

total sulfur samples are provided by the fuel 

supplier. In that case you may opt to convert 

these data to monthly averages and then if, 

for each month, the average total sulfur 

content is 0.5 grains/100 scf or less, and if 

the GCV or percent methane requirement is 

also met, the fuel qualifies as pipeline natural 

gas. Alternatively, the fuel qualifies as 

pipeline natural gas if ≥ 98 percent of the 100 

(or more) samples have a total sulfur content 

of 0.5 grains/100 scf or less and if the GCV 

or percent methane requirement is also met; 

or 

* * * * * 

(e) If a fuel qualifies as pipeline natural gas 

based on the specifications in a fuel contract 

or tariff sheet, no additional, on-going 

sampling of the fuel’s total sulfur content is 

required, provided that the contract or tariff 

sheet is current, valid and representative of 

the fuel combusted in the unit. If the fuel 

qualifies as pipeline natural gas based on fuel 

sampling and analysis, on-going sampling of 

the fuel’s sulfur content is required annually 

and whenever the fuel supply source 

changes. For the purposes of this paragraph 

(e), sampling ‘‘annually’’ means that at least 

one sample is taken in each calendar year. If 

the results of at least 100 daily (or more 

frequent) total sulfur samples have been 

provided by the fuel supplier since the last 

annual assessment of the fuel’s sulfur 

content, the data may be used as follows to 

satisfy the annual sampling requirement for 

the current year. If this option is chosen, all 

of the data provided by the fuel supplier 

shall be used. First, convert the data to 

monthly averages. Then, if, for each month, 

the average total sulfur content is 0.5 grains/ 

100 scf or less, and if the GCV or percent 

methane requirement is also met, the fuel 

qualifies as pipeline natural gas. 

Alternatively, the fuel qualifies as pipeline 

natural gas if the analysis of the 100 (or more) 

total sulfur samples since the last annual 

assessment shows that ≥ 98 percent of the 

samples have a total sulfur content of 0.5 

grains/100 scf or less and if the GCV or 

percent methane requirement is also met. 

The effective date of the annual total sulfur 

sampling requirement is January 1, 2003. 

* * * * * 

2.3.3.1.2 Use one of the following 

methods when using manual sampling (as 

applicable to the type of gas combusted) to 

determine the sulfur content of the fuel: 

ASTM D1072–06, Standard Test Method for 

Total Sulfur in Fuel Gases by Combustion 

and Barium Chloride Titration, ASTM 

D4468–85 (Reapproved 2006), Standard Test 

Method for Total Sulfur in Gaseous Fuels by 

Hydrogenolysis and Rateometric Colorimetry, 

ASTM D5504–01, Standard Test Method for 

Determination of Sulfur Compounds in 

Natural Gas and Gaseous Fuels by Gas 

Chromatography and Chemiluminescence, 

ASTM D6667–04, Standard Test Method for 

Determination of Total Volatile Sulfur in 

Gaseous Hydrocarbons and Liquefied 

Petroleum Gases by Ultraviolet Fluorescence, 

or ASTM D3246–96, Standard Test Method 

for Sulfur in Petroleum Gas by Oxidative 

Microcoulometry, (all incorporated by 

reference under § 75.6 of this part). 

Alternatively, the gas samples may be 

analyzed for percent sulfur by any consensus 

standard method prescribed for the affected 

unit under part 60 of this chapter. 

* * * * * 

2.3.4 Gross Calorific Values for Gaseous 

Fuels 

Determine the GCV of each gaseous fuel at 

the frequency specified in this section, using 

one of the following methods: ASTM D1826–

94 (Reapproved 1998), ASTM D3588–98, 

ASTM D4891–89 (Reapproved 2006), GPA 

Standard 2172–96, Calculation of Gross 

Heating Value, Relative Density and 

Compressibility Factor for Natural Gas 

Mixtures from Compositional Analysis, or 

GPA Standard 2261–00, Analysis for Natural 

Gas and Similar Gaseous Mixtures by Gas 

Chromatography (all incorporated by 

reference under § 75.6 of this part). Use the 

appropriate GCV value, as specified in 

section 2.3.4.1, 2.3.4.2, or 2.3.4.3 of this 

appendix, in the calculation of unit hourly 

heat input rates. Alternatively, the gas 

samples may be analyzed for heat content by 

any consensus standard method prescribed 

for the affected unit under part 60 of this 

chapter. 

2.3.4.1 GCV of Pipeline Natural Gas 

* * * If multiple GCV samples are taken 

and analyzed in a particular month, the GCV 

values from all samples shall be averaged 

arithmetically to obtain the monthly GCV. 

Then, apply the monthly average GCV value 

as described in paragraph (c) in section 2.3.7 

of this appendix. 

* * * * * 

2.3.7 * * * 

(b) * * * 

(2) For natural gas, if only one sample is 

taken, apply the results beginning at the date 

on which the sample was taken. If multiple 

samples are taken and averaged, apply the 

results beginning at the date on which the 

last sample used in the annual assessment 

was taken; 

* * * * * 

(c) For monthly samples of the fuel GCV: 

(1) If the actual monthly value is to be used 

in the calculations and only one sample is 

taken, apply the results starting from the date 

on which the sample was taken. If multiple 

samples are taken and averaged, apply the 

monthly average GCV value to the entire 

month; or 

(2) If an assumed value (contract maximum 

or highest value from previous year’s 

samples) is to be used in the calculations, 

apply the assumed value to all hours in each 

month of the quarter unless a higher value is 

obtained in a monthly GCV sample (or, if 

multiple samples are taken and averaged, if 

the monthly average exceeds the assumed 

value). In that case, if only one monthly 

sample is taken, use the sampled value, 

starting from the date on which the sample 

was taken. If multiple samples are taken and 

averaged, use the average value for the entire 

month in which the assumed value was 

exceeded. Consider the sample (or, if 

applicable, monthly average) results to be the 

new assumed value. Continue using the new 

assumed value unless and until one of the 

following occurs (as applicable to the 

reporting option selected): The assumed 

value is superseded by a higher value from 

a subsequent monthly sample (or by a higher 

monthly average); or the assumed value is 

superseded by a new contract in which case 

the new contract value becomes the assumed 

value at the time the fuel specified under the 

new contract begins to be combusted in the 

unit; or both the calendar year in which the 

new sampled value (or monthly average) 

exceeded the assumed value and the 

subsequent calendar year have elapsed. 

* * * * * 

3.2.2 Convert density, specific gravity, or 

API gravity of the oil sample to density of the 

oil sample at the sampling location’s 

temperature using ASTM D1250–07, 

Standard Guide for Use of the Petroleum 

Measurement Tables (incorporated by 

reference under (§ 75.6 of this part). 

* * * * * 

3.5.1 Hourly SO2 Mass Emissions from 

the Combustion of all Fuels. Determine the 

total mass emissions for each hour from the 

combustion of all fuels using Equation D–12 

(On and after January 1, 2009, determine the 

total mass emission rate (in lbs/hr) for each 

hour from the combustion of all fuels by 

dividing Equation D–12 by the actual unit 

operating time for the hour): 

M SO t Eq So hr rate i

all fuels

2 1 2 − −

−

= ∑ ( . D-12)

Where: 

MSO2-hr = Total mass of SO2 emissions from 

all fuels combusted during the hour, lb. 

SO2 rate¥I = SO2 mass emission rate for each 

type of gas or oil fuel combusted during 

the hour, lb/hr. 

ti = Time each gas or oil fuel was combusted 

for the hour (fuel usage time), fraction of 

an hour (in equal increments that can 


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range from one hundredth to one quarter 

of an hour, at the option of the owner or 

operator). 

* * * * * 

■ 43. Appendix E to part 75 is amended 

by: 

■ a. Adding a new sentence to the end 

of section 2.1; 

■ b. Revising the seventh sentence of 

section 2.1.2.1; 

■ c. Revising sections 2.1.2.2 and 

2.1.2.3; 

■ d. Removing the phrase ‘‘(MWge or 

steam load in 1000 lb/hr)’’ and adding 

in its place the phrase ‘‘(MWge or steam 

load in 1000 lb/hr, or mmBtu/hr thermal 

output)’’, in section 2.4.1; 

■ e. Revising section 2.5.2; and 

■ f. Adding section 2.5.2.4. 

The revisions and additions read as 

follows: 

Appendix E to Part 75—Optional NOX

Emissions Estimation Protocol for GasFired Peaking Units and Oil-Fired 

Peaking Units 

* * * * * 

2.1 Initial Performance Testing 

* * * The requirements in section 6.1.2 of 

appendix A to this part shall be met by any 

Air Emissions Testing Body (AETB) 

performing O2 and NOX concentration 

measurements under this appendix, either for 

units using the excepted methodology in this 

appendix or for units using the low mass 

emissions excepted methodology in § 75.19. 

* * * * * 

2.1.2.1 * * * Use a minimum of 12 

sample points, located according to Method 

1 in appendix A–1 to part 60 of this chapter. 

* * * * * 

2.1.2.2 For stationary gas turbines, 

sample at a minimum of 12 points per run 

at each load level. Locate the sample points 

according to Method 1 in appendix A–1 to 

part 60 of this chapter. For each fuel or 

consistent combination of fuels (and, 

optionally, for each combination of fuels), 

measure the NOX and O2 concentrations at 

each sampling point using methods 7E and 

3A in appendices A–4 and A–2 to part 60 of 

this chapter. For diesel or dual fuel 

reciprocating engines, select the sampling 

site to be as close as practicable to the 

exhaust of the engine. 

2.1.2.3 Allow the unit to stabilize for a 

minimum of 15 minutes (or longer if needed 

for the NOX and O2 readings to stabilize) 

prior to commencing NOX, O2, and heat input 

measurements. Determine the measurement 

system response time according to sections 

8.2.5 and 8.2.6 of method 7E in appendix A–

4 to part 60 of this chapter. When inserting 

the probe into the flue gas for the first 

sampling point in each traverse, sample for 

at least one minute plus twice the 

measurement system response time (or 

longer, if necessary to obtain a stable 

reading). For all other sampling points in 

each traverse, sample for at least one minute 

plus the measurement system response time 

(or longer, if necessary to obtain a stable 

reading). Perform three test runs at each load 

condition and obtain an arithmetic average of 

the runs for each load condition. During each 

test run on a boiler, record the boiler excess 

oxygen level at 5 minute intervals. 

* * * * * 

2.5.2 Substitute missing NOX emission 

rate data using the highest NOX emission rate 

tabulated during the most recent set of 

baseline correlation tests for the same fuel or, 

if applicable, combination of fuels, except as 

provided in sections 2.5.2.1, 2.5.2.2, 2.5.2.3, 

and 2.5.2.4 of this appendix. 

* * * * * 

2.5.2.4 Whenever 20 full calendar 

quarters have elapsed following the quarter 

of the last baseline correlation test for a 

particular type of fuel (or fuel mixture), 

without a subsequent baseline correlation 

test being done for that type of fuel (or fuel 

mixture), substitute the fuel-specific NOX

MER (as defined in § 72.2 of this chapter) for 

each hour in which that fuel (or mixture) is 

combusted until a new baseline correlation 

test for that fuel (or mixture) has been 

successfully completed. For fuel mixtures, 

report the highest of the individual MER 

values for the components of the mixture. 

* * * * * 

■ 44. Appendix F to Part 75 is amended 

by: 

■ a. Removing the second and third 

sentences from the introductory text of 

section 2; 

■ b. Removing the phrase ‘‘method 19 in 

appendix A of part 60 of this chapter’’

and adding in its place the phrase 

‘‘Method 19 in appendix A–7 to part 60 

of this chapter’’, in the last sentence of 

section 3.1 and in the last sentence of 

section 3.2; 

■ c. Adding the phrase ‘‘, or (if 

applicable) in the equations in Method 

19 in appendix A–7 to part 60 of this 

chapter’’ after the words ‘‘of this 

appendix’’, in section 3.3; 

■ d. Removing the second and third 

sentences from section 3.3.4; 

■ e. Adding sections 3.3.4.1 and 3.3.4.2; 

■ f. Revising Table 1; 

■ g. Revising the text preceding 

Equation F–7a, in section 3.3.6; 

■ h. Revising section 3.3.6.1; 

■ i. Revising section 3.3.6.2; 

■ j. Revising sections 3.3.6.3 and 3.3.6.4; 

■ k. Adding section 3.3.6.5; 

■ l. Adding the words ‘‘either measured 

directly with a CO2 monitor or 

calculated from wet-basis O2 data using 

Equation F–14b,’’ after the words ‘‘wet 

basis,’’ in the first sentence of the Ch

variable definition, and by removing the 

second and third sentences from the Ch

variable definition, in section 4.1; 

■ m. Revising section 4.4.1; 

■ n. Removing the second and third 

sentences from the %CO2w variable 

definition in 5.2.1; 

■ o. Removing the second and third 

sentences from the %CO2d variable 

definition in 5.2.2; 

■ p. Removing the second and third 

sentences from the %O2w variable 

definition, and by adding a new 

sentence at the end of the paragraph, in 

section 5.2.3; 

■ q. Removing the second and third 

sentences from the %O2d variable 

definition, in section 5.2.4; 

■ r. Revising the definition of ‘‘GCVo’’ in 

paragraph (a) of section 5.5.1; 

■ s. Revising the definition of ‘‘GCVg’’ in 

section 5.5.2; 

■ t. Revising section 5.5.3.1; 

■ u. Revising section 5.5.3.2; 

■ v. Removing the phrase ‘‘as measured 

by ASTM D3176–89, D1989–92, D3286–

91a, or D2015–91, Btu/lb’’ and adding in 

its place the phrase ‘‘as measured by 

ASTM D3176–89 (Reapproved 2002), or 

ASTM D5865–01a, Btu/lb. (incorporated 

by reference under § 75.6 of this part).’’

in the definition of the GCVc variable in 

Equation F–21; 

■ w. Removing the word ‘‘lb/hr’’ and 

adding in its place the phrase ‘‘lb/hr, or 

mmBtu/hr’’ in the definition of the SF 

variable in Equation F–21b; 

■ x. Revising the heading and text of 

section 7; 

■ y. Adding the words ‘‘of this 

appendix’’ after the words ‘‘section 8.1, 

8.2, or 8.3’’ and after the words ‘‘section 

8.4’’ in the introductory text for section 

8; 

■ z. Revising sections 8.1 and 8.1.1; 

■ aa. Revising section 8.2; 

■ bb. Adding sections 8.2.1 and 8.2.2; 

■ cc. Revising section 8.3; 

■ dd. Revising section 8.4; and 

■ ee. Adding section 10. 

The revisions and additions read as 

follows: 

Appendix F to Part 75—Conversion 

Procedures. 

* * * * * 

3.3.4 * * * 

3.3.4.1 For boilers, a minimum 

concentration of 5.0 percent CO2 or a 

maximum concentration of 14.0 percent O2

may be substituted for the measured diluent 

gas concentration value for any operating 

hour in which the hourly average CO2

concentration is < 5.0 percent CO2 or the 

hourly average O2 concentration is > 14.0 

percent O2. For stationary gas turbines, a 

minimum concentration of 1.0 percent CO2

or a maximum concentration of 19.0 percent 

O2 may be substituted for measured diluent 

gas concentration values for any operating 

hour in which the hourly average CO2

concentration is < 1.0 percent CO2 or the 

hourly average O2 concentration is > 19.0 

percent O2. 

3.3.4.2 If NOX emission rate is calculated 

using either Equation 19–3 or 19–5 in 

Method 19 in appendix A–7 to part 60 of this 

chapter, a variant of the equation shall be 

used whenever the diluent cap is applied. 

The modified equations shall be designated 

as Equations 19–3D and 19–5D, respectively. 


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Equation 19–3D is structurally the same as 

Equation 19–3, except that the term ‘‘%O2w’’

in the denominator is replaced with the term 

‘‘%O2dc × [(100¥% H2O)/100]’’, where %O2dc

is the diluent cap value. The numerator of 

Equation 19–5D is the same as Equation 19–

5; however, the denominator of Equation 19–

5D is simply ‘‘20.9¥%O2dc’’, where %O2dc is 

the diluent cap value. 

* * * * * 

TABLE 1.—F- AND Fc-FACTORS 1

Fuel F-factor 

(dscf/mmBtu) 

FC-factor 

(scf CO2/mmBtu) 

Coal (as defined by ASTM D388–99 2): 

Anthracite .............................................................................................................................................. 10,100 1,970 

Bituminous ............................................................................................................................................ 9,780 1,800 

Subbituminous ...................................................................................................................................... 9,820 1,840 

Lignite ................................................................................................................................................... 9,860 1,910 

Petroleum Coke ........................................................................................................................................... 9,830 1,850 

Tire Derived Fuel ......................................................................................................................................... 10,260 1,800 

Oil ................................................................................................................................................................. 9,190 1,420 

Gas: 

Natural gas ........................................................................................................................................... 8,710 1,040 

Propane ................................................................................................................................................ 8,710 1,190 

Butane .................................................................................................................................................. 8,710 1,250 

Wood: 

Bark ...................................................................................................................................................... 9,600 1,920 

Wood residue ....................................................................................................................................... 9,240 1,830 

1 Determined at standard conditions: 20 °C (68 °F) and 29.92 inches of mercury. 2 Incorporated by reference under § 75.6 of this part. 

* * * * * 

3.3.6 Equations F–7a and F–7b may be 

used in lieu of the F or Fc factors specified 

in Section 3.3.5 of this appendix to calculate 

a site-specific dry-basis F factor (dscf/ 

mmBtu) or a site-specific Fc factor (scf CO2/ 

mmBtu), on either a dry or wet basis. At a 

minimum, the site-specific F or Fc factor 

must be based on 9 samples of the fuel. Fuel 

samples taken during each run of a RATA are 

acceptable for this purpose. The site-specific 

F or Fc factor must be re-determined at least 

annually, and the value from the most recent 

determination must be used in the emission 

calculations. Alternatively, the previous F or 

Fc value may continue to be used if it is 

higher than the value obtained in the most 

recent determination. The owner or operator 

shall keep records of all site-specific F or Fc

determinations, active for at least 3 years. 

(Calculate all F- and Fc factors at standard 

conditions of 20 °C (68 °F) and 29.92 inches 

of mercury). 

* * * * * 

3.3.6.1 H, C, S, N, and O are content by 

weight of hydrogen, carbon, sulfur, nitrogen, 

and oxygen (expressed as percent), 

respectively, as determined on the same basis 

as the gross calorific value (GCV) by ultimate 

analysis of the fuel combusted using ASTM 

D3176–89 (Reapproved 2002), Standard 

Practice for Ultimate Analysis of Coal and 

Coke, (solid fuels), ASTM D5291–02, 

Standard Test Methods for Instrumental 

Determination of Carbon, Hydrogen, and 

Nitrogen in Petroleum Products and 

Lubricants, (liquid fuels) or computed from 

results using ASTM D1945–96 (Reapproved 

2001), Standard Test Method for Analysis of 

Natural Gas by Gas Chromatography, or 

ASTM D1946–90 (Reapproved 2006), 

Standard Practice for Analysis of Reformed 

Gas by Gas Chromatography, (gaseous fuels) 

as applicable. (All of these methods are 

incorporated by reference under § 75.6 of this 

part.) 

3.3.6.2 GCV is the gross calorific value 

(Btu/lb) of the fuel combusted determined by 

ASTM D5865–01a, Standard Test Method for 

Gross Calorific Value of Coal and Coke, and 

ASTM D240–00, Standard Test Method for 

Heat of Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter, or ASTM 

D4809–00, Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon Fuels by 

Bomb Calorimeter (Precision Method) for oil; 

and ASTM D3588–98, Standard Practice for 

Calculating Heat Value, Compressibility 

Factor, and Relative Density of Gaseous 

Fuels, ASTM D4891–89 (Reapproved 2006), 

Standard Test Method for Heating Value of 

Gases in Natural Gas Range by Stoichiometric 

Combustion, GPA Standard 2172–96 

Calculation of Gross Heating Value, Relative 

Density and Compressibility Factor for 

Natural Gas Mixtures from Compositional 

Analysis, GPA Standard 2261–00 Analysis 

for Natural Gas and Similar Gaseous 

Mixtures by Gas Chromatography, or ASTM 

D1826–94 (Reapproved 1998), Standard Test 

Method for Calorific (Heating) Value of Gases 

in Natural Gas Range by Continuous 

Recording Calorimeter, for gaseous fuels, as 

applicable. (All of these methods are 

incorporated by reference under § 75.6 of this 

part). 

3.3.6.3 For affected units that combust a 

combination of a fuel (or fuels) listed in 

Table 1 in section 3.3.5 of this appendix with 

any fuel(s) not listed in Table 1, the F or Fc

value is subject to the Administrator’s 

approval under § 75.66. 

3.3.6.4 For affected units that combust 

combinations of fuels listed in Table 1 in 

section 3.3.5 of this appendix, prorate the F 

or Fc factors determined by section 3.3.5 or 

3.3.6 of this appendix in accordance with the 

applicable formula as follows: 

Where, 

Xi = Fraction of total heat input derived from 

each type of fuel (e.g., natural gas, 

bituminous coal, wood). Each Xi value 

shall be determined from the best 

available information on the quantity of 

fuel combusted and the GCV value, over 

a specified time period. The owner or 

operator shall explain the method used 

to calculate Xi in the hardcopy portion 

of the monitoring plan for the unit. The 

Xi values may be determined and 

updated either hourly, daily, weekly, or 

monthly. In all cases, the prorated Ffactor used in the emission calculations 

shall be determined using the Xi values 

from the most recent update. 

Fi or (Fc)i = Applicable F or Fc factor for each 

fuel type determined in accordance with 

Section 3.3.5 or 3.3.6 of this appendix. 

n = Number of fuels being combusted in 

combination. 

3.3.6.5 As an alternative to prorating the 

F or Fc factor as described in section 3.3.6.4 

of this appendix, a ‘‘worst-case’’ F or Fc factor 

may be reported for any unit operating hour. 


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The worst-case F or Fc factor shall be the 

highest F or Fc value for any of the fuels 

combusted in the unit. 

* * * * * 

4. Procedure for CO2 Mass Emissions 

* * * * * 

4.4.1 If the owner or operator elects to use 

data from an O2 monitor to calculate CO2

concentration, the appropriate F and FC

factors from section 3.3.5 of this appendix 

shall be used in one of the following 

equations (as applicable) to determine hourly 

average CO2 concentration of flue gases (in 

percent by volume) from the measured 

hourly average O2 concentration: 

2

2 100 20 9

20 9 d

c d CO F

F

O = Eq . −

. ( . F-14a) 

Where: 

CO2d = Hourly average CO2 concentration 

during unit operation, percent by 

volume, dry basis. 

F, FC = F-factor or carbon-based Fc-factor 

from section 3.3.5 of this appendix. 

20.9 = Percentage of O2 in ambient air. 

O2d = Hourly average O2 concentration 

during unit operation, percent by 

volume, dry basis. 

CO F

F

H O w O c

2 w

2

2

100

20 9

20 9 100

100 =  −



 



 − 



 



 . . % (Eq. F-14b)

Where: 

CO2w = Hourly average CO2 concentration 

during unit operation, percent by 

volume, wet basis. 

O2w = Hourly average O2 concentration 

during unit operation, percent by 

volume, wet basis. 

F, Fc = F-factor or carbon-based FC-factor 

from section 3.3.5 of this appendix. 

20.9 = Percentage of O2 in ambient air. 

%H2O = Moisture content of gas in the stack, 

percent. 

For any hour where Equation F–14a or F–

14b results in a negative hourly average CO2

value, 0.0% CO2w shall be recorded as the 

average CO2 value for that hour. 

* * * * * 

5. Procedures for Heat Input 

* * * * * 

5.2.3 * * * For any operating hour where 

Equation F–17 results in an hourly heat input 

rate that is ≤ 0.0 mmBtu/hr, 1.0 mmBtu/hr 

shall be recorded and reported as the heat 

input rate for that hour. 

* * * * * 

5.5.1 (a) * * * 

GCVo = Gross calorific value of oil, as 

measured by ASTM D240–00, ASTM D5865–

01a, or ASTM D4809–00 for each oil sample 

under section 2.2 of appendix D to this part, 

Btu/unit mass (all incorporated by reference 

under (§ 75.6 of this part). 

* * * * * 

5.5.2 * * * 

GCVg = Gross calorific value of gaseous 

fuel, as determined by sampling (for each 

delivery for gaseous fuel in lots, for each 

daily gas sample for gaseous fuel delivered 

by pipeline, for each hourly average for gas 

measured hourly with a gas chromatograph, 

or for each monthly sample of pipeline 

natural gas, or as verified by the contractual 

supplier at least once every month pipeline 

natural gas is combusted, as specified in 

section 2.3 of appendix D to this part) using 

ASTM D1826–94 (Reapproved 1998), ASTM 

D3588–98, ASTM D4891–89 (Reapproved 

2006), GPA Standard 2172–96 Calculation of 

Gross Heating Value, Relative Density and 

Compressibility Factor for Natural Gas 

Mixtures from Compositional Analysis, or 

GPA Standard 2261–00 Analysis for Natural 

Gas and Similar Gaseous Mixtures by Gas 

Chromatography, Btu/100 scf (all 

incorporated by reference under § 75.6 of this 

part). 

* * * * * 

5.5.3.1 Perform coal sampling daily 

according to section 5.3.2.2 in Method 19 in 

appendix A to part 60 of this chapter and use 

ASTM D2234–00, Standard Practice for 

Collection of a Gross Sample of Coal, 

(incorporated by reference under § 75.6 of 

this part) Type I, Conditions A, B, or C and 

systematic spacing for sampling. (When 

performing coal sampling solely for the 

purposes of the missing data procedures in 

§ 75.36, use of ASTM D2234–00 is optional, 

and coal samples may be taken weekly.) 

5.5.3.2 All ASTM methods are 

incorporated by reference under § 75.6 of this 

part. Use ASTM D2013–01, Standard Practice 

for Preparing Coal Samples for Analysis, for 

preparation of a daily coal sample and 

analyze each daily coal sample for gross 

calorific value using ASTM D5865–01a, 

Standard Test Method for Gross Calorific 

Value of Coal and Coke. On-line coal analysis 

may also be used if the on-line analytical 

instrument has been demonstrated to be 

equivalent to the applicable ASTM methods 

under §§ 75.23 and 75.66. 

* * * * * 

7. Procedures for SO2 Mass Emissions, Using 

Default SO2 Emission Rates and Heat Input 

Measured by CEMS 

The owner or operator shall use Equation 

F–23 to calculate hourly SO2 mass emissions 

in accordance with § 75.11(e)(1) during the 

combustion of gaseous fuel, for a unit that 

uses a flow monitor and a diluent gas 

monitor to measure heat input, and that 

qualifies to use a default SO2 emission rate 

under section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of 

appendix D to this part. Equation F–23 may 

also be applied to the combustion of solid or 

liquid fuel that meets the definition of very 

low sulfur fuel in § 72.2 of this chapter, 

combinations of such fuels, or mixtures of 

such fuels with gaseous fuel, if the owner or 

operator has received approval from the 

Administrator under § 75.66 to use a sitespecific default SO2 emission rate for the fuel 

or mixture of fuels. 

E ER HI Eq F h = ( )( ) (. ) -23

Where: 

Eh = Hourly SO2 mass emission rate, lb/hr. 

ER = Applicable SO2 default emission rate for 

gaseous fuel combustion, from section 

2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix 

D to this part, or other default SO2

emission rate for the combustion of very 

low sulfur liquid or solid fuel, 

combinations of such fuels, or mixtures 

of such fuels with gaseous fuel, as 

approved by the Administrator under 

§ 75.66, lb/mmBtu. 

HI = Hourly heat input rate, determined 

using the procedures in section 5.2 of 

this appendix, mmBtu/hr. 

8. Procedures for NOX Mass Emissions 

* * * * * 

8.1 The own or operator may use the 

hourly NOX emission rate and the hourly 

heat input rate to calculate the NOX mass 

emissions in pounds or the NOX mass 

emission rate in pounds per hour, (as 

required by the applicable reporting format), 

for each unit or stack operating hour, as 

follows: 

8.1.1 If both NOX emission rate and heat 

input rate are monitored at the same unit or 

stack level (e.g., the NOX emission rate value 

and the heat input rate value both represent 

all of the units exhausting to the common 

stack), then (as required by the applicable 

reporting format) either: 

(a) Use Equation F–24 to calculate the 

hourly NOX mass emissions (lb). 

M ER HI t NOx NOx h h h h () () = (Eq. F-24)

Where: 

M(NOX)h = NOX mass emissions in lbs for the 

hour. 

ER(NOX)h = Hourly average NOX emission rate 

for hour h, lb/mmBtu, from section 3 of 

this appendix, from Method 19 in 


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Federal Register / Vol. 73, No. 16 / Thursday, January 24, 2008 / Rules and Regulations 4375 

appendix A–7 to part 60 of this chapter, 

or from section 3.3 of appendix E to this 

part. (Include bias-adjusted NOX

emission rate values, where the bias-test 

procedures in appendix A to this part 

shows a bias-adjustment factor is 

necessary.) 

HIh = Hourly average heat input rate for hour 

h, mmBtu/hr. (Include bias-adjusted flow 

rate values, where the bias-test 

procedures in appendix A to this part 

shows a bias-adjustment factor is 

necessary.) 

th = Monitoring location operating time for 

hour h, in hours or fraction of an hour 

(in equal increments that can range from 

one hundredth to one quarter of an hour, 

at the option of the owner or operator). 

If the combined NOX emission rate and 

heat input are monitored for all of the 

units in a common stack, the monitoring 

location operating time is equal to the 

total time when any of those units was 

exhausting through the common stack; or 

(b) Use Equation F–24a to calculate the 

hourly NOX mass emission rate (lb/hr). 

E ER HI Eq NOx NOx h h h () () = ( . F-24a)

Where: 

E(NOX)h = NOX mass emissions rate in lbs/hr 

for the hour. 

ER(NOX)h = Hourly average NOX emission rate 

for hour h, lb/mmBtu, from section 3 of 

this appendix, from Method 19 in 

appendix A–7 to part 60 of this chapter, 

or from section 3.3 of appendix E to this 

part. (Include bias-adjusted NOX

emission rate values, where the bias-test 

procedures in appendix A to this part 

shows a bias-adjustment factor is 

necessary.) 

HIh = Hourly average heat input rate for hour 

h, mmBtu/hr. (Include bias-adjusted flow 

rate values, where the bias-test 

procedures in appendix A to this part 

shows a bias-adjustment factor is 

necessary.) 

* * * * * 

8.2 Alternatively, the owner or operator 

may use the hourly NOX concentration (as 

measured by a NOX concentration monitoring 

system) and the hourly stack gas volumetric 

flow rate to calculate the NOX mass emission 

rate (lb/hr) for each unit or stack operating 

hour, in accordance with section 8.2.1 or 

8.2.2 of this appendix (as applicable). If the 

hourly NOX mass emissions are to be 

reported in lb, Equation F–26c in section 8.3 

of this appendix shall be used to convert the 

hourly NOX mass emission rates to hourly 

NOX mass emissions (lb). 

8.2.1 When the NOX concentration 

monitoring system measures on a wet basis, 

first calculate the hourly NOX mass emission 

rate (in lb/hr) during unit (or stack) 

operation, using Equation F–26a. (Include 

bias-adjusted flow rate or NOX concentration 

values, where the bias-test procedures in 

appendix A to this part shows a biasadjustment factor is necessary.) 

E KC Q NOx hw h h ( ) = (Eq. F-26a)

Where: 

E(NOX)h = NOX mass emissions rate in lb/hr. 

K = 1.194 x 10¥7 for NOX, (lb/scf)/ppm. 

Chw = Hourly average NOX concentration 

during unit operation, wet basis, ppm. 

Qh = Hourly average volumetric flow rate 

during unit operation, wet basis, scfh. 

8.2.2 When NOX mass emissions are 

determined using a dry basis NOX

concentration monitoring system and a wet 

basis flow monitoring system, first calculate 

hourly NOX mass emission rate (in lb/hr) 

during unit (or stack) operation, using 

Equation F–26b. (Include bias-adjusted flow 

rate or NOX concentration values, where the 

bias-test procedures in appendix A to this 

part shows a bias-adjustment factor is 

necessary.) 

E KQ

H O

Eq NO h ( ) X h= ( ) −

( ) C F-26b hd ( ) 100

100

% 2 .

Where: 

E(NOX)h = NOX mass emissions rate, lb/hr. 

K = 1.194 x 10¥7 for NOX, (lb/scf)/ppm. 

Chd = Hourly average NOX concentration 

during unit operation, dry basis, ppm. 

Qh = Hourly average volumetric flow rate 

during unit operation, wet basis, scfh. 

%H2O = Hourly average stack moisture 

content during unit operation, percent by 

volume. 

8.3 When hourly NOX mass emissions are 

reported in pounds and are determined using 

a NOX concentration monitoring system and 

a flow monitoring system, calculate NOX

mass emissions (lb) for each unit or stack 

operating hour by multiplying the hourly 

NOX mass emission rate (lb/hr) by the unit 

operating time for the hour, as follows: 

M E t Eq F c NO h h X h ( ) = ( ) . -26

Where: 

M(NOX)h = NOX mass emissions for the hour, 

lb. 

Eh = Hourly NOX mass emission rate during 

unit (or stack) operation from Equation 

F–26a in section 8.2.1 of this appendix 

or Equation F–26b in section 8.2.2 of this 

appendix (as applicable), lb/hr. 

th = Unit operating time or stack operating 

time (as defined in § 72.2 of this chapter) 

for hour ‘‘h’’, in hours or fraction of an 

hour (in equal increments that can range 

from one hundredth to one quarter of an 

hour, at the option of the owner or 

operator). 

8.4 Use the following procedures to 

calculate quarterly, cumulative ozone season, 

and cumulative yearly NOX mass emissions, 

in tons: 

(a) When hourly NOX mass emissions are 

reported in lb., use Eq. F–27. 

M

M NO

Eq F NO

X h h

p

( ) X

= =

( )

( )

∑

time period

 -27 1

2000 .

Where: 

M(NOX)time period = NOX mass emissions in tons 

for the given time period (quarter, 

cumulative ozone season, cumulative 

year-to-date). 

M(NOX)h = NOX mass emissions in lb for the 

hour. 

p = The number of hours in the given time 

period (quarter, cumulative ozone 

season, cumulative year-to-date). 

(b) When hourly NOX mass emission rate 

is reported in lb/hr, use Eq. F–27a. 

M

E t

Eq NO

NO h

h

p

X

X h

( )

( ) = = ( )

∑

time period

 F-27a 1

2000 .


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4376 Federal Register / Vol. 73, No. 16 / Thursday, January 24, 2008 / Rules and Regulations 

Where: 

M(NOX)time period = NOX mass emissions in tons 

for the given time period (quarter, 

cumulative ozone season, cumulative 

year-to-date). 

E(NOX)h = NOX mass emission rate in lb/hr for 

the hour. 

p = The number of hours in the given time 

period (quarter, cumulative ozone 

season, cumulative year-to-date). 

th = Monitoring location operating time for 

hour h, in hours or fraction of an hour 

(in equal increments that can range from 

one hundredth to one quarter of an hour, 

at the option of the owner or operator). 

* * * * * 

10. Moisture Determination From Wet and 

Dry O2 Readings 

If a correction for the stack gas moisture 

content is required in any of the emissions 

or heat input calculations described in this 

appendix, and if the hourly moisture content 

is determined from wet- and dry-basis O2

readings, use Equation F–31 to calculate the 

percent moisture, unless a ‘‘K’’ factor or other 

mathematical algorithm is developed as 

described in section 6.5.7(a) of appendix A 

to this part: 

% . H O

O O

O Eq d w

d

2

2 2

2

= 100 ( ) − × ( ) F-31

Where: 

% H2O = Hourly average stack gas moisture 

content, percent H2O 

O2d = Dry-basis hourly average oxygen 

concentration, percent O2

O2w = Wet-basis hourly average oxygen 

concentration, percent O2

■ 45. Appendix G to Part 75 is amended 

by: 

■ a. Revising section 2.1.2; 

■ b. Removing ‘‘D3174–89 ‘Standard 

Test Method for Ash in the Analysis 

Sample of Coal and Coke From Coal’ ’’

and by adding in its place, ‘‘D3174–00, 

Standard Test Method for Ash in the 

Analysis Sample of Coal and Coke from 

Coal’’ in section 2.2.1; and 

■ c. Removing ‘‘D3178–89 (1997), 

‘Standard Test Methods for Carbon and 

Hydrogen in the Analysis Sample of 

Coal and Coke’ ’’ and adding in its place 

‘‘D5373–02 (Reapproved 2007), 

Standard Test Methods for Instrumental 

Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal 

and Coke’’ in section 2.2.2. 

The revisions read as follows: 

Appendix G to Part 75—Determination 

of CO2 Emissions. 

* * * * * 

2.1.2 Determine the carbon content of 

each fuel sample using one of the following 

methods: ASTM D3178–89 (Reapproved 

2002) or ASTM D5373–02 (Reapproved 2007) 

for coal; ASTM D5291–02, Standard Test 

Methods for Instrumental Determination of 

Carbon, Hydrogen, and Nitrogen in 

Petroleum Products and Lubricants, ultimate 

analysis of oil, or computations based upon 

ASTM D3238–95 (Reapproved 2000) and 

either ASTM D2502–92 (Reapproved 1996) or 

ASTM D2503–92 (Reapproved 1997) for oil; 

and computations based on ASTM D1945–96 

(Reapproved 2001) or ASTM D1946–90 

(Reapproved 2006) for gas (all incorporated 

by reference under § 75.6 of this part). 

* * * * * 

■ 46. Appendix K to Part 75 is amended 

by: 

■ a. Removing the words ‘‘(see 

§§ 75.11(b) and 75.12(b))’’ and adding in 

its place the words ‘‘(see § 75.11(b))’’ in 

section 5; 

■ b. Adding a sentence to the end of 

section 7.2.3; 

■ c. Removing the words ‘‘or § 75.12(b)’’

and ‘‘or § 75.12,’’ from section 7.2.4; 

■ d. Revising Table K–1 of section 8; 

and 

■ e. Adding the words ‘‘or in Table K–

1’’ following the words ‘‘§ 75.15(h)’’ in 

the second sentence of section 11.8. 

The revisions and additions read as 

follows: 

Appendix K to Part 75—Quality 

Assurance and Operating Procedures 

for Sorbent Trap Monitoring Systems 

* * * * * 

7.2.3 * * * The sample flow rate through 

a sorbent trap monitoring system during any 

hour (or portion of an hour) in which the unit 

is not operating shall be zero. 

* * * * * 

TABLE K–1.—QUALITY ASSURANCE/QUALITY CONTROL CRITERIA FOR SORBENT TRAP MONITORING SYSTEMS

QA/QC test or specification Acceptance criteria Frequency Consequences if not met 

Pre-test leak check ......................... ≤4% of target sampling rate ......... Prior to sampling .......................... Sampling shall not commence 

until the leak check is passed. 

Post-test leak check ........................ ≤4% of average sampling rate ..... After sampling .............................. ** See Note, below. 

Ratio of stack gas flow rate to sample flow rate.No more than 5% of the hourly 

ratios or 5 hourly ratios (whichever is less restrictive) may deviate from the reference ratio 

by more than ± 25%.

Every hour throughout data collection period.** See Note, below. 

Sorbent trap section 2 breakthrough.≤5% of Section 1 Hg mass .......... Every sample ............................... ** See Note, below. 

Paired sorbent trap agreement ....... ≤10% Relative Deviation (RD) if 

the average concentration is > 

1.0 μg/m3.

≤ 20% RD if the average concentration is ≤ 1.0 μg/m3.

Results are also acceptable if absolute difference between concentrations from paired traps is 

≤ 0.03 μg/m3.

Every sample ............................... Either invalidate the data from the 

paired traps or report the results from the trap with the 

higher Hg concentration. 

Spike Recovery Study ..................... Average recovery between 85% 

and 115% for each of the 3 

spike concentration levels.

Prior to analyzing field samples 

and prior to use of new sorbent 

media.

Field samples shall not be analyzed until the percent recovery 

criteria has been met 

Multipoint analyzer calibration ......... Each analyzer reading within ± 

10% of true value and r2 ≥ 0.99.

On the day of analysis, before 

analyzing any samples.

Recalibrate until successful. 


sroberts on PROD1PC70 with RULESER24JA08.031</GPH>
Federal Register / Vol. 73, No. 16 / Thursday, January 24, 2008 / Rules and Regulations 4377 

TABLE K–1.—QUALITY ASSURANCE/QUALITY CONTROL CRITERIA FOR SORBENT TRAP MONITORING SYSTEMS—Continued 

QA/QC test or specification Acceptance criteria Frequency Consequences if not met 

Analysis of independent calibration 

standard.

Within ± 10% of true value .......... Following daily calibration, prior to 

analyzing field samples.

Recalibrate and repeat independent standard analysis until 

successful. 

Spike recovery from section 3 of 

sorbent trap.

75–125% of spike amount ........... Every sample ............................... ** See Note, below. 

RATA ............................................... RA ≤ 20.0% or Mean difference ≤ 

1.0 μg/dscm for low emitters.

For initial certification and annually thereafter.Data from the system are invalidated until a RATA is passed. 

Gas flow meter calibration .............. Calibration factor (Y) within ± 5% 

of average value from the most 

recent 3-point calibration.

At three settings prior to initial 

use and at least quarterly at 

one setting thereafter. For 

mass flow meters, initial calibration with stack gas is required.

Recalibrate the meter at three orifice settings to determine a 

new value of Y. 

Temperature sensor calibration ...... Absolute temperature measured 

by sensor within ± 1.5% of a 

reference sensor.

Prior to initial use and at least 

quarterly thereafter.

Recalibrate. Sensor may not be 

used until specification is met. 

Barometer calibration ...................... Absolute pressure measured by 

instrument within ± 10 mm Hg 

of reading with a mercury barometer.

Prior to initial use and at least 

quarterly thereafter.

Recalibrate. Instrument may not 

be used until specification is 

met. 

** Note: If both traps fail to meet the acceptance criteria, the data from the pair of traps are invalidated. However, if only one of the paired traps 

fails to meet this particular acceptance criterion and the other sample meets all of the applicable QA criteria, the results of the valid trap may be 

used for reporting under this part, provided that the measured Hg concentration is multiplied by a factor of 1.111. When the data from both traps 

are invalidated and quality-assured data from a certified backup monitoring system, reference method, or approved alternative monitoring system 

are unavailable, missing data substitution must be used. 

* * * * * 

[FR Doc. E7–25071 Filed 1–23–08; 8:45 am] 

BILLING CODE 6560–50–P 


sroberts on PROD1PC70 with RULES