[Federal Register Volume 66, Number 114 (Wednesday, June 13, 2001)]
[Proposed Rules]
[Pages 31978-32049]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 01-13142]



[[Page 31977]]

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Part II





Environmental Protection Agency





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40 CFR Parts 72, 75, 78, and 97



Revisions to the Federal NO<INF>X</INF> Budget Trading Program, the 
Emissions Monitoring Provisions, the Permits Regulation Provisions, and 
the Appeal Procedures; Proposed Rule

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / 
Proposed Rules

[[Page 31978]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 72, 75, 78, and 97

[FRL-6984-8]
RIN 2060-AJ43


Revisions to the Federal NO<INF>X</INF> Budget Trading Program, 
the Emissions Monitoring Provisions, the Permits Regulation Provisions, 
and the Appeal Procedures

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing rule revisions that would modify the existing 
requirements for sources affected by the Federal NO<INF>X</INF> Budget 
Trading Program, the Acid Rain Program, and the October 27, 1998 
NO<INF>X</INF> SIP Call. The proposed revisions would streamline and 
add flexibility to the monitoring and reporting requirements in 
response to the significant changes that have occurred in power 
generation in recent years due to deregulation and recent environmental 
actions initiated by EPA to reduce nitrogen oxides emissions. This 
proposed action would also make certain technical corrections, remove 
outdated provisions, and correct printing, typographical, and 
grammatical errors to correct or clarify cross references, and, in a 
few instances, to ensure that the specific rule language is consistent 
with the Agency's intent.

DATES: Comments. All public comments must be received on or before July 
30, 2001.
    Public Hearing. Anyone requesting a public hearing must contact EPA 
no later than June 25, 2001. If a hearing is held, it will take place 
June 27, 2001, beginning at 10 a.m.

ADDRESSES: Comments. Comments must be mailed (in duplicate if possible) 
to: EPA Air Docket (6102), Attention: Docket No. A-2000-33, Room M-
1500, Waterside Mall, 401 M Street, SW., Washington, DC 20460.
    Public Hearing. If a public hearing is requested, it will be held 
at the Environmental Protection Agency, 401 M Street, SW., Washington, 
DC 20460, in the Education Center Auditorium. Refer to the Clean Air 
Markets homepage at www.epa.gov/airmarkets for more information or to 
determine if a public hearing has been requested and will be held.
    Docket. Docket No. A-2000-33, containing supporting information 
used to develop the proposal, is available for public inspection and 
copying from 8:00 a.m. to 5:30 p.m., Monday through Friday, excluding 
legal holidays, at EPA's Air Docket Section at the above address.

FOR FURTHER INFORMATION CONTACT: Gabrielle Stevens, Clean Air Markets 
Division (6204N), U.S. Environmental Protection Agency, Ariel Rios 
Building, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, 
telephone number (202) 564-2681 or the Acid Rain Hotline at (202) 564-
9620. Electronic copies of this document and technical support 
documents can be accessed through the EPA Web site at: http://www.epa.gov/airmarkets.

SUPPLEMENTARY INFORMATION: In accordance with titles I and IV of the 
Clean Air Act (CAA or the Act), EPA is proposing rule revisions to 
support previous actions the Agency has taken to mitigate interstate 
transport of nitrogen oxides as well as to reduce the acidic deposition 
precursor emissions of sulfur dioxide and nitrogen oxides 
(NO<INF>X</INF>). Title I of the CAA, as amended by the Clean Air Act 
Amendments of 1990, authorizes EPA, under section 126 of the Act, to 
require reductions of NO<INF>X</INF> emissions from sources that emit 
in violation of the CAA prohibition against significantly contributing 
to ozone nonattainment or maintenance problems in a downwind State that 
petitions EPA for relief. On January 18, 2000, EPA published a section 
126 finding that a number of large electric generating units and large 
industrial boilers and turbines named in petitions filed by several 
northeastern States emit NO<INF>X</INF> in violation of the CAA. In 
that same notice, the EPA finalized the Federal NO<INF>X</INF> Budget 
Trading Program as the control remedy for sources affected by the rule. 
EPA originally promulgated 40 CFR parts 72, 75, and 78 on January 11, 
1993, to implement the Acid Rain Program as authorized by title IV of 
the Act. EPA has subsequently promulgated several final rules revising 
the January 11, 1993 rules. The most recent revisions were promulgated 
on May 26, 1999. Finally, note that although today's proposal will not 
revise the Finding of Significant Contribution and Rulemaking for 
Certain States in the Ozone Transport Assessment Group for Purposes of 
Reducing the Transport of Ozone ( NO<INF>X</INF> SIP call), promulgated 
on October 27, 1998, under section 110 of the Act, the proposed changes 
to the monitoring and reporting provisions of 40 CFR part 75 (and 
related changes to certain definitions in 40 CFR part 72) will affect 
sources that are subject to the NO<INF>X</INF> SIP call, since many of 
these sources will be required to implement part 75 emissions 
monitoring.
    The provisions of 40 CFR parts 72, 75, 78, and 97 will be revised 
to modify the existing requirements for sources affected by the Acid 
Rain Program, the Federal NO<INF>X</INF> Budget Trading Program, and 
the October 27, 1998, NO<INF>X</INF> SIP call. Today's proposal is 
limited to the specific provisions in parts 72, 75, 78, and 97 
identified and discussed here. EPA is not considering reopening or 
requesting public comment on any other provisions of parts 72, 75, 78, 
or 97 or of the section 126 or NO<INF>X</INF> SIP call rulemaking.
    A redline/strikeout version of 40 CFR parts 72 and 75 as amended by 
this proposed rule is available in the Docket and on the EPA Web site 
referenced above. The contents of the preamble are listed in the 
following outline:

I. Regulated Entities
II. Background and Summary of the Proposed Rule
III. Detailed Discussion of Proposed Revisions
    A. Rule Definitions
    1. How does EPA propose to revise the definitions of pipeline 
natural gas and natural gas in Sec. 72.2?
    2. How does EPA propose to change the definitions of unit and 
stack operating hours?
    3. What other definitions would be revised or added to the rule?
    B. Certification Timeline Issues
    1. What is the deadline for an application for initial 
certification?
    2. For an appendix E peaking unit, when is initial certification 
required while combusting the backup fuel?
    3. What happens if a unit loses peaking, gas-fired, or LME 
status?
    C. Missing Data
    1. How will the proposed rule affect the missing data procedures 
in Secs. 75.31 through 75.37 for units that produce electrical or 
thermal output?
    2. How will subpart H missing data provisions be affected for 
units that produce electrical or thermal output?
    3. What are the missing data requirements for units that do not 
produce electrical or thermal output?
    4. How will today's proposed rule revise the procedures in 
appendix C for establishing load ranges (or ``bins'') for missing 
data purposes?
    5. How will the maximum potential moisture provision be revised?
    6. How will the proposed rule affect the method of determination 
codes?
    D. Low Mass Emissions (LME) Units
    1. What are the certification requirements for low mass 
emissions (LME) units?
    2. How does the LME methodology apply to subpart H units?
    3. When must the annual demonstration for LME units be 
completed?
    4. How should EPA Reference Method 20 be altered when 
determining a fuel-and unit-specific NO<INF>X</INF> emission rate 
for an LME unit?
    5. What temperature and humidity corrections are required for 
turbines

[[Page 31979]]

when unit-and fuel-specific NO<INF>X</INF> emission rates are 
determined for LME units?
    6. How is identical unit status demonstrated for a group of LME 
units?
    7. How is the fuel-and unit-specific NO<INF>X</INF> emission 
rate determined for LME turbines equipped with water injection, 
steam injection, or water/fuel emulsion, and no other type(s) of 
add-on NO<INF>X</INF> controls?
    8. What effect would today's proposed rule have on LME units 
sharing a common fuel supply?
    9. When would single load testing be allowed to determine unit-
and fuel-specific NO<INF>X</INF> emission rates for LME units?
    10. How are unit-specific, fuel-specific NO<INF>X</INF> emission 
rates for LME units determined from the individual test run data at 
each load level?
    11. Which mathematical equations are affected by the proposed 
changes to Sec. 75.19?
    E. Conditionally Valid Data--Mandatory Use
    F. Quality Assurance/Quality Control (QA/QC)
    1. What changes are proposed for CEMS span and range 
evaluations?
    2. Will EPA allow use of two separate CEM systems with separate 
probes and sample interfaces to meet dual-range requirements?
    3. What changes would the proposed rule make with regard to 
determining NO<INF>X</INF> MPC, MEC, span, and range?
    4. What revisions would be made to the 7-day calibration error 
test for peaking units?
    5. What changes would be made to QA/QC for units with very low 
NO<INF>X</INF> concentrations?
    6. When would EPA require the application of a calibration 
correction factor to linearity or RATA test data?
    7. What changes would be made to the flow-to-load ratio test?
    8. When would three-load flow RATAs be allowed for routine 
quality assurance?
    9. What changes would be made to the data analysis time period 
for single-load flow RATA claims?
    10. For units that do not produce electrical output or steam 
load, at what operating levels should gas and flow monitor RATAs be 
performed?
    G. Streamlining Changes
    H. Monitoring Plan Information Submittal
    1. What changes are proposed in the timeline for monitoring plan 
updates?
    2. Is EPA changing the process for electronic submittal of 
monitoring plan updates and certification/recertification test 
results?
    I. Appendix D--Miscellaneous Issues
    J. Reporting and Recordkeeping
    1. Will certification and recertification test notice 
requirements change?
    2. Will EPA continue to accept hardcopy certification 
statements?
    3. Will EPA allow the electronic storage of quality assurance/
quality control plan information?
    K. NO<INF>X</INF> Monitoring in Multiple Stacks/Common Stacks
    L. Appendix E Issues
    1. How will the proposed rule affect Appendix E test 
notifications and submittal of hardcopy recertification test 
results?
    2. Will the frequency of retesting of Appendix E units be 
changed?
    3. How will the timeline for unscheduled Appendix E retests be 
revised?
    4. How will Appendix E missing data procedures be changed?
    5. How will the Appendix E testing requirements for emergency 
fuel be changed?
    M. Reference Methods
    1. Which Code of Federal Regulations versions of reference 
methods are to be used?
    2. Are there other changes to reference methods?
    N. Appendix G Revisions
    O. Technical Changes and Corrections
    P. What other changes is EPA proposing to the Federal 
NO<INF>X</INF> Budget Trading Program today?
IV. Administrative Requirements
    A. Public Hearing
    B. Public Docket
    C. Executive Order 12866
    D. Unfunded Mandates Reform Act
    E. Paperwork Reduction Act
    F. Regulatory Flexibility
    G. National Technology Transfer and Advancement Act
    H. Executive Order 13175
    I. Executive Order 12898
    J. Executive Order 13045
    K. Executive Order 13132

I. Regulated Entities

    Entities regulated by this action are fossil fuel-fired boilers, 
turbines, and combined cycle units that serve generators which produce 
electricity, generate steam, or cogenerate electricity and steam. While 
part 75 primarily regulates the electric utility industry, certain 
State and Federal NO<INF>X</INF> mass emission trading programs may 
rely on subpart H of part 75, and those programs may include boilers, 
turbines, and combined cycle units from other industries. Regulated 
categories and entities include:

------------------------------------------------------------------------
                                                Examples of regulated
                 Category                             entities
------------------------------------------------------------------------
Industry..................................  (1) Electric service
                                             providers
                                            (2) Process sources with
                                             large boilers and turbines
                                             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 the table could also be regulated. To determine whether 
your facility, company, business, organization, etc., is regulated by 
this action, you should carefully examine the applicability provisions 
in Secs. 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 of this preamble.

II. Background and Summary of the Proposed Rule

    Today's proposed action modifies existing monitoring and reporting 
requirements in 40 CFR parts 72 and 75 that support emission control 
programs that use the monitoring and reporting provisions of part 75 
such as the Acid Rain Program and State NO<INF>X</INF> reduction 
programs developed in response to the October 27, 1998, NO<INF>X</INF> 
SIP call. The emphasis of these revisions is three-fold: (1) To 
streamline the rule by eliminating outdated sections; (2) to make 
technical corrections and clarifications to the rule; and (3) to add 
flexibility to the monitoring and reporting requirements. The most 
substantive proposed changes are as follows: the definitions of 
``pipeline natural gas'' and ``natural gas'' in Sec. 72.2 would be 
revised to remove all references to the H<INF>2</INF>S content of the 
fuel and would instead be based on total sulfur content (corresponding 
changes would be made to appendix D to part 75); the compliance and 
certification timelines for certifying monitoring systems would be made 
the same for new units, newly affected units, deferred units, and new 
stacks; the low mass emissions (LME) units provisions in Sec. 75.19 
would be clarified; for units with certain types of NO<INF>X</INF> 
emission controls, qualification as a LME unit would be made easier; 
the CEMS missing data procedures would be revised to allow fuel-
specific missing data substitution as well as the use of a controlled 
and uncontrolled database for units with add-on emission controls; the 
missing data procedures in subpart H of part 75 would be expanded and 
clarified for sources that report emission data only in the ozone 
season; the NO<INF>X</INF> span and range provisions in appendix A 
would be revised to make them more realistic and easier to implement 
for combustion turbines; and the alternate calibration error limit for 
daily operation would be tightened from 10 ppm to 5 ppm for units with 
span values of 50 ppm or less. Many of the above changes to part 75 
would affect the monitoring and reporting sections of

[[Page 31980]]

the part 97 rule. Therefore, today's proposed rule would also revise 
certain sections of part 97 to make the monitoring and reporting 
sections of the part 75 and part 97 rules consistent. In addition, 
certain miscellaneous changes would be made to clarify or correct minor 
errors in other sections of part 97 or to make the administrative 
appeal procedures in part 78 applicable to decisions of the 
Administrator under part 97.

III. Detailed Discussion of Proposed Revisions

A. Rule Definitions

    EPA policy guidance and the instructions EPA has developed for 
monitoring and electronic reporting under part 75 rely on many terms 
that are used in part 75 but that are not defined in Sec. 72.2 (the 
definitions section for all Acid Rain Program regulations). Also, some 
of the existing definitions in Sec. 72.2 are incorrect or incomplete. 
To address these concerns, the proposed revisions would add or modify 
several definitions.
1. How Does EPA Propose To Revise the Definitions of Pipeline Natural 
Gas and Natural Gas in Sec. 72.2?
    Background. Following the May 26, 1999, rulemaking, a utility group 
sued EPA over the definitions of ``pipeline natural gas'' and ``natural 
gas'' contained in Sec. 72.2. The issue is that gaseous fuel must meet 
a two-fold requirement to qualify as one of these fuels. In the current 
rule, there is an H<INF>2</INF>S content limit (0.3 gr/100 scf for 
pipeline natural gas and 1.0 gr/100 scf for natural gas) and a 
requirement that H<INF>2</INF>S constitute more than 50 percent of the 
total fuel sulfur content. Appendix D to the rule does not explain how 
to comply with the second of these two requirements (the H<INF>2</INF>S 
as a percentage of total sulfur requirement). Further, industry members 
are concerned that this requirement cannot be implemented in a fair and 
consistent manner. For example, a very clean fuel with 0.1 gr/100 scf 
of H<INF>2</INF>S and 0.3 gr/100 scf of total sulfur would not qualify 
as pipeline natural gas, because H<INF>2</INF>S is less than 50 percent 
of the total sulfur content, but a fuel with three times more 
H<INF>2</INF>S and twice as much total sulfur (0.3 gr/100 scf of 
H<INF>2</INF>S and over 0.6 gr/100 scf of total sulfur) would qualify 
as pipeline natural gas under the current rule. In response to the 
industry's concerns, EPA recently issued guidance on how to demonstrate 
compliance with the H<INF>2</INF>S content limit. As explained in the 
guidance, EPA also granted a petition allowing owners or operators to 
meet total sulfur limits in lieu of the H<INF>2</INF>S percent of-
total-sulfur requirement.
    Discussion of Proposed Changes. The proposed rule would revise the 
definitions of ``pipeline natural gas'' and ``natural gas'' in 
Sec. 72.2. All references to H<INF>2</INF>S content would be removed 
and these fuels would be defined in terms of total sulfur content. For 
the purposes of determining SO<INF>2</INF> emissions, it makes no 
difference whether the fuel's sulfur is in the form of H<INF>2</INF>S 
or any other form. The proposed total sulfur content values are 0.5 gr/
100 scf or less for pipeline natural gas and 20.0 gr/100 scf or less 
for natural gas. EPA chose the value of 0.5 gr/100 scf for pipeline 
natural gas so that typical supplies of pipeline natural gas that have 
an average sulfur content of 0.2 to 0.3 gr/100 scf will consistently 
yield samples below this cutoff of 0.5 gr/100 scf. In addition, 
SO<INF>2</INF> emission rates calculated using this value will not be 
much higher than the rate of 0.0006 lb SO<INF>2</INF> /mmBtu for 
pipeline natural gas that EPA used to compute allocations for sources 
combusting pipeline natural gas. The value of 20.0 gr/scf is the 
maximum total sulfur content allowed under most contracts for 
transmitting pipeline natural gas and allowed under most tariffs 
established with the Federal Energy Regulatory Commission.
    In addition, appendix D, sections 2.3.1.4 and 2.3.2.4 would be 
revised to require initial and periodic sampling to document the total 
sulfur content of the fuel. The revised rule would require periodic 
sampling on a semiannual basis, as well as whenever it is reasonable to 
believe that the composition of the fuel supply has changed. For fuels 
that qualify as pipeline natural gas, the 0.0006 lb/mmBtu default 
SO<INF>2</INF> emission rate would be used, and for fuels that qualify 
as natural gas, an SO<INF>2</INF> emission rate would be calculated 
based on Equation D-1h in appendix D. Note that Equation D-1h would be 
revised to be based upon the total sulfur content of the fuel, rather 
than the H<INF>2</INF>S content.
2. How Does EPA Propose To Change the Definitions of Unit and Stack 
Operating Hours?
    Background. The current rule allows quality-assurance (QA) test 
exemptions and deadline extensions for continuous emission monitors, 
based on the amount of unit operation. Grace periods are also allowed 
to complete missed QA tests. To qualify for QA test extensions and 
exemptions, an owner or operator must determine whether there are at 
least 168 unit or stack operating hours in the quarter (so that the 
quarter meets the definition of a ``QA operating quarter''). The length 
of grace periods is also determined on a unit or stack operating hour 
basis. The rule defines ``unit operating hour'' and ``stack operating 
hour'' in such a way that partial operating hours are counted as full 
hours. This is counterintuitive to the way that source operators 
normally count operating hours. They normally count cumulative 
operating time so that 30 minutes of operation equals 0.5 operating 
hours, not 1.0 hours.
    Discussion of Proposed Changes. Definitions of ``cumulative stack 
operating hours'' and ``cumulative unit operating hours'' would be 
added to Sec. 72.2. The definitions of ``QA operating quarter'' and'' 
fuel flowmeter QA operating quarter'' would be revised to put them in 
terms of cumulative unit or stack operating hours. Finally, all 
references to the length of grace periods would be changed to be in 
terms of cumulative unit operating hours or cumulative stack operating 
hours.
3. What Other Definitions Would Be Revised or Added to the Rule?
    Background. There are several definitions in Sec. 72.2 that are 
either unclear or inconsistent with the way in which part 75 has been 
implemented. In addition, some terms that are used in the Acid Rain 
Program Policy Manual and the EDR v2.1 Instructions are not defined in 
the rule.
    Discussion of Proposed Changes. Under the proposal, EPA would add 
definitions of ``common pipe,'' ``common pipe operating time,'' 
``diluent cap value,'' ``fuel flowmeter system,'' ``fuel usage 
time,''''multiple stack configuration,'' ``stack operating time,'' and 
``unit operating time.'' These terms are all used in part 75 and the 
accompanying guidance materials, but are not defined in Sec. 72.2. EPA 
believes these terms should be defined because they are terms of art as 
used in various sections of part 75.
    Finally, the definitions of ``continuous emission monitoring system 
or CEMS,'' ``emergency fuel,'' ``heat input,'' ``hour before and 
after,'' ``maximum potential NO<INF>X</INF> emission rate,'' ``maximum 
rated hourly heat input,'' ``missing data period,'' ``monitor 
accuracy,'' ``stack operating hour,'' and ``unit operating hour'' would 
be revised. See the technical support document (Docket A-2000-33, Item 
II-A-2) for an explanation of these technical changes.

B. Certification Timeline Issues

1. What Is the Deadline for an Application for Initial Certification?
    Background. The current rule specifies different monitor 
certification timelines in Sec. 75.4, for new units, new

[[Page 31981]]

stacks, and deferred units. New units must certify their monitors 
within 90 calendar days after the unit commences commercial operation. 
Similarly, for newly affected units, owners or operators have 90 
calendar days from the date on which they become Acid Rain affected 
units to certify monitors. Also, when a new stack or flue gas 
desulfurization system (FGD) is constructed, the owner or operator has 
90 calendar days from the date on which emissions first exit to the 
atmosphere through the new stack or FGD to install and certify 
continuous monitoring systems. However, for deferred units (affected 
units that were in cold-storage on their compliance deadline), owners 
or operators have either 45 operating days or 180 calendar days 
(whichever occurs first) to certify monitors after recommencing 
operation. The 90 calendar day timeline has proven to be problematic, 
particularly for new units that experience mechanical problems when 
they first begin operating. The deferred unit timeline has greater 
flexibility.
    Discussion of Proposed Changes. EPA proposes to make all of the 
timelines the same for deferred units, new units, new stacks, and newly 
affected units. In all cases, the certification deadline would be the 
earlier of 90 unit operating days or 180 calendar days after the unit 
commences commercial operation or recommences operation. Paragraphs 
(b), (c), (d), and (e) of Sec. 75.4 would be revised to incorporate 
this change. Corresponding changes would be made to 40 CFR 97.70, the 
monitoring and reporting sections of the January 18, 2000, final 
section 126 rule, in order to make the certification timelines in parts 
75 and 97 consistent.
2. For an Appendix E Peaking Unit, When Is Initial Certification 
Required While Combusting the Backup Fuel?
    Background. The current rule specifies in Sec. 75.4(f) that for an 
appendix E unit for which certification testing prior to the applicable 
deadline has been done only while combusting the primary fuel, 
certification tests using backup fuel must be completed within 30 unit 
operating days after the backup fuel is first combusted following the 
certification deadline.
    Discussion of Proposed Changes. The proposal would revise 
Sec. 75.4(f) to state that certification is required within the earlier 
of 90 unit operating days or 180 calendar days after the backup fuel is 
first burned following the initial certification deadline. This revised 
timeline is consistent with the changes to the timelines in Sec. 75.4, 
paragraphs (b), (c), (d), and (e) in today's proposed rule.
3. What Happens if a Unit Loses Peaking, Gas-Fired, or LME Status?
    Background. Under the current rule, when an appendix E unit loses 
its status as a peaking unit, a NO<INF>X</INF> CEMS must be installed 
by December 31 of the following calendar year. Similarly, loss of gas-
fired unit status requires (in some cases) installation of a COMS by 
December 31 of the following year. Loss of low mass emissions (LME) 
unit status under Sec. 75.19 requires monitoring systems to be 
installed within two quarters after the quarter in which LME status is 
lost. The LME requirement appears to be inconsistent with the others in 
that it contains a shorter timeline to install and certify monitoring 
systems. In addition, when peaking unit or LME status is lost, the rule 
does not provide specific instructions regarding what emission values 
to report if the deadline for certifying monitors is not met.
    Discussion of Proposed Changes. For units that lose their LME 
status, EPA proposes to change the deadline in Sec. 75.19(b)(2) for 
monitor certification to December 31 of the year after the year in 
which the unit exceeded the LME applicability threshold(s), thus making 
the monitor certification timeline the same as the timelines in 
Secs. 75.12(d)(2) and 75.14(c) for, respectively, loss of peaking unit 
status and loss of gas-fired status. In the period from the time of 
loss of LME status until the certification deadline, units would 
continue to monitor and report in accordance with the provisions for 
LME units.
    Today's proposed rule also includes provisions in 
Secs. 75.19(b)(2), 75.12(d)(2), 75.71(d), and appendix E, section 1.1 
that would specify the emission reporting requirements when LME status 
or peaking unit status is lost and the monitor certification deadline 
is not met. For loss of peaking unit status, the maximum potential 
NO<INF>X</INF> emission rate would be reported after the CEM 
certification deadline. For loss of LME status, SO<INF>2</INF> and 
CO<INF>2</INF> emissions would be reported after the deadline using the 
applicable LME default emission rate and the maximum potential hourly 
heat input, and NO<INF>X</INF> emissions would be reported using the 
fuel specific maximum potential NO<INF>X</INF> emission rate.

C. Missing Data

1. How Will the Proposed Rule Affect the Missing Data Procedures in 
Secs. 75.31 Through 75.37 for Units That Produce Electrical or Thermal 
Output?
    Background. The part 75 CEMS missing data procedures in Secs. 75.31 
through 75.37 require the use of substitute data values for each unit 
operating hour in which quality-assured data are not obtained, either 
from a certified CEMS, a reference method, or an approved alternative 
monitoring system. The method of determining the appropriate substitute 
data values depends principally on two things: (1) The length of the 
missing data period; and (2) the percent monitor data availability at 
the end of the missing data period. In some cases, the substitute data 
value is simply the arithmetic average of the CEMS hourly averages 
recorded before and after the missing data period. In other cases, the 
substitute data value is either the 90th percentile value, the 95th 
percentile value, or the maximum value in a historical lookback period 
consisting of a certain number of quality-assured monitor operating 
hours (the previous 720 hours of quality-assured data for 
SO<INF>2</INF>, CO<INF>2</INF>, and moisture, and the previous 2,160 
hours of quality-assured data in a particular load range (``load bin'') 
for NO<INF>X</INF> and flow rate). Finally, if, at the time of the 
missing data period, the percent monitor data availability is below 80 
percent, the appropriate maximum potential value must be reported for 
each hour of the missing data period.
    The part 75 missing data procedures do not take into consideration 
the type of fuel combusted. Rather, a single database of quality-
assured monitor operating hours is maintained for each monitored 
parameter (SO<INF>2</INF>, NO<INF>X</INF>, flow rate, etc.) in order to 
provide substitute data values when a historical lookback is required. 
For a unit that combusts different types of fuel having significantly 
different emission levels for a particular parameter (e.g., for a unit 
which can burn either coal or natural gas, the SO<INF>2</INF> emissions 
are much higher when coal is burned), the substitute data values 
obtained in a historical lookback may not be representative of the 
actual emissions during the missing data period.
    For units with add-on SO<INF>2</INF> or NO<INF>X</INF> emission 
controls, Sec. 75.34 in the current rule allows three missing data 
options. The owner or operator may either: (1) Use the standard missing 
data procedures, if the controls are documented to be operating 
properly, or otherwise use maximum potential

[[Page 31982]]

values; or (2) petition the Administrator to use the maximum controlled 
emission rate recorded in the previous 720 quality-assured monitor 
operating hours, if the percent monitor data availability is below 90 
percent and if the controls are documented to be operating properly 
during the missing data period; or (3) petition the Administrator to 
use site-specific parametric monitoring procedures for missing data 
substitution. These missing data options have proven to be difficult to 
implement and lack flexibility. The representativeness of the 
substitute data values derived from these procedures, particularly for 
Options (1) and (3), is also uncertain.
    Option (1) requires parametric data to be recorded during missing 
data periods to document proper operation of the add-on emission 
controls, in order to justify using the standard missing data 
procedures. The parameters selected and the acceptable ranges for the 
parameters must be documented in the QA plan for the unit. The 
designated representative must submit a certification statement in the 
electronic quarterly report, affirming that the emission controls 
operated within the acceptable parametric ranges during each missing 
data period and that use of the standard missing data procedures is 
appropriate. This approach to missing data substitution is problematic 
because currently there are no clear guidelines, either in the rule or 
in EPA policy guidance, for selecting the appropriate parameters or the 
acceptable parametric ranges. Therefore, it is difficult to establish 
whether the emission controls are actually working properly during a 
missing data period, even if parametric data have been recorded and are 
available for auditing purposes. Further, when the standard missing 
data procedures are used, the substitute data values derived from 
historical lookbacks may not be representative of the actual emissions 
during the missing data period, because the historical databases used 
for the lookbacks include all quality-assured CEMS data, for both 
controlled and uncontrolled operation.
    Option (2), above, is difficult to implement administratively, 
because it requires a petition every time the owner or operator wants 
to use a missing data value based solely on data recorded during hours 
when the emission controls were working, instead of using the standard 
missing data routines. Use of this missing data option could therefore 
require a petition to be submitted to and answered by EPA every 
quarter.
    To date, no units in the Acid Rain Program have petitioned to use 
Option (3), above.
    Discussion of Proposed Changes. Today's proposed rule would revise 
the part 75 missing data procedures to allow missing data substitution 
to be done on a fuel-specific basis. Also, for units with add-on 
SO<INF>2</INF> or NO<INF>X</INF> emission controls, EPA proposes to 
revise Sec. 75.34 to include a new missing data option, based on the 
operating status of the emission controls. Note that the use of these 
new rule provisions would be optional. Therefore, sources using the 
missing data provisions in the current rule could continue to do so.
    Today's proposed rule would add fuel-specific missing data 
provisions to Sec. 75.33, in five new paragraphs, (b)(5), (b)(6), 
(c)(7), (c)(8), and (c)(9). These provisions would allow the owner or 
operator to create and maintain separate databases for each type of 
fuel combusted in the unit, for missing data purposes. Substitute data 
values would be derived from the appropriate database, depending on the 
type of fuel being burned during the missing data period. To use these 
new provisions, the owner or operator would be required to determine 
fuel-specific maximum potential values for concentration, emission 
rate, or flow rate (as applicable).
    The owner or operator would be allowed to switch to the new fuel-
specific missing data procedures at any time. Until the requisite 
number of hours of quality-assured fuel-specific data were recorded for 
the lookback periods (either 720 or 2,160 hours), the owner or operator 
would use all available data in the databases for the lookbacks.
    For units with add-on controls, the proposed rule would retain the 
missing data option in Sec. 75.34(a)(3), allowing the owner or operator 
to petition to use a site-specific parametric missing data substitution 
procedure. The owner or operator could also continue using the missing 
data option in Sec. 75.34(a)(1), which allows the standard missing data 
procedures to be used for hours in which proper operation of the 
emission controls is documented by means of parametric data, and 
requires maximum potential values to be reported for all other missing 
data hours. Note, however, that the proposed rule would expand and 
clarify the way in which parametric data are used to document proper 
operation of the add-on emission controls, as explained below in the 
discussion of the changes to Sec. 75.34(a)(2).
    Today's proposed rule would significantly revise Sec. 75.34(a)(2), 
to allow the owner or operator of a unit with add-on SO<INF>2</INF> or 
NO<INF>X</INF> emission controls (including units equipped with dry 
low- NO<INF>X</INF> technology) to create and maintain two separate 
databases, controlled and uncontrolled, for missing data purposes. Any 
hour in which the add-on controls are documented to be operating (on) 
would be included in the controlled database. Any hour in which the 
controls are not operating (off) would be included in the uncontrolled 
database. For units with more than one type of add-on controls (e.g., 
steam injection plus SCR), hours in which any of the add-on controls 
operate would be included in the controlled database. Alternatively, 
the uncontrolled database could consist of either: (a) quality-assured 
data recorded by a certified monitor at the control device inlet; or 
(b) for a unit with a main stack and a bypass stack, quality-assured 
data recorded by a certified monitoring system installed on the bypass 
stack.
    If the proposed missing data option in Sec. 75.34(a)(2) were 
selected, then, whenever a historical lookback was required, the 
substitute data value for each hour of the missing data period would be 
taken from the appropriate database (controlled or uncontrolled), 
depending on whether the emission controls are documented (by means of 
parametric data) to be operating properly during the hour. For the 
SO<INF>2</INF> missing data algorithms in Sec. 75.33, paragraphs 
(b)(1)(i) and (b)(2)(i), which require the hour before and hour after 
average value to be reported rather than performing a historical 
lookback, proposed Sec. 75.34(a)(2) would restrict the use of the hour 
before and hour after value to missing data hours in which the emission 
controls are documented to be operating properly; otherwise, the 
maximum uncontrolled value recorded in the previous 720 hours would be 
reported. The owner or operator would be required, under 
Sec. 75.58(b)(3), to keep records of the operational status (on or off) 
of the emission controls for all unit operating hours, and to keep 
records of the parametric data recorded during periods of missing 
SO<INF>2</INF> or NO<INF>X</INF> data. The designated representative 
would also be required to submit a certification statement in the 
quarterly report, verifying that the add-on controls were operating 
properly during each missing data hour in which substitute values from 
the controlled database were reported, or, for SO<INF>2</INF>, each 
missing data hour in which the average of the hour before and hour 
after values was reported.
    The owner or operator of a unit with add-on emission controls would 
be allowed to switch to the missing data

[[Page 31983]]

procedures in Sec. 75.34(a)(2) at any time. If, at the time of the 
change, the standard missing data procedures of Sec. 75.33 are already 
in use, and if hourly calculation of percent monitor data availability 
(PMA) is being performed according to Sec. 75.32, it would not be 
necessary to repeat the initial missing data procedures of Sec. 75.31. 
Rather, calculation of the PMA could continue uninterrupted and the two 
emission databases (controlled and uncontrolled) could be created 
prospectively. Alternatively, the databases could be created from 
historical CEM data, if records are available to document the operating 
status (on or off) of the add-on controls during each quality-assured 
monitor operating hour. Until the requisite number of hours of quality-
assured data for the lookback periods are recorded (i.e., either 720 or 
2,160 hours), the owner or operator would use all available data in 
each database for the lookbacks.
    Section 75.34(d) of the proposed rule would expand and clarify the 
way in which parametric data are used to document proper operation of 
add-on emission controls during periods of missing SO<INF>2</INF> or 
NO<INF>X</INF> data. According to Sec. 75.58(b)(3)(ii) of the current 
rule, ``proper operation'' of the controls means that parametric data 
were recorded during the missing data period, indicating that, ``all 
parameters * * * [were] * * * within the ranges specified in the 
quality assurance/quality control program.'' EPA believes that in view 
of today's proposed substantive changes to Sec. 75.34, this regulatory 
language is inadequate, because it gives no guidelines concerning which 
parameters to monitor or how to determine the acceptable parametric 
ranges.
    EPA therefore proposes to revise Sec. 75.34(d), as follows. The 
owner or operator of a unit with add-on controls would, for missing 
data purposes, still be required (as in the current rule) to document 
in the QA/QC program for the unit the parameter(s) monitored and the 
acceptable parametric ranges and combinations of parameters which 
indicate proper operation of the emission controls. However, for units 
that use a control method involving injection of water, steam, or 
chemical reagents into the combustion chamber or flue gas stream (e.g., 
limestone injection, limestone scrubbing, water injection, steam 
injection, SCR, or SNCR) today's proposed rule would require at least 
one key parameter to be monitored during missing data periods, to 
document proper emission control operation. A key parameter would be 
one that has a direct relationship to control device removal 
efficiency, such as the water-to-fuel ratio, the ammonia injection 
rate, or the slurry flow rate.
    Further, proposed Sec. 75.34(d) would require the owner or operator 
to establish a demonstrable correlation between the parametric data and 
control device removal efficiency, as part of the QA/QC program for the 
unit. The correlation would be based on parametric data recorded during 
unit operation, when the add-on controls are in-service and the 
SO<INF>2</INF> or NO<INF>X</INF> monitor at the control device outlet 
is providing quality-assured data. The correlation would be derived 
from a minimum of 720 hours of data, obtained at various load levels, 
representing the range of operation of the unit. The correlation would 
serve as the basis for determining whether substitute data values 
should be taken from the controlled database or from the uncontrolled 
database during periods of missing SO<INF>2</INF> or NO<INF>X</INF> 
data. Finally, the owner or operator would be required to provide to 
EPA or to the State, upon request, either the parametric data recorded 
during missing data periods or the related QA/QC program information 
(or both).
    EPA believes that the new proposed missing data option in 
Sec. 75.34(a)(2), which conditionally allows the use of substitute data 
values taken from a controlled database, would be sufficiently 
protective of the environment, for two reasons. First, if the add-on 
controls were not working properly when flagged as being on, emissions 
would be higher than normal. These high emission values would be 
recorded by the CEMS and would become part of the controlled database. 
This would result in conservatively high substitute data values being 
obtained from the historical lookbacks and applied to controlled 
missing data hours. Second, the proposed revisions to Sec. 75.34(d), 
requiring the owner or operator to monitor key parameters for certain 
types of controls and to develop an actual correlation between the 
parametric data and the removal efficiency of the control device, would 
provide reasonable assurance that the emission controls are operating 
properly during missing data periods.
2. How Will Subpart H Missing Data Provisions Be Affected for Units 
That Produce Electrical or Thermal Output?
    Background. The missing data procedures for subpart H units are 
specified in Secs. 75.70(f) and 75.74(c)(7). Section 75.70(f) requires 
the missing data procedures in subpart D of part 75 (Secs. 75.31 
through 75.37) to be used for sources that report emission data on a 
year-round basis. Section 75.74(c)(7) also requires subpart H sources 
that report data on an ozone season-only basis to use the missing data 
procedures of subpart D, except that: (1) Only data from within the 
ozone season are to be used in the historical lookbacks; and (2) when a 
fuel combusted in the current ozone season has a higher NO<INF>X</INF> 
emission rate than the fuel(s) burned in the previous ozone season, or 
when a unit's add-on controls are not working properly (as indicated by 
recorded parametric data), the maximum potential NO<INF>X</INF> 
emission rate (MER) must be reported.
    Discussion of Proposed Changes. Because owners and operators of 
subpart H units are required to use the initial and standard missing 
data procedures in Secs. 75.31 through 75.37, all of today's proposed 
changes to those sections would apply to subpart H units. Therefore, 
the owner or operator of a subpart H unit could elect to use either the 
new fuel-specific missing data procedures in Sec. 75.33 or, for units 
with add-on emission controls, the new missing data procedure in 
proposed Sec. 75.34(a)(2).
    Today's proposed rule would also revise Sec. 75.74(c)(7), the 
section which provides the missing data procedures for subpart H 
sources that report emission data only during the ozone season, rather 
than on a year-round basis. EPA proposes to make three substantive 
revisions to that section.
    First, Sec. 75.74(c)(7)(ii) would be revised to require reporting 
of the MER only when sufficient, prior quality-assured NO<INF>X</INF> 
emission data are not available for combustion of a new fuel that has a 
higher NO<INF>X</INF> emission rate than any fuel burned in the 
previous ozone seasons. Once sufficient quality-assured emission data 
are obtained for the new fuel, it would no longer be necessary or 
appropriate to report the MER, as NO<INF>X</INF> emission data for the 
new fuel would be in the missing data banks, and the standard, 
historical lookbacks could be used to provide representative substitute 
data values.
    Second, EPA proposes to remove from Sec. 75.74(c)(7)(ii) the 
requirement to report the MER when the NO<INF>X</INF> emission controls 
are not working properly, as indicated by parametric data recorded 
under Sec. 75.74(c)(8). The requirement to report the MER when the 
emission controls are not working properly is associated with the 
missing data option in Sec. 75.34(a)(1) and is found in that section. 
Therefore, it is unnecessary to restate the requirement in subpart H. 
Since proposed Sec. 75.74(c)(7)(ii) requires subpart H units that 
report data on an ozone season-only basis to use the missing data 
procedures in Secs. 75.31

[[Page 31984]]

through 75.37, owners and operators of such units must follow the 
missing data provisions in Sec. 75.34 if the units have add-on 
NO<INF>X</INF> emission controls. This includes the provision in 
Sec. 75.34(a)(1), if that missing data option is selected, requiring 
the MER to be reported when proper operation of the NO<INF>X</INF> 
emission controls cannot be documented.
    Third, today's proposed rule would add a new paragraph (iii), with 
subparagraphs (A) through (M), to Sec. 75.74(c)(7), explaining how to 
apply the initial and standard part 75 missing data procedures in 
Secs. 75.31 through 75.37 on an ozone season-only basis. EPA is adding 
these provisions to subpart H because the part 75 missing data routines 
are designed for sources that report emission data on a year-round 
basis. For example, for all of the part 75 standard missing data 
routines that use 720 or 2,160 hour historical lookbacks to determine 
the appropriate substitute data values, the databases for the lookbacks 
consist of quality-assured CEMS data that have been recorded throughout 
the year. Also, the percent monitor data availability (PMA) 
calculations described in Sec. 75.32 are always based on a particular 
number of unit operating hours, either the number of unit operating 
hours since initial certification, or the number of unit operating 
hours in the past three years, or the previous 8,760 unit operating 
hours. The number of unit operating hours used in the PMA calculations 
includes operating hours from all four calendar quarters of the year.
    Section 75.74, paragraph (c)(7)(i) clearly states that for subpart 
H sources that report data on an ozone season-only basis, only data 
from within the ozone season are to be included in the missing data 
routines. Thus, as written, the missing data procedures in subpart D of 
part 75, which use data from all twelve months of the year, are 
incompatible with the requirements of Sec. 75.74(c)(7)(i). Despite 
this, EPA believes that there is a relatively simple way to resolve 
this inconsistency in the rule, as discussed in the following 
paragraphs.
    Section 75.74, paragraph (c)(7)(iii) in today's proposed rule would 
modify the initial and standard part 75 missing data procedures in 
Secs. 75.31 through 75.37 to adapt them to sources that report emission 
data only during the ozone season. This adaptation is possible because 
there is a commonality between year-round reporting and ozone season-
only reporting--in both cases there is a discrete time period used for 
compliance determination. For year-round reporters, that time period is 
the calendar year, and for ozone season-only reporters, the compliance 
time period is the ozone season. This commonality allows the missing 
data instructions for ozone season-only reporters to be written in a 
parallel manner to the missing data procedures for year-round 
reporters.
    Paragraphs (A) through (M) in proposed Sec. 75.74(c)(7)(iii) 
provide the necessary parallel rule language to adapt the missing data 
provisions in Secs. 75.31 through 75.37 to ozone season-only reporters. 
The following is a summary of the essential elements of these proposed 
rule provisions:
    <bullet> Use of the initial missing data procedures in Sec. 75.31 
would commence with the first operating hour in the first ozone season 
for which emission reporting is required.
    <bullet> For initial missing data purposes and for the historical 
data lookbacks required under Sec. 75.33, phrases such as ``720 
quality-assured monitor operating hours'' would be replaced with 
phrases such as ``720 quality-assured monitor operating hours within 
the ozone season.''
    <bullet> For PMA calculations, phrases such as ``total unit 
operating hours'' would be replaced with ``total unit operating hours 
within the ozone season.'' Also, ``8,760 unit operating hours'' (the 
number of hours in a calendar year) would be replaced with ``3,672 unit 
operating hours'' (the number of hours in an ozone season).
    <bullet> For both PMA calculations and historical lookbacks, the 
phrase ``three years (26,280 clock hours)'' would be replaced with 
``three ozone seasons.''
3. What Are the Missing Data Requirements for Units That Do not Produce 
Electrical or Thermal Output?
    Background. Today's proposed rule would add missing data procedures 
to part 75 for units that do not generate electricity or produce steam 
load. The new missing data provisions would be added to Secs. 75.31 and 
75.33, to appendix C of part 75, and to section 2.4 of appendix D. The 
rationale for these new provisions and a discussion of the provisions 
are presented in the following paragraphs.
    As stated in Section II of this preamble, one of the main 
objectives of today's proposed rule is to modify the existing 
monitoring and reporting sections of parts 72 and 75 which support 
emission control programs that use the monitoring and reporting 
provisions of part 75, such as State NO<INF>X</INF> reduction programs 
developed in response to the October 27, 1998 SIP call. Under the 
NO<INF>X</INF> SIP call, States have the flexibility to include 
stationary sources other than electric generating units in their 
NO<INF>X</INF> reduction plans. For example, the State of New York has 
proposed regulation 204 to control emissions of nitrogen oxides from 
stationary sources. The sources affected by this regulation include EGU 
and non-EGU sources, such as industrial boilers and cement kilns. To 
comply with sections 204-8 of this regulation, all of the affected 
units must monitor and report NO<INF>X</INF> mass emissions according 
to subpart H of 40 CFR part 75, beginning on May 1, 2002. Other States, 
including New Jersey, Pennsylvania, Maryland, Delaware, and 
Massachusetts have proposed, or may be proposing, similar rules which 
require some non-electric generating units to monitor according to 
subpart H of part 75. To date, EPA has identified three non-EGU source 
categories that would likely be subject to part 75 monitoring and 
reporting under the various State rules: industrial boilers, refinery 
process heaters, and cement kilns.
    At the request of the New York State Department of Environmental 
Conservation, EPA examined the part 75 monitoring provisions to assess 
whether these provisions are adequate for determining NO<INF>X</INF> 
mass emissions from non-electric generating units. As a result of this 
assessment, EPA concluded that for industrial boilers, which produce 
thermal output (i.e., steam load) and which are very similar to 
electric utility boilers, no significant changes to the monitoring and 
reporting provisions of part 75 would be required. However, for cement 
kilns and refinery process heaters, which do not produce electricity or 
steam load, EPA has identified three key areas where modifications to 
the existing part 75 monitoring provisions would be necessary to allow 
full and complete monitoring of NO<INF>X</INF> mass emissions. These 
areas are:
    <bullet> Determination of the maximum potential concentration (MPC) 
for NO<INF>X</INF>;
    <bullet> The missing data routines for NO<INF>X</INF> 
concentration, NO<INF>X</INF> emission rate, stack flow rate, and fuel 
flow rate; and
    <bullet> RATA load level requirements.
    Discussion of Proposed Changes. To address the first issue 
(NO<INF>X</INF> MPC determination), EPA is proposing to add default MPC 
values for process heaters and cement kilns to part 75. The selected 
MPC values and the rationale for them are found in section III.F.3 of 
this preamble. The third issue (RATA load level requirements) is 
discussed in detail in section III.F.10 of this preamble. To address 
the second issue (missing data routines), EPA is proposing to add non-
load-based missing data procedures to part 75, as previously noted.

[[Page 31985]]

    The missing data procedures in part 75 for NO<INF>X</INF>, stack 
flow rate, and fuel flow rate are load-based. That is, all of the 
quality-assured hourly data recorded by part 75 NO<INF>X</INF> 
monitors, flow monitors, and fuel flowmeters are segregated into load 
ranges (or ``bins''). The purpose of using the load bin approach is to 
ensure that representative substitute data values are provided during 
periods of monitor downtime (i.e., for each missing data hour, the 
appropriate substitute data value is taken from the corresponding load 
bin). However, for units that do not produce electrical or thermal 
output, the current part 75 missing data procedures for NO<INF>X</INF>, 
stack flow rate, and fuel flow rate are inadequate.
    The missing data procedures for non-load-based units in today's 
proposed rule are the result of discussions between EPA and 
representatives of the cement industry. The Agency had received a 
letter on August 20, 1999, from the American Portland Cement Alliance 
(APCA) (see Docket A-2000-33, Item II-D-1), containing a proposed 
methodology for performing missing data substitution for NO<INF>X</INF> 
and flow rate at cement kilns. EPA responded to this draft proposal in 
a letter to APCA dated April 24, 2000 (see Docket A-2000-33, Item II-C-
2). In that response letter, the Agency expressed agreement with some, 
but not all, of the provisions of APCA's proposal. The missing data 
approach outlined in today's proposed rule for non-load-based units 
reflects EPA's stated position in the April 24, 2000, letter to APCA.
    The proposed non-load-based missing data routines are modeled 
after, and are much the same as, the existing routines for load-based 
units. However, there are two important differences:
    <bullet> The owner or operator of a non-load-based unit would have 
the choice of either not using bins at all or using ``operational 
bins'' to segregate the quality-assured NO<INF>X</INF>, stack flow 
rate, or fuel flow rate data; and
    <bullet> For a non-load-based unit, the arithmetic average of the 
previous 2,160 quality-assured hours of NO<INF>X</INF> concentration or 
NO<INF>X</INF> emission rate (as applicable) would be used in the 
standard NO<INF>X</INF> missing data routines, instead of the 
arithmetic average of the values from the hour before and hour after 
the missing data period.
    The reason for allowing the use of operational bins is to give 
affected facilities the flexibility to customize their missing data 
routines, based on plant operational parameters and conditions that 
affect NO<INF>X</INF> emissions, stack flow rate, or fuel flow rate. 
The procedures and requirements for defining operational bins are found 
in proposed new sections 3 and 4 of appendix C to part 75. The owner or 
operator would be required to provide a complete description of each 
operational bin in the hardcopy portion of the monitoring plan required 
under Secs. 75.53(e)(2) (for NO<INF>X</INF> and stack flow rate) or 
75.53(f)(1)(ii) (for fuel flow rate). The description of each 
operational bin would include the unique combination of parameters and 
operating conditions associated with the bin and an explanation of the 
relationship between these parameters and conditions and the magnitude 
of the NO<INF>X</INF> emissions, stack flow rates, or fuel flow rates. 
When using operational bins, it would be necessary to monitor the 
parameter(s) and operating conditions used to define the operational 
bin. For any hour in which essential operating or parametric data are 
unavailable and the operational bin could not be determined, the 
proposed non-load-based provisions in Secs. 75.31 and 75.33 and section 
2.4 of appendix D would require maximum potential values to be 
reported.
    In response to a recommendation by the cement industry, EPA 
proposes to use the average of the previous 2,160 quality-assured hours 
of NO<INF>X</INF> data in the standard missing data routines for non-
load-based units instead of using the average of the hour before and 
hour after values. APCA advocated this approach in the previously 
mentioned missing data proposal that was sent to EPA on August 20, 
1999. EPA agrees with APCA's position that hour-to-hour variability of 
NO<INF>X</INF> emissions from a cement kiln is high, and using the hour 
before and hour after average could cause significant underestimation 
or overestimation of emissions.
4. How Will Today's Proposed Rule Revise the Procedures in Appendix C 
for Establishing Load Ranges (or ``bins'') for Missing Data Purposes?
    Background and Discussion of Proposed Changes. Today's proposed 
rule will revise section 2.2.1 of appendix C to clarify the method of 
determining the maximum hourly average gross load (MHGL) for 
cogeneration units or other units for which some portion of the heat 
input is not used to produce electricity. The MHGL for such units would 
be determined by converting the maximum rated hourly heat input of the 
unit to an equivalent electrical output in megawatts. The maximum rated 
hourly unit heat input would include the maximum potential heat input 
from auxiliary combustion sources, such as duct burners or auxiliary 
boilers. The efficiency of the unit would be used in conjunction with 
the maximum unit heat input to calculate the MHGL. If the actual 
efficiency of a particular combustion source is unknown, a default 
efficiency of 50 percent would be used for a combustion turbine, and 33 
percent for any other type of combustion source. Having established the 
maximum hourly gross load, the missing data load ranges would then be 
determined as percentages of the MHGL.
5. How Will the Maximum Potential Moisture Provision Be Revised?
    Background. For units for which you continuously account for the 
stack gas moisture content with a moisture monitoring system, 
substitute data must be reported whenever an hourly moisture reading is 
missing. When a moisture monitoring system is uncertified, and when the 
percent monitor data availability for moisture drops below 80 percent, 
the maximum potential moisture percentage or the minimum potential 
moisture percentage must be reported (depending upon which emission and 
heat input rate equations are used). For the minimum potential moisture 
percentage, the rule specifies that the value may be determined from 
quality-assured CEM data or a default value of 3 percent H<INF>2</INF>O 
may be used. However, to determine the maximum potential moisture 
percentage, the rule requires quality-assured CEM data to be used--no 
default value is specified.
    Discussion of Proposed Changes. The proposal would add a second 
option to section 2.1.6 of appendix A, allowing the use of a default 
maximum potential moisture value of 16 percent H<INF>2</INF>O. This 
revision would treat maximum and minimum potential moisture values on a 
consistent basis for substitute data purposes.
6. How Will the Proposed Rule Affect the Method of Determination Codes?
    Background. Two method of determination codes, MODC values ``13'' 
and ``15'' from Table 4a under Sec. 75.57, became inactive as of 
January 1, 2000. Also, today's proposed rule would add provisions that 
require new MODCs that do not appear in the current version of Table 
4a.
    Discussion of Proposed Changes. EPA proposes to add three new MODC 
codes, ``21,'' ``22,'' and ``23'' to Table 4a in Sec. 75.57 for use in 
the electronic data reporting (EDR) format, and to designate the 
inactive codes ``13'' and ``15'' as ``Reserved.'' MODC 21 would be used 
when replacing a negative hourly concentration, emission rate, or 
percent moisture value with zero. MODC 22 would be used when an hourly 
average

[[Page 31986]]

SO<INF>2</INF> or NO<INF>X</INF> concentration is reported from a 
certified monitor at the inlet to an emission control device. MODC 23 
would be used when the maximum potential SO<INF>2</INF> concentration, 
CO<INF>2</INF> concentration, NO<INF>X</INF> concentration, 
NO<INF>X</INF> emission rate, or flow rate, or when the minimum 
potential moisture percentage is reported for an hour in which flue 
gases are discharged through an unmonitored bypass stack. These changes 
will make the specific electronic data reporting format elements 
consistent with the rule.

D. Low Mass Emissions (LME) Units

1. What Are the Certification Requirements for Low Mass Emissions (LME) 
Units?
    Background. In response to concerns raised by both regulated 
entities and other regulatory agencies, EPA examined the administrative 
procedures pertaining to LME units in part 75. It was determined that 
some provisions should be clarified to simplify program implementation 
and insure that the LME requirements are consistent with other sections 
of part 75.
    Discussion of Proposed Changes. The proposed revisions require the 
electronic portion of the LME certification application to be sent to 
EPA Headquarters (the Clean Air Markets Division) and the hardcopy 
portion to the appropriate Region and State. The proposal would also 
require LME applications to be submitted no less than 45 days prior to 
the date on which use of the methodology will commence.
    In addition, EPA proposes to remove the references to January 1, 
1997, in Secs. 75.19(a)(2)(ii), 75.19(b)(4), and 75.20(h)(3), as this 
date has no regulatory or statutory significance. Instead, the use of 
these provisions would depend upon whether a unit is a new or newly 
affected unit and to what extent the LME applicability demonstration 
relies on the use of projected data, instead of actual, historical 
data. The proposal would also clarify the period of provisional 
certification for LME units in Sec. 75.20(h)(3), the date on which a 
qualifying unit begins using the methodology in Sec. 75.19(a)(1)(ii), 
and the certification application submittal process in 
Sec. 75.63(a)(1).
2. How Does the LME Methodology Apply to Subpart H Units?
    Background. In its current form Sec. 75.19 contains only a limited 
explanation of the requirements for units subject to subpart H of part 
75 (and not covered under the Acid Rain Program) that are using the LME 
methodology to account for emissions. Note that some of these 
requirements for subpart H units are the same as those for Acid Rain 
Program units.
    Discussion of Proposed Changes. Paragraphs (a), (b), and (c) of 
Sec. 75.19 would be revised to distinguish the applicability, on-going 
qualification, and reporting requirements for Acid Rain Program units 
and non-Acid Rain Program, subpart H units. The revisions would make a 
clear distinction between sources that report emission data on a year-
round basis and those that report data only during the ozone season. 
These changes would help owners and operators of non-Acid Rain Program 
units understand how to comply with the LME requirements. Language was 
added to clarify that non-Acid Rain Program units using the LME 
methodology and the provisions of subpart H of part 75 (to comply with 
the monitoring and reporting requirements of a NO<INF>X</INF> mass 
trading program) must submit NO<INF>X</INF> mass emission data, but are 
not required to submit SO<INF>2</INF> mass emissions data. In addition, 
language was added to clearly state the initial and ongoing 
qualification criteria for non-Acid Rain Program units. Specifically, 
non-Acid Rain Program units for which you choose to report data year 
round under the LME methodology must emit no more than 50 tons of 
NO<INF>X</INF> annually, while units for which you choose to report 
only ozone season NO<INF>X</INF> mass emission data must emit no more 
than 25 tons of NO<INF>X</INF> each ozone season.
3. When Must the Annual Demonstration for LME Units be Completed?
    Background. The current rule does not specifically state the 
deadline for performing the annual demonstration of LME qualification. 
EPA believes that a consistent standard should be used for all units 
every year.
    Discussion of Proposed Changes. For a unit to continue to qualify 
as a LME unit, certain mass emission thresholds must be met on an on-
going basis. These thresholds are: 25 tons SO<INF>2</INF> and 50 tons 
NO<INF>X</INF> annually for an Acid Rain Program unit; 50 tons 
NO<INF>X</INF> annually for a non-Acid Rain Program, subpart H unit 
reporting on a year-round basis; and 25 tons per ozone season for a 
non-Acid Rain Program, subpart H unit reporting on an ozone season 
basis only. The owner or operator must demonstrate annually that the 
unit does not exceed the applicable mass emissions threshold(s). The 
proposed rule would add language to Sec. 75.19(b)(1) to expressly state 
that the annual demonstration will be considered complete only when the 
official data reconciliation process is complete. More specifically, 
only the final emissions data record for the year or ozone season 
(i.e., the final accounting of emissions, after data have been fully 
reconciled and any necessary quarterly report resubmittals have been 
made) will be used to determine whether a unit has met the applicable 
mass emissions threshold and satisfied the LME qualification 
requirements.
4. How Should EPA Reference Method 20 Be Altered When Determining a 
Fuel-and Unit-Specific NO<INF>X</INF> Emission Rate for an LME Unit?
    Background. The Method 20 test procedures require the measured 
NO<INF>X</INF> concentrations to be corrected to 15 percent O2. For 
units simply determining the NO<INF>X</INF> emission rate, this 
correction is unnecessary because the measured fuel- and unit-specific 
NO<INF>X</INF> emission rate will be the same whether or not the 
concentration is corrected to 15 percent O2.
    Discussion of Proposed Changes. Today's proposal would remove the 
requirement from Sec. 75.19(c)(1)(iv)(A) that a unit must correct 
NO<INF>X</INF> concentration values to 15 percent O2 when performing 
Method 20 testing.
5. What Temperature and Humidity Corrections are Required for Turbines 
When Unit- and Fuel-Specific NO<INF>X</INF> Emission Rates are 
Determined for LME Units?
    Background. Beginning in the 1999 ozone season, the Ozone Transport 
Commission (OTC) NO<INF>X</INF> Budget Program required monitoring and 
reporting of NO<INF>X</INF> mass emissions for use in a regional 
NO<INF>X</INF> trading program. Each State participating in the program 
required monitoring and reporting to be performed according to the 
``Guidance for Implementation of Emissions Monitoring Requirements for 
the NO<INF>X</INF> Budget Program'' and the `` NO<INF>X</INF> Budget 
Program Monitoring Certification and Reporting Instructions.'' These 
documents required reporting of emissions data in the Electronic Data 
Reporting (EDR) version 2.0 format. Under this program, a large number 
of small peaking turbines were required to begin monitoring and 
reporting data in the EDR v2.0 format. This group of units contains 
simple combustion peaking turbines of 15 to approximately 75 MWh 
capacity. These units have historically been exempt from the Acid Rain 
Program monitoring and reporting under either Sec. 72.6(b)(1), an 
exemption for simple turbines built prior to November 15, 1990, or 
Sec. 72.7, the new unit exemption. The monitoring and

[[Page 31987]]

reporting options allowed for these type of units in the OTC 
NO<INF>X</INF> Budget Program guidance documents are similar to the 
monitoring and reporting provisions under Sec. 75.19 with some key 
differences, including the use of a multiplier of 1.15 to all fuel- and 
unit-specific NO<INF>X</INF> emission rates determined using the 
testing procedures of appendix E. In the preamble to the May 1999 final 
revisions to part 75, EPA states that the reason for the 1.15 
multiplier is that the NO<INF>X</INF> emission rate may vary at a given 
load for any particular unit. In particular, EPA was concerned with 
possible underestimation of emissions using the results of appendix E 
testing to determine fuel- and unit-specific NO<INF>X</INF> emission 
rates.
    EPA anticipates that the majority of the simple peaking turbine 
units described above will be required to begin monitoring and 
reporting data according to the LME provisions under Sec. 75.19 in the 
future as part of a larger NO<INF>X</INF> trading program. Several 
utilities asked that the LME requirements under Sec. 75.19 be modified 
to allow removal of the 1.15 multiplier to fuel and unit-specific 
NO<INF>X</INF> emission rates. They argued that the requirement to use 
a 1.15 multiplier would result in a high overestimation of 
NO<INF>X</INF> emission rates under some circumstances. EPA 
investigated the causes of variability in NO<INF>X</INF> emission rates 
in turbines by reviewing literature, reviewing test results, analyzing 
CEMS data for turbines, and by discussing turbine operation with 
turbine and utility experts (see Docket A-2000-33, Item II-B-1). The 
result of the investigation was confirmation that temperature, 
pressure, and, in particular, humidity affect the NO<INF>X</INF> 
emission rate in combustion turbines. The investigation revealed that 
several empirically-derived mathematical algorithms have been developed 
to correct a measured NO<INF>X</INF> concentration to a theoretical 
NO<INF>X</INF> concentration at a different temperature, pressure, and 
humidity, including the equation in subpart GG, Standards of 
Performance for Stationary Gas Turbines (Sec. 60.335).
    Discussion of Proposed Changes. The proposal would add a new 
requirement for certain turbines to correct measured NO<INF>X</INF> 
concentrations using an equation similar to the equation in subpart GG 
of the New Source Performance Standards (40 CFR part 60), for 
correcting to the International Organization for Standardization (ISO) 
standard ambient conditions. This correction, in 
Sec. 75.19(c)(1)(iv)(A)(4), would apply only to uncontrolled diffusion 
flame style turbines and would compensate for temperature and humidity 
effects on NO<INF>X</INF> formation by correcting the measured 
NO<INF>X</INF> concentrations at the test conditions to the average 
annual temperature, atmospheric pressure, and humidity at the location 
of the turbine. If a unit (including an Acid Rain Program unit) is 
subject to an ozone season-based NO<INF>X</INF> mass emission reduction 
program, average ozone season values of temperature, atmospheric 
pressure, and humidity would be used instead of average annual values. 
The proposed rule suggests (but does not require) using National 
Oceanic and Atmospheric Administration temperature and humidity data 
from the weather station at the nearest airport. This provision would 
prevent underestimation or overestimation of NO<INF>X</INF> emissions 
for uncontrolled diffusion flame turbines. Today's proposal also 
removes the requirement to multiply the measured NO<INF>X</INF> 
emission rates for such turbines by 1.15, as the new correction 
equation would make use of the multiplier unnecessary.
6. How Is Identical Unit Status Demonstrated for a Group of LME Units?
    Background. The rule currently requires, in 
Sec. 75.19(c)(1)(iv)(B)(1), that to be considered identical a group of 
LME units must be of the same manufacturer, model, and size, have the 
same history of modifications (e.g., the same controls installed), and 
have similar outlet temperatures under similar operating conditions. 
Section 75.19(c)(1)(iv)(B)(3) further requires that if there are more 
than two identical units in the group, the NO<INF>X</INF> emission rate 
of each unit tested must be within 10 percent of the average emission 
rate for all units tested, at each load level.
    Discussion of Proposed Changes. The proposal would delete from 
Sec. 75.19(c)(1)(iv)(B)(3) the requirement that the emission rate for 
each unit must be within 10 percent of the group average rate in order 
for a particular unit to be considered an identical unit. These 
proposed identical unit provisions in part 75 are based in large part 
on comparable provisions used under the Ozone Transport Commission 
(OTC) NO<INF>X</INF> Budget Program. Because the OTC requirements for 
identical units have been effective and have minimized the compliance 
burdens on LME units, EPA believes that it is appropriate to eliminate 
the ten percent requirement from the part 75 LME provisions. The 
criteria in Sec. 75.19(c)(1)(iv)(B)(1) for identifying identical units 
would be retained, however.
7. How Is the Fuel- and Unit-Specific NO<INF>X</INF> Emission Rate 
Determined for LME Turbines Equipped With Water Injection, Steam 
Injection, or Water/Fuel Emulsion, and no Other Type(s) of add-on 
NO<INF>X</INF> Controls?
    Background. The current LME provisions in Sec. 75.19 include a 
provision which restricts the use of fuel- and unit-specific 
NO<INF>X</INF> emission rates to be no less than 0.15 lb/mmBtu for 
units with any type of NO<INF>X</INF> emission controls. Use of the 
0.15 value ensures that large, highly controlled units would not use 
the LME provisions for estimating emissions. EPA believes that the LME 
provisions are inappropriate for units with such controls as SCR or 
SNCR and that NO<INF>X</INF> emission monitoring is the only effective 
way to determine that a unit achieves its target control level. 
Industry representatives have asked EPA to consider allowing the use of 
controlled fuel and unit specific NO<INF>X</INF> emission rates below 
the 0.15 lb/mmBtu minimum for turbines with water injection, steam 
injection, or water/fuel emulsion. The representatives stated that if 
the water-to-fuel ratio were monitored each hour, the use of a fuel- 
and unit-specific default for times when the water-to-fuel ratio were 
within acceptable limits would not underestimate emissions.
    EPA investigated the claims of the industry representatives. EPA 
reviewed data from CEMS installed at turbines with water and steam 
injection and water/fuel emulsion. Based on results of the 
investigation, EPA believes that if the water-to-fuel ratio is 
monitored, then effective and constant control of NO<INF>X</INF> is 
achieved with little chance of underestimation of NO<INF>X</INF> 
emissions (see Docket A-2000-33, Item II-B-1).
    Discussion of Proposed Changes. The proposal would revise 
Sec. 75.19(c)(1)(iv)(H)(1) to allow the use of measured NO<INF>X</INF> 
emission rates for units with water or steam injection or water/fuel 
emulsion (and no other type(s) of add-on NO<INF>X</INF> controls) even 
if the emission rates are below 0.15 lb/mmBtu. This removes the current 
rule requirement that all tested emission rates below 0.15 lb/mmBtu be 
adjusted upward to a default value of 0.15 lb/mmBtu. The proposed 
action requires units with steam or water injection to monitor the 
water-to-fuel or steam-to-fuel ratio in order to give assurance that 
the emission controls are operating properly, making it unnecessary to 
use the default value.

[[Page 31988]]

8. What Effect Would Today's Proposed Rule Have on LME Units Sharing a 
Common Fuel Supply?
    Background. The current LME provisions require that where a group 
of units shares a common fuel supply, use the long term fuel flow 
(LTFF) methodology for heat input, and use a fuel-and unit-specific 
default NO<INF>X</INF> emission rate, the group of units must perform 
the required testing and use the highest tested NO<INF>X</INF> emission 
rate for all units. EPA has reviewed the requirement for taking the 
highest NO<INF>X</INF> emission rate for all units, found it to be 
unnecessary, and is proposing to remove the requirement.
    Discussion of Proposed Changes. Today's proposal would delete and 
reserve Secs. 75.19(c)(1)(iv)(C)(2) and 75.19(c)(1)(iv)(C)(5). These 
sections describe unnecessary restrictions for groups of units sharing 
a common fuel supply and using the long term fuel flow heat input 
approach. It is highly unlikely that an incorrectly apportioned heat 
input for units with different efficiencies could lead to improper 
estimation of emissions. Therefore, EPA proposes to remove these 
restrictions from the rule. In addition, a source would use the highest 
rate at each individual unit to calculate emissions from that unit, 
rather than using the highest NO<INF>X</INF> emission rate from the 
entire group of units.
9. When Would Single Load Testing Be Allowed to Determine Unit- and 
Fuel-Specific NO<INF>X</INF> Emission Rates for LME Units?
    Background. The current LME provisions require four load testing 
for all units which opt to determine a default fuel- and unit-specific 
NO<INF>X</INF> emission rate. Several industry representatives asked 
that this requirement be waived for units which operate at a single 
load only. EPA considered two options as alternatives to the four load 
testing requirement.
    Option 1. Require the first appendix E test to be performed at all 
four loads, then allow future testing to be performed at the load at 
which the highest NO<INF>X</INF> emission rate was found.
    Option 2. Allow single load testing for units which submit a 
demonstration that a unit operates at a single load.
    EPA considers option 2 to be preferable. It allows single load 
testing to be performed as of the first test and can save time and 
effort, consistent with the intent of the LME provisions to be cost 
effective and simple to use. EPA solicits comment on these methods or 
other methods suitable for allowing single load testing to be used for 
determining fuel- and unit-specific NO<INF>X</INF> emission rates.
    Discussion of Proposed Changes. EPA proposes to add a new provision 
to the rule, Sec. 75.19(c)(1)(iv)(I), which would conditionally allow 
single load testing for a unit which the owner or operator can 
demonstrate has operated at a single load level for at least 85 percent 
of the time in the three years prior to the emission test. In addition, 
the new section would conditionally allow turbines, that operate to a 
set point temperature and not a given load, to perform single load 
testing. If a set point turbine is tested at base load, but the unit is 
capable of operating at a higher (peak) load and is not tested at peak 
load, the fuel- and unit-specific NO<INF>X</INF> emission rate obtained 
from the base load testing would be adjusted upward using a 
conservative multiplier of 1.15 to ensure that emissions are not 
underestimated when the unit operates at peak load.
10. How Are Unit-Specific, Fuel-Specific NO<INF>X</INF> Emission Rates 
for LME Units Determined From the Individual Test Run Data at Each Load 
Level?
    Background. The current LME provisions require the use of the 
highest emission rate from the appendix E test. This language is not 
clear in describing whether the value used was the highest reading of 
any run during the test or the average of the required three runs 
during the test. In this rulemaking EPA is clarifying its intent that 
the three run average from a test is the value used as the fuel- and 
unit-specific default emission rate.
    Discussion of Proposed Changes. Today's proposal would revise 
Sec. 75.19(c)(1)(iv)(C) to clarify the way in which the fuel- and unit-
specific NO<INF>X</INF> emission rates are calculated for LME units 
when four load emission tests are performed. The proposal would add new 
language to that section, explaining how to determine the appropriate 
NO<INF>X</INF> emission rates when single load testing is performed.
    For four load testing of an individual LME unit, the appropriate 
NO<INF>X</INF> emission rate would be the highest three-run average 
obtained at any load level tested. For single load testing, the 
NO<INF>X</INF> emission rate would simply be the three-run average at 
the load level tested. For four load testing of a group of identical 
LME units, the appropriate NO<INF>X</INF> emission rate would be the 
highest three-run average obtained for any unit in the group, at any 
load level tested. For single load testing of a group of identical LME 
units, the NO<INF>X</INF> emission rate would be the highest three-run 
average obtained for any tested unit.
11. Which Mathematical Equations Are Affected by the Proposed Changes 
to Sec. 75.19?
    Background. Today's proposal would correct several equations 
pertaining to LME units. These revisions are necessary to correct one 
equation and to clarify the nomenclature of several other equations.
    Discussion of Proposed Changes. The proposed revisions will correct 
Equation LM-1 and clarify the nomenclature for Equations LM-3, LM-5, 
LM-6, LM-7, LM-7a, LM-8, and LM-8a.

E. Conditionally Valid Data--Mandatory Use

    Background. In the May 26, 1999, revisions to part 75, new CEM data 
validation provisions were promulgated. One such provision in 
Sec. 75.20(b)(3) addresses the use of conditional data validation. For 
recertification testing and diagnostic tests, Sec. 75.20(b)(3) requires 
that sources use conditional data validation. For initial 
certifications and routine quality assurance, the rule allows, but does 
not require, conditional data validation.
    Discussion of Proposed Changes. To address the inconsistency in the 
rule, Sec. 75.20(b)(3) would be revised to make the use of conditional 
data validation optional in all cases. Appendix A, sections 2.1.1.5(c) 
and 2.1.2.5(c) and appendix B, sections 2.2.5, would also be revised to 
reference the amended Sec. 75.20(b)(3).

F. Quality Assurance/Quality Control (QA/QC)

1. What Changes Are Proposed for CEMS Span and Range Evaluations?
    Background. Part 75 requires periodic evaluations (at least 
annually) of the spans and ranges of all required continuous monitors 
to ensure that the proper span and range values are being used. To 
perform the annual span/range evaluation, a review of the emission data 
from the past year is required. The results are acceptable if the data 
meet the guidelines in section 2.1 of appendix A. The basic requirement 
of that section is for the majority of the data to be between 20 and 80 
percent of the full-scale range, with certain allowable exceptions.
    With the increased emphasis in recent years on reducing 
NO<INF>X</INF> emissions, many new combustion turbines are being built. 
The span/range evaluation guideline in section 2.1 of appendix A does 
not fully address the issues raised by this type of unit. These units 
typically have NO<INF>X</INF> controls capable of reducing emissions to 
very low levels (e.g., 20 ppm or less for oil-firing and

[[Page 31989]]

less than 10 ppm for gas-firing) and are often required by part 75 to 
have two measurement ranges (low and high). Some of these units operate 
their emission controls only on a seasonal basis, rather than year-
round. One span and range issue for these units is that when natural 
gas is combusted, the majority of the NO<INF>X</INF> emissions may not 
meet the 20 to 80 percent guideline of section 2.1 if, for example, the 
low-scale measurement range is set at 25 ppm based on oil-firing, in 
accordance with section 2.1.2.3 of appendix A. Further, if gas is the 
primary fuel in this example and the NO<INF>X</INF> emissions are 
typically 5 ppm or less during gas combustion, one might erroneously 
conclude during the annual span/range evaluation that the low range 
needs to be adjusted or that a third monitoring range (e.g., 0-10 ppm) 
is necessary to measure the gas-fired emissions, in order to meet the 
section 2.1 guideline. A second issue is that under appendix A, section 
2.1, for dual-span units with add-on emission controls, SO2 or 
NO<INF>X</INF> data recorded on the high monitor range are exempted 
from meeting the 20 to 80 percent guideline. However, this exemption is 
not appropriate for units with seasonally operated emission controls.
    Discussion of Proposed Changes. To address the first issue 
described above, the proposed rule would clearly state that for dual-
span units low-range readings below 20 percent of full-scale are 
exempted from the 20 to 80 percent guideline, provided that the maximum 
expected concentration (MEC) and the low-scale span and range values 
have been determined according to the applicable provisions of appendix 
A. In the example cited in the Background section above, if the low 
measurement range of 25 ppm (based on oil-burning) was properly set 
according to section 2.1.2.3 of appendix A, then re-ranging the low 
measurement scale would not be appropriate, even if the majority of the 
data do not fall between 20 and 80 percent of the range when natural 
gas is combusted. This is because the unit is capable of burning oil, 
and a low-scale range of 25 ppm, if set according to section 2.1.2.3 of 
appendix A, is a good choice for that fuel. Nor would it be necessary 
to establish a third monitoring range. Part 75 was never intended to 
require more than two monitoring ranges.
    To address the second issue described above, the proposed rule 
would require units that operate their emission controls seasonally to 
meet the 20 to 80 percent guideline on the high measurement range. The 
Agency believes it is appropriate for units using their emission 
controls seasonally (such as a unit that uses SCR during the summer 
only) to meet the 20 to 80 percent guideline on the high range because 
emissions data will be recorded on that range for extended periods of 
time during the year. This is unlike the case in which controls are 
used year-round, where the source is likely to operate without the 
controls only on occasion and relatively few readings are recorded on 
the high scale.
2. Will EPA Allow Use of Two Separate CEM Systems With Separate Probes 
and Sample Interfaces To Meet Dual-Range Requirements?
    Background. For units required to have two spans and ranges for 
NO<INF>X</INF> or SO2, the current rule disallows the use of two 
separate CEM systems with separate probes and sample interfaces. This 
option was excluded because dual-span units often use add-on controls 
and have very low emissions. In many cases, the add-on controls are 
used year-round, so the emissions remain low virtually all the time. 
The low emission levels can make it difficult to perform and pass a 
RATA on the high range. Despite this, EPA has received two petitions 
requesting permission to use separate systems with separate probes and 
interfaces to meet a dual-range requirement (see Docket A-2000-33; 
Items II-C-1 and II-D-13). To date, one of these petitions has been 
approved, for a unit that operates its NO<INF>X</INF> controls 
seasonally.
    Discussion of Proposed Changes. Today's proposal would revise 
appendix A, section 2.1 to conditionally allow the use of separate CEMS 
with separate probes and interfaces to satisfy dual-range requirements. 
The condition is that RATAs of both ranges must be performed and 
passed. The revised rule would also state that the two CEMS should be 
designated as separate monitoring systems in the monitoring plan.
3. What Changes Would the Proposed Rule Make With Regard to Determining 
NO<INF>X</INF> MPC, MEC, Span, and Range?
    Background. EPA receives many questions about the way in which the 
MPC, MEC, span, and range are determined for NO<INF>X</INF>, especially 
for new combustion turbines. Some of the questioners have requested 
additional options for MPC and MEC determinations and claim that the 
rule does not address dry, low-NO<INF>X</INF> control technology, which 
is being used on many new turbines. Others have questioned the 
appropriateness of the 50 ppm default value for the MPC of new turbines 
in Table 2-2 of appendix A.
    Discussion of Proposed Changes. The proposed rule would clarify the 
definition of MPC for NO<INF>X</INF>, making a distinction between 
uncontrolled units and units with low NO<INF>X</INF> burner technology. 
The proposal would also revise appendix A, section 2.1 to add a new 
option for NO<INF>X</INF> MPC determination: use of a reliable estimate 
of the unit's uncontrolled emissions obtained from the manufacturer. A 
new option for MEC would also be added: use of the federally-
enforceable permit limit. The new MEC option could only be used for 
units that have add-on emission controls or that use dry, low-
NO<INF>X</INF> technology.
    The 50 ppm default MPC value for new turbines in Table 2-2 would be 
removed and replaced with two new values: (a) 150 ppm for units that 
are permitted to fire only natural gas; and (b) 200 ppm for units 
permitted to fire both gas and oil. These values are much more 
representative of actual NO<INF>X</INF> emissions from turbines during 
unit startup and periods when the emission controls are not 
operational. EPA requests comment on whether the new values are 
representative (see Docket A-2000-33, Item II-B-2).
    Finally, default MPC values would be added to the rule for two 
categories of non-load-based units: cement kilns and process heaters. 
As discussed in more detail under section III.C of this preamble, 
certain States are likely to require these two source categories to 
report NO<INF>X</INF> mass emissions under the NO<INF>X</INF> SIP call. 
For cement kilns, an MPC value of 2,000 ppm is proposed; for process 
heaters, an MPC value of 200 ppm is proposed for gas-fired units, and 
500 ppm for oil-fired heaters. The default MPC value for cement kilns 
was determined using NO<INF>X</INF> emissions data sent to EPA during 
pre-proposal discussions between the Agency, representatives of cement 
kilns located in New York, and the Portland Cement Association. 
NO<INF>X</INF> emissions data for seven cement kilns were submitted for 
review. The data represented more than one year of hourly 
NO<INF>X</INF> concentration values for each of the kilns. EPA selected 
2,000 ppm as an appropriate MPC for cement kilns based on the maximum 
values reported for these units (see Docket A-2000-33, Item II-I-3). 
For process heaters, the Agency evaluated NO<INF>X</INF> emissions data 
submitted in quarterly EDR reports for six process heater units 
regulated under the OTC NO<INF>X</INF> Budget Program. EPA selected the 
200 and 500 ppm MPC values based on the maximum NO<INF>X</INF> 
concentration values reported for these units (see Docket A-2000-33, 
Item II-I-3). EPA is proposing the default NO<INF>X</INF>

[[Page 31990]]

MPC values for cement kilns and process heaters principally because an 
MPC value would be required in the initial monitoring plan submittal if 
these units were to become regulated under the NO<INF>X</INF> SIP call. 
None of the default NO<INF>X</INF> MPC values in appendix A, section 
2.1.2.1 of the current rule are considered to be appropriate for either 
cement kilns or process heaters, and emission test results or 
historical CEMS data might not be available at the time of initial 
monitoring plan submittals from these sources. Therefore, EPA has 
proposed default NO<INF>X</INF> MPC values that can be used for the 
initial MPC determinations for cement kilns and process heaters.
4. What Revisions Would Be Made to the 7-day Calibration Error Test for 
Peaking Units?
    Background. For gas monitors, the 7-day calibration error test is 
required only for initial certification, recertification, and 
occasionally as a diagnostic test. It is not a routine, required 
periodic QA test. The current rule specifies that the 7-day calibration 
error test data must be recorded while the unit is operating. For 
peaking units, the requirement for the unit to be operating during the 
test can be problematic. Because of the infrequent and unpredictable 
nature of peaking unit operation, the 7-day test may take weeks or even 
months to complete.
    Discussion of Proposed Changes. Today's proposal would revise the 
7-day calibration error test requirement for gas monitors installed on 
peaking units in appendix A, section 6.3.1, to require data to be 
recorded for only three of the seven test days with the unit operating. 
The unit would not be required to operate for the other four days of 
the test.
5. What Changes Would Be Made to QA/QC for Units With Very low 
NO<INF>X</INF> Concentrations?
    Background. The current rule requires owners and operators of units 
with very low SO2 and NO<INF>X</INF> concentrations to perform RATAs 
and daily calibrations on their CEMS. They are required to perform 
linearity checks unless the span value is 30 ppm or less (see appendix 
A, section 6.2). Appendix B to part 75 provides an alternate daily 
calibration specification for low emitters of SO<INF>2</INF> and 
NO<INF>X</INF>.
    With respect to the daily calibrations of SO<INF>2</INF> and 
NO<INF>X</INF> monitors, the allowable calibration error is currently 5 
percent of the span value. However, appendix B to part 75 provides an 
alternate daily calibration specification for low emitters of SO<INF>2</INF> 
and NO<INF>X</INF>. The alternative specification for units with low 
concentrations (for span values less than 200 ppm) is 10 ppm or less 
(based on the absolute value of the difference between the tag value of 
the calibration gas and the instrument response). For most low-emitting 
sources, the alternate 10 ppm specification is reasonable and provides 
relief from the 5 percent of span requirement, which is often too 
stringent at low span values. However, for very low span values, the 10 
ppm alternate specification is not stringent enough and needs to be 
tightened. This is especially important because many of the new Acid 
Rain-affected gas turbines that are being built have very low 
NO<INF>X</INF> emissions. To illustrate, suppose that for a very low 
span value of 10 ppm, the upscale calibration gas for daily 
calibrations is 9 ppm. When the 10 ppm alternate calibration error 
specification is applied, the monitor could actually be inoperative, 
read 0 ppm, and the calibration would still be passed.
    Discussion of Proposed Changes. Today's proposal would modify the 
alternate calibration error specification in section 2.1.4(a) of 
appendix B, for daily operation of SO<INF>2</INF> and NO<INF>X</INF> 
monitors. The 10 ppm alternate specification would be retained for span 
values greater than 50 ppm but less than 200 ppm. For span values less 
than or equal to 50 ppm, the alternate specification would be lowered 
to 5 ppm. EPA believes that a daily calibration error limit of 5 ppm is 
both reasonable and achievable, in view of the measurement capability 
of today's gas analyzers. The Agency notes that 5 ppm is also the 
alternate low-emitter performance specification in section 3.1(b) of 
appendix A, for initial certification of SO<INF>2</INF> and 
NO<INF>X</INF> monitors.
6. When Would EPA Require the Application of a Calibration Correction 
Factor to Linearity or RATA Test Data?
    Background. After a routine daily calibration error test, many Data 
Acquisition and Handling Systems (DAHSs) apply a mathematical 
correction to the subsequent emission data in order to account for the 
calibration error. When a linearity check or RATA is initiated after a 
daily calibration, the current rule does not specify whether the 
mathematical correction factor should be applied to the monitor 
readings recorded during the linearity test or RATA.
    Discussion of Proposed Changes. EPA proposes to add language to 
sections 2.2.3(c) and 2.3.2(c) of appendix B, requiring that if a 
mathematical correction factor (calibration adjustment) is applied by 
the DAHS following a daily calibration error test, the correction 
factor would be applied to all subsequent data recorded by the monitor 
until the next calibration error test is performed, including any 
linearity test or RATA data recorded in that time interval.
7. What Changes Would Be Made to the Flow-to-Load Ratio Test?
    Background. In the May 26, 1999, revisions to part 75, a new 
quarterly QA test for flow monitors was promulgated: the flow-to-load 
ratio test. Since promulgation, EPA has received many questions about 
the methodology, relating both to the procedural aspects of how the 
data analysis is done and to the consequences when the test is failed. 
As a result, EPA believes it is necessary to clarify the test 
procedures and to re-evaluate the issue of data validation when the 
test is failed.
    Discussion of Proposed Changes. The proposed rule would allow you 
to take the data exclusions listed in section 2.2.5(c) of appendix B 
before analyzing the quarterly flow-to-load data. The current rule 
appears to require an initial data analysis with no exclusions and to 
allow owners and operators to claim the data exclusions only when the 
first analysis results in a failed test. Proposed section 2.2.5(c) also 
clarifies the issue of co-firing as it pertains to data exclusions. For 
units that co-fire different fuels as part of their normal operation, 
you could claim flow-to-load test data exclusions for hours in which 
fuels were not co-fired if the reference flow RATA at normal load was 
done while co-firing. Conversely, if the reference flow RATA was done 
while firing a single fuel, flow-to-load test data exclusions could be 
claimed for hours in which fuels were co-fired. The proposed rule would 
also add a statement to section 6.5(a) of appendix A requiring that 
units which co-fire fuels as the predominant mode of operation perform 
RATAs while co-firing.
    The proposal would change the method of data validation following a 
flow-to-load ratio test failure. Section 2.2.5(c)(8) of appendix B 
would allow the flow rate data to be declared conditionally valid, 
rather than invalid, when a flow-to-load test is failed, pending the 
results of a follow-up investigation and/or a RATA. This would allow 
data validation in case a false positive is obtained with the flow-to-
load test. If the investigation fails to reveal a problem and a 
confirming RATA is passed hands-off, no data loss would be incurred. 
The timeline for investigating a flow-to-load test failure would also 
be changed from ``within 2

[[Page 31991]]

weeks'' to ``within 14 unit operating days.''
    The proposal would clarify the instructions for multiple stack 
configurations and allow you to do the data analysis in one of two 
ways: (1) Using combined flow and average unit load; or (2) using the 
flow in each stack and the corresponding unit load.
    Finally, section 7.8 in appendix A of part 75 would be revised to 
exempt non-load-based units (i.e., units that do not produce electrical 
output or steam load) from the flow-to-load ratio test.
8. When Would Three-Load Flow RATAs Be Allowed for Routine Quality 
Assurance?
    Background. The current rule specifies that an annual two-load flow 
RATA is required for routine quality assurance of a flow monitor. The 
rule appears to require two-load testing and to disallow three-load 
tests for routine QA.
    Discussion of Proposed Changes. Today's proposal would clarify in 
section 2.3.1.3(c) of appendix B that you may perform a three-load RATA 
in lieu of any required two-load flow RATA.
9. What Changes Would Be Made to the Data Analysis Time Period for 
Single-Load Flow RATA Claims?
    Background. In the May 26, 1999 revisions to part 75, a new 
provision was promulgated, allowing annual flow RATAs to be done at a 
single load level. To qualify for the single-load option the source 
must have operated at one load level (low, mid, or high) for at least 
85% of the time since the last annual flow RATA. A historical load 
analysis must be done to confirm this, extending from the date and hour 
of completion of the last annual flow RATA to a date no less than seven 
days prior to the date of the current annual flow RATA. Some utilities 
have asked if EPA would consider changing this timeline. Two 
suggestions have been offered: (1) Make the end date of the analysis 21 
days ahead of the scheduled RATA date; and (2) include in the analysis 
all data from the quarter of the last RATA and exclude all data from 
the quarter of the current RATA.
    Discussion of Proposed Changes. EPA believes that the suggested 
revisions are appropriate and would increase the amount of time 
available to conduct test planning. The proposal would modify the 
timeline for the data analysis in section 2.3.1.3(c) of appendix B, to 
allow data to be analyzed from either: (a) The date/hour of the last 
annual flow RATA to a date no more than 21 days prior to the current 
flow RATA; or (b) the beginning of the quarter in which the last annual 
flow RATA was done, through the end of the calendar quarter preceding 
the quarter of this year's annual flow RATA.
10. For Units That Do Not Produce Electrical Output or Steam Load, at 
What Operating Levels Should Gas and Flow Monitor RATAs Be Performed?
    Background. For units that do not produce electrical or thermal 
output (e.g., cement kilns and process heaters), today's proposed rule 
would provide a method by which to establish the proper ``operating 
levels'' (as opposed to ``load levels'') at which to perform relative 
accuracy test audits (RATAs). The proposed methodology is found in 
section 6.5.2.1 of appendix A. The rationale for, and a discussion of, 
these proposed rule provisions is presented in the following 
paragraphs.
    Units subject to the monitoring and reporting requirements of part 
75 must account for their emissions on a continuous basis. Most units 
use continuous emission monitoring systems (CEMS) for this purpose. 
Part 75 requires periodic RATAs of all CEMS to demonstrate that the 
data recorded by the monitoring systems accurately represent the 
SO<INF>2</INF>, NO<INF>X</INF>, and CO<INF>2</INF> emissions from the 
affected unit. RATAs of gas and flow monitors are required for initial 
certification and either semiannually or (if the relative accuracy 
obtained on the previous RATA was <ls-thn-eq> 7.5 percent) annually 
thereafter.
    Section 6.5.1 of appendix A to part 75 requires that RATAs of gas 
monitors be done at the ``normal'' load level. Section 6.5.2 of 
appendix A and section 2.3.1.3 of appendix B specify the load levels 
for flow RATAs. In general, flow monitor RATAs are performed at 
multiple load levels (either two or three), with a few exceptions 
(e.g., for flow monitors installed on peaking units, only single-load 
RATAs are required). For multiple-load flow RATAs, at least one of the 
tested load levels must be the ``normal'' load level.
    The method of establishing the normal load level is found in 
section 6.5.2.1 of appendix A. First, the owner or operator must 
determine the ``range of operation'' for the unit or stack. The range 
of operation extends from the minimum safe, stable load to the maximum 
sustainable load. Next, the range of operation is divided into three 
load levels. The first 30 percent of the range of operation is 
considered to be the ``low'' load level, the next 30 percent of the 
range is the ``mid'' load level, and the remaining 40 percent of the 
range is the ``high'' load level. The ``normal'' load level is 
determined by performing an analysis of at least four quarters of 
representative historical load data. From these data a distribution 
graph, such as a histogram, is constructed showing the percentage of 
the time that each load level has been used historically. The most 
frequently-used load level (low, mid, or high) is automatically 
designated as the normal load level. The owner or operator may opt to 
designate the next most frequently used load level as a second normal 
load. Thus, the appropriate load levels for the required RATAs of the 
gas and flow monitors are established.
    Discussion of Proposed Changes. As previously discussed in section 
III.C of this preamble, EPA anticipates that under the NO<INF>X</INF> 
SIP call, sources such as cement kilns or refinery process heaters, 
which do not produce electrical or thermal output, will become subject 
to the monitoring and reporting requirements of part 75. Consequently, 
these sources will be required to perform periodic RATAs of their gas 
and flow monitors. Because these sources do not produce electrical or 
steam load, the concept of performing ``normal load'' RATAs cannot be 
applied to them. Therefore, an alternative RATA approach is needed for 
these non-load-based units. Today's proposed rule would revise section 
6.5.2.1 of appendix A to provide the necessary alternative methodology.
    The proposed RATA approach for units that do not produce electrical 
or steam load would be based on an ``operating level'' concept, rather 
than a ``load level'' concept. The method of determining the normal 
operating level for a non-load-based unit would be much the same as the 
previously-described method for determining the normal load level for a 
load-based unit. The owner or operator would determine the range of 
operation, divide it into three operating levels, and perform a data 
analysis to establish the ``normal'' (i.e., most frequently-used) 
operating level. The only significant difference between the load-based 
and non-load-based methodologies is that instead of defining the range 
of operation in units of electrical or steam load (i.e., in megawatts 
or klb/hr of steam), the range of operation of the non-load-based unit 
would be defined in units of stack gas velocity, in ft/sec. The range 
of operation would extend from the minimum expected velocity to the 
maximum potential velocity. These minimum and maximum gas velocities 
could either be determined from reference method test data or by using 
Equation A-3a or A-3b (as applicable) in section 2.1.4.1 of appendix A 
to part 75.

[[Page 31992]]

    EPA is aware that for new or newly-affected units, four quarters of 
historical load data (for load-based units) or flow rate data (for non-
load-based units) may not be initially available to establish the two 
most frequently-used operating loads (or levels) and the normal 
operating load (or level). Also, for a non-load-based unit which is not 
required to install a flow monitor, the necessary flow rate data for 
the determinations will neither be available initially nor at some 
point in the future. Therefore, a revision to section 6.5.2.1 (c) of 
appendix A is proposed, which would allow the initial determinations to 
be made as follows: (1) For load-based units or for non-load-based 
units with installed flow monitors, the determinations could be based 
on less than four quarters of data, or, if no representative historical 
data are available, projections of how the unit will be operated could 
be used. Note, however, that as soon as four representative quarters of 
load or flow rate data are obtained, the determination of the two most 
frequently-used operating loads (or levels) and the normal operating 
load(s) (or level(s)) would have to be repeated; or (2) for non-load-
based units without installed flow monitors, sound engineering judgment 
(based on a combination of knowledge of the unit, operating experience, 
and actual stack gas velocity measurements using EPA Method 2) would be 
used to make the operating level determinations.
    Once the boundaries of the range of operation are established and 
the normal operating level(s) has been identified, the owner or 
operator of a non-load-based unit would perform the required gas and 
flow RATAs in essentially the same manner as for a load-based unit. The 
only difference is that in many sections of part 75 the term 
``operating level'' would replace the term ``load'' or ``load level.'' 
Today's proposed rule would modify the text in several sections of part 
75 (e.g., by adding a parenthetical expression such as ``(or normal 
operating level)'' after the term ``normal load''), to indicate that 
the provisions apply to both load-based and non-load-based units. The 
affected rule sections are: Sec. 75.20(c)(2), sections 6.5.1, 6.5.2, 
6.5.6.1(a), and 6.5.6.2(a) of appendix A, and sections 2.3.1.3, 
2.3.2(d), 2.3.2(f), 2.4(b), and Figure 1 of appendix B.

G. Streamlining Changes

    Background. There are a number of rule sections in part 75 that 
have expired, either on December 31, 1999, or on March 31, 2000. For 
some, but not all, of these expired rule provisions, part 75 contains 
new (replacement) provisions, having effective dates of January 1, 
2000, or April 1, 2000, respectively. The expired provisions are a 
potential source of confusion to both the regulated community and to 
regulators in assessing compliance with part 75. For instance, the rule 
contains two sets of recordkeeping and reporting provisions, one of 
which expired on March 31, 2000, and the other which became effective 
on April 1, 2000. Removing the expired sections would greatly 
facilitate part 75 implementation and compliance.
    EPA notes that the removal of expired provisions will not change 
the fact that those provisions were in effect up to their respective 
expiration dates. EPA intends to take appropriate enforcement action 
against violations of those provisions that occurred before the time of 
expiration.
    Discussion of Proposed Changes. Today's proposed changes would 
streamline part 75 by eliminating outdated language in the rule and by 
removing a number of references throughout part 75 to sections of the 
rule that are no longer effective. This streamlining would occur in 
several places in the rule.
    The May 26, 1999 revisions to part 75 became effective on June 25, 
1999. However, the regulatory language in certain sections of the rule 
specified that compliance with those sections would not be required 
until a later date, April 1, 2000. The reason for the later effective 
date of certain provisions was to allow adequate time for development 
of the necessary reporting software associated with the rule changes. 
For instance, on May 26, 1999, revised recordkeeping and reporting 
sections were added to the rule as new Secs. 75.57, 75.58, and 75.59, 
to replace the previous recordkeeping and reporting Secs. 75.54, 75.55, 
and 75.56, as of April 1, 2000. However, due to the April 1, 2000 
effective date of the new sections, the old sections could not be 
deleted from part 75, because this would have left a regulatory gap 
extending from June 25, 1999 (the effective date of the May 26, 1999 
revisions) until April 1, 2000, during which there would have been no 
part 75 recordkeeping and reporting requirements in effect. So, the old 
sections were left in the rule and language was added to them to 
indicate that they were in effect only until April 1, 2000, and could 
no longer be used on and after that date.
    Other rule sections with April 1, 2000 expiration dates and 
effective dates include the monitoring plan provisions (Sec. 75.53, 
paragraphs (e) and (f) replaced Sec. 75.53, paragraphs (c) and (d) on 
April 1, 2000) and the CO<INF>2</INF> missing data provisions 
(Sec. 75.35, paragraphs (b) and (d) replaced Sec. 75.35(c) on April 1, 
2000). Today's proposal would remove from part 75 all of the rule 
sections that expired on April 1, 2000, and all textual references to 
those sections.
    Rule sections that only applied to Phase I units and are now 
inapplicable and textual references to those sections would also be 
removed by today's proposal. For example, the 15 percent relative 
accuracy specification for flow monitors expired at the end of Phase I 
(on December 31, 1999) and was replaced on January 1, 2000, by the 
current 10 percent standard. Today's proposed rule would revise 
appendix A, section 3.3.4; appendix B, sections 2.3.1.2(b) and (c), and 
Figure 2 of appendix B, to reflect this.
    EPA has prepared a technical support document (see Docket A-2000-
33, Item II-A-2) that identifies in tabular form each of the 
streamlining revisions in the proposed revisions to part 75.

H. Monitoring Plan Information Submittal

1. What Changes Are Proposed in the Timeline for Monitoring Plan 
Updates?
    Background. In several places part 75 requires the monitoring plan 
to be updated following a particular change or event (such as a span 
adjustment). For example, Sec. 75.62(a)(2) requires submittal of 
updated hardcopy portions of the monitoring plan within 30 days of the 
event associated with a change. However, for events that require 
updating of the electronic monitoring plan, in many cases no similar 
deadline for submitting the changes is specified in part 75.
    Discussion of Proposed Changes. Today's proposed rule would add 
parallel requirements to Secs. 75.62(a)(1) and 75.73(e) for electronic 
monitoring plan updates. It would require the updated electronic 
monitoring plan to be submitted within 30 days of the event associated 
with a change, unless otherwise specified in part 75.
2. Is EPA Changing the Process for Electronic Submittal of Monitoring 
Plan Updates and Certification/Recertification Test Results?
    Background. The current rule requires that you submit the complete, 
up-to-date electronic monitoring plan to EPA at least 45 days prior to 
initial certification, with each certification or recertification 
application, and in each quarterly report. The rule also requires an 
electronic version of the test results of all monitor certifications 
and recertifications to be submitted to EPA.

[[Page 31993]]

To best handle the data, EPA has decided to develop a consistent 
process for transmitting and receiving the information.
    Discussion of Proposed Changes. Today's proposal would add language 
to Secs. 75.62(a)(1), 75.63(c), and 75.73(e)(1), requiring monitoring 
plan updates and certification or recertification data to be submitted 
electronically by a method specified by EPA. The Agency's goal is to 
develop a process by which the required electronic monitoring plan 
information and test data could be submitted at any time and the 
database would be automatically updated. Until the final goal is 
achieved, EPA may use short-term, interim methods, such as email, to 
receive the information. The language in today's proposed rule, ``* * * 
by a method specified by the Administrator,'' is sufficiently general 
to allow the use of such interim methods until the goal is reached.

I. Appendix D--Miscellaneous Issues

    Background. In addition to the revisions of the definitions of 
pipeline natural gas and natural gas described above in section C of 
this preamble, EPA believes that there are a number of other changes 
and clarifications that would improve implementation of the excepted 
method allowed under appendix D to part 75.
    Discussion of Proposed Changes. The proposed rule would modify 
section 2.1.2 of appendix D, as follows. EPA proposes to relax the 
restriction in section 2.1.2 which prohibits units using the provisions 
of subpart H of part 75 to monitor and report NO<INF>X</INF> mass 
emissions (i.e., units subject to a State or federal NO<INF>X</INF> 
emission reduction program) from apportioning the measured hourly heat 
input at a common pipe to the individual units served by the pipe. For 
subpart H units, revised section 2.1.2 would conditionally allow 
apportionment of the common pipe heat input, provided that: (1) All of 
the units served by the common pipe are affected units; and (2) all of 
the units served by the pipe have similar efficiencies (i.e., they are 
all boilers or all combustion turbines). Section 2.1.2 would be further 
revised by removing the text from subsection 2.1.2.2 which describes a 
petition process for obtaining permission to apportion SO<INF>2</INF> 
emissions to the individual units served by a common pipe. This 
petition process is considered to be superfluous, because section 2.1.2 
assumes that a certified appendix D fuel flowmeter has been installed 
on the common pipe. For SO<INF>2</INF> emissions accounting purposes, 
it is sufficient to report the combined SO<INF>2</INF> emissions for 
the units served by the common pipe, based on fuel flow rate 
measurements made at the pipe. Thus, revised section 2.1.2 would simply 
state that if you install a fuel flowmeter on a common pipe, you should 
report combined SO<INF>2</INF> emissions from the units served by the 
pipe and you should apportion the common pipe heat input to the 
individual units using the appropriate equation from appendix F to part 
75 (e.g., Equation F-21a or F-21b).
    The proposed rule would revise section 2.1.4.1 of appendix D to 
exempt oil-fired units that use a different grade of oil only for unit 
startup from using a certified fuel flowmeter. This exemption parallels 
the existing exemption for oil-fired units that use gas fuel only for 
unit startup.
    The proposed rule would also revise section 2.1.4.3 of appendix D 
to clarify the reporting requirements when emergency fuel is burned. 
The owner or operator would have the option during emergency fuel 
combustion to either: (1) Use and report maximum potential values for 
heat input rate, fuel sulfur content, GCV, and density; or (2) to use 
measured values if a certified fuel flowmeter is installed for the 
emergency fuel and/or if fuel sampling and analysis of the fuel is 
performed.
    For temperature transmitter calibrations, EPA would revise section 
2.1.6.1(a) of appendix D to allow fixed reference points (such as the 
freezing point or boiling point of water) to be used for the zero and 
upscale calibrations.
    For a subpart H unit for which you report data only during the 
ozone season and for which you use an orifice, nozzle, or venturi-type 
appendix D fuel flowmeter to determine heat input rate, the proposal 
would clarify that the owner or operator still would have to use all 
calendar quarters in the year to determine the deadline for the next 
visual inspection of the primary element (see Sec. 75.74(c)(4)). This 
clarification is appropriate because the 12 calendar quarter time 
interval for conducting these visual inspections is not dependent on 
the reporting schedule.
    For the optional fuel flow-to-load ratio test in section 2.1.7, 
minor errors in the instructions for common pipe and multiple pipe 
configurations would be corrected. Also, for the optional fuel flow-to-
load ratio test, the proposal would allow data exclusions to be taken 
before analyzing the data. The current rule appears to require an 
initial data analysis with no exclusions, and allows the data 
exclusions to be claimed only when the first analysis results in a 
failed test. This was not the original intent when EPA adopted this 
provision.
    For units using the fuel flow-to-load ratio test to extend the fuel 
flowmeter accuracy test deadline, the proposal would clarify the 
various reasons for which owners or operators could claim a one-quarter 
extension of the fuel flowmeter accuracy test deadline.
    Today's proposal would clarify in Tables D-4, D-5, and elsewhere in 
the text that owners and operators could not continue to use an assumed 
sulfur content or GCV value, such as a contract specification or the 
maximum value from the previous year, if a sampled value exceeded the 
assumed value. In these circumstances the sampled value would become 
the new assumed value.
    Guidelines would be added to section 2.3.2.1.2, explaining how to 
apply the results of periodic sulfur and GCV samples. Owners and 
operators would have to begin using the new values as of the date when 
the sample results were received (not retroactively to the date the 
sample was taken).
    A clarification would be added that the demonstrations of sulfur 
content and GCV variability described in sections 2.3.5 and 2.3.6 are 
options, not requirements, for units that combust other gaseous fuels 
(fuels that do not qualify as either pipeline natural gas or natural 
gas) and choose not to perform daily GCV sampling and hourly fuel 
sulfur content sampling, respectively. Also, these sections would be 
revised to make clear that, as stated in sections 2.3.1.4 and 2.3.2.4, 
the 720-hour demonstration methodology may be used to demonstrate that 
a particular fuel meets the appropriate GCV and/or sulfur content 
requirements to qualify as pipeline natural gas or natural gas.
    The missing data requirements for the sulfur content of gaseous 
fuels in Table D-6 would be changed. All of the missing data values 
would be based on the total sulfur content of the gas. For pipeline 
natural gas, a missing data value of 0.002 lb/mmBtu is proposed. For 
natural gas, the missing data value would be an emission rate (in lb/
mmBtu) calculated from Equation D-1h, using the lesser of: (a) The 
maximum total sulfur content specified in the fuel contract; or (b) 1.5 
times the highest total sulfur value from the previous year's samples. 
For gaseous fuels sampled daily, the substitute data value would be 1.5 
times the highest total sulfur content obtained in the previous 30 
daily samples. For gaseous fuels sampled hourly, the missing data value 
would be the highest total sulfur content from the previous 720 hourly 
samples. The reason for selecting the 0.002 lb/mmBtu value for pipeline 
natural gas (which exceeds the lb/mmBtu equivalent of the 0.5 gr/100 
scf total

[[Page 31994]]

sulfur limit in the definition of pipeline natural gas) and for using 
the 1.5 multipliers is to ensure that the missing data values will be 
higher than the values normally used in the calculations from Table D-
5.
    Equations D-10 and D-11 would be removed from section 3.4.3(b). 
These equations are not needed because they are redundant with 
equations F-21a and F-21b in appendix F. A new equation, D-15a, which 
gives the unit heat input rate when multiple fuels are burned during 
the hour, would be added to section 3.5.4.
    Sections 2.3.1.4(b) and 2.3.2.4(b) of appendix D would be revised 
to require initial and periodic sampling of pipeline natural gas and 
natural gas for documenting the total sulfur content of fuel. The 
proposed sampling frequency is semiannual and whenever ``it is 
reasonable to believe that the fuel composition has changed 
significantly.'' EPA solicits comment on the acceptability of this 
rather subjective ``reasonability'' criterion for determining when an 
additional sample is required. For compliance purposes, more precise 
language such as, ``Take an additional sample whenever there is any 
change to the contract or fuel supply to the unit, such that the latest 
sample is no longer representative of the fuel currently being 
combusted,'' may be more appropriate.
    For fuels that qualify as pipeline natural gas, the 0.0006 lb/mmBtu 
default SO<INF>2</INF> emission rate would continue to be used. For 
natural gas, revised Equation D-1h would be used to calculate the 
SO<INF>2</INF> emission rate, based on the total sulfur content 
sampling results.
    Two new sections, 2.3.1.4(c) and 2.3.2.4(c), would be added to 
appendix D, to state that if the results of periodic sampling show 
exceedances of the applicable total sulfur limits, the fuel would have 
to be reclassified.
    Finally, as previously noted under section III.C.3 of this 
preamble, fuel flow rate missing data provisions for non-load-based 
units (such as cement kilns and process heaters) would be added to 
section 2.4 of appendix D. Guidelines for creating and using optional 
``operational bins'' for determining appropriate fuel flow rate missing 
data values for non-load-based units would be added to appendix C of 
part 75, as new section 4.

J. Reporting and Recordkeeping

1. Will Certification and Recertification Test Notice Requirements 
Change?
    Background. For initial certifications, the current rule requires 
at least 45 days notice before the first date of scheduled testing. For 
recertifications, 45 days of advance notice is required when all 
recertification tests are required (full recertification), but only 7 
days notice is required when all of the tests are not required (partial 
recertification). This raises two questions: (1) Whether the 
notification requirements should be the same for both certifications 
and recertifications; and (2) how much advance notice is actually 
needed.
    Discussion of Proposed Changes. The proposed rule changes would 
revise Secs. 75.20 and 75.61 to make a single notification requirement 
of 21 days for initial certifications and for all recertifications, 
regardless of whether all of the tests are required. Based on the 
experience to date in implementing part 75, EPA believes the existing 
seven day notice provides too little time for State and local agency 
personnel and EPA personnel to schedule site visits to observe the 
recertification testing. Conversely, the Agency believes that 45 days 
notice is too far in advance, especially for recertifications. Test 
observation is a critical component of agency oversight of the Acid 
Rain Program monitoring requirements, and the 21 day test notification 
requirement would ensure that the agencies can successfully fulfill 
this responsibility.
2. Will EPA Continue to Accept Hardcopy Certification Statements?
    Background. The current rule allows either electronic or hardcopy 
signatures and certification statements for quarterly report 
submittals. This creates unnecessary extra work for the EPA analysts 
who must document the receipt of all compliance certifications.
    Discussion of Proposed Changes. Today's proposal would revise 
Sec. 75.64(d) to eliminate the option to submit hardcopy compliance 
certifications and would, instead, require electronic submittal. 
Because of the electronic reporting requirements for all other 
quarterly report elements, all designated representatives will have the 
technical capability to submit electronic certifications. This rule 
change should therefore reduce the reporting burdens on both the 
regulated entities and EPA staff.
3. Will EPA Allow the Electronic Storage of Quality Assurance/Quality 
Control Plan Information?
    Background. Section 1 of appendix B requires you to develop a 
quality assurance/quality control (QA/QC) program for all approved 
monitoring systems at a facility. The QA/QC program must include a 
written plan that provides detailed procedures and operations for 
certain activities, such as preventive maintenance and quality 
assurance test procedures. You must make this information and any 
ancillary supporting information from the monitor manufacturer (for 
example, maintenance manuals) available to auditors upon request. EPA 
has received a request from one utility to allow the QA/QC plan 
information to be stored electronically rather than in hardcopy.
    Discussion of Proposed Changes. Today's proposal would revise 
appendix B, section 1, to allow QA/QC plan information to be stored 
electronically, provided that the information can be made available in 
hardcopy to inspectors or auditors upon request. Part 75 already allows 
electronic storage of hardcopy monitoring plan information, if the 
information can be furnished in hardcopy upon request during an audit 
(see Sec. 75.53(e)). The proposed rule revision would use an approach 
for QA/QC plans that is consistent with this existing monitoring plan 
provision.

K. NO<INF>X</INF> Monitoring in Multiple Stacks/Common Stacks

    Background. For an exhaust configuration consisting of a main stack 
and a bypass stack, if the use of the bypass stack is limited by 
regulation or permit to emergency malfunctions of the flue gas 
desulfurization system, Sec. 75.16 of the current rule allows the 
maximum potential SO<INF>2</INF> concentration to be reported during 
the malfunction in lieu of installing monitors on the bypass stack. For 
NO<INF>X</INF>, however, the rule has no corresponding provision. 
Rather, it appears that monitoring of the bypass stack or monitoring of 
the duct(s) leading to the bypass stack are the only available options. 
Also, the current multiple stack and bypass stack provisions for 
NO<INF>X</INF> (see Secs. 75.17(c) and 75.72, paragraphs (c) and (d)) 
are not particularly clear or consistent.
    Discussion of Proposed Changes. EPA would clarify and expand the 
instructions for SO<INF>2</INF> and NO<INF>X</INF> monitoring in 
multiple and bypass stacks in Secs. 75.16(c) and 75.17(c), and in 
Sec. 75.72, paragraphs (c) and (d) in this proposal. EPA would also add 
a new provision to Secs. 75.17(c) and 75.72(c), for configurations 
consisting of a main stack and a bypass stack, that allows the maximum 
potential NO<INF>X</INF> emission rate to be reported when the bypass 
stack is used. Instructions would also be provided for reporting other 
parameters (i.e., SO<INF>2</INF>, CO<INF>2</INF>, flow rate, moisture, 
heat input rate) during hours when the bypass stack is used.
    Today's proposed rule would revise the language in Sec. 75.16(c)(3) 
which

[[Page 31995]]

restricts the reporting of the maximum potential SO<INF>2</INF> 
concentration (MPC) to emergency situations in which the flue gas 
desulfurization (FGD) system is bypassed. Today's rule would allow the 
MPC to be reported in lieu of monitoring at the bypass stack, provided 
that the use of the bypass stack is limited to unit startups, emergency 
situations, and routine maintenance of the FGD system and the main 
stack. Instructions would also be provided for reporting other 
parameters (i.e., NO<INF>X</INF> , CO<INF>2</INF>, flow rate, moisture, 
heat input rate) during hours when the bypass stack is used.

L. Appendix E Issues

1. How Will the Proposed Rule Affect Appendix E Test Notifications and 
Submittal of Hardcopy Recertification Test Results?
    Background. For routine appendix E retests and recertification 
testing, the rule is currently unclear regarding the test notification 
requirements and submittal of the hardcopy test results.
    Discussion of Proposed Changes. The proposal would add a 
requirement to Sec. 75.61(a)(5) to provide notice of routine appendix E 
retesting at least 21 days prior to the start of the testing. It would 
also add a requirement to Sec. 75.61(a)(1)(ii) to provide notice of 
appendix E recertification testing. Finally, the proposed rule would 
add a requirement to Secs. 75.60(b) and 75.73(d) to submit the results 
of routine appendix E retest results in hardcopy to the appropriate 
Region and State, upon request. This is exactly analogous to the 
requirement in Secs. 75.60(b)(6) and 75.73(d)(4) to provide hardcopy 
RATA results.
2. Will the Frequency of Retesting of Appendix E Units Be Changed?
    Background. Section 2.2 of appendix E requires periodic retesting 
for quality assurance purposes. The timeline for retesting is every 
3,000 operating hours or the five year anniversary of the operating 
permit, whichever is sooner. These requirements are difficult to 
implement and to track. The permit anniversary date is not a good 
reference point. Also, the rule does not indicate whether the 3,000 
operating hours are fuel-specific.
    Discussion of Proposed Changes. Today's proposal would revise 
appendix E, section 2.2, to require retesting for all fuels, once every 
20 calendar quarters. The quarter of the last test would serve as the 
reference point, similar to the methodology used for setting RATA and 
fuel flowmeter accuracy test deadlines. Fuel-specific missing data 
procedures would be used when a retest is not completed by the 
deadline. For each fuel, the new correlation curve obtained in a retest 
would be used for reporting, beginning with the first operating hour in 
which the fuel is combusted after completion of the retest. This is 
analogous to the part 75 requirement to apply CEMS bias adjustment 
factors beginning with the first operating hour after completion of a 
RATA.
3. How Will the Timeline for Unscheduled Appendix E Retests Be Revised?
    Background. Section 2.3 of appendix E requires retesting within 10 
unit operating days or 180 calendar days (whichever occurs first) 
whenever the monitored operating parameters are exceeded for more than 
16 consecutive hours or the data availability, since the last test, is 
less than 90 percent. For many units, 10 operating days is not a 
sufficient amount of time to schedule a retest and perform the testing.
    Discussion of Proposed Changes. EPA proposes to revise appendix E, 
section 2.3, to change the 10 unit operating day requirement to 30 unit 
operating days. This change would provide sufficient time to schedule 
and perform the tests and to meet the applicable test notification 
requirements.
4. How Will Appendix E Missing Data Procedures Be Changed?
    Background. For missing data purposes, appendix E prescribes that 
the highest NO<INF>X</INF> emission rate from the most recent set of 
baseline correlation tests be reported for each hour of the missing 
data period. There are three situations for which this missing data 
scheme may be inappropriate: (1) When the measured hourly heat input 
rate is higher than the highest heat input rate from the baseline 
correlation tests; (2) for a unit with add-on NO<INF>X</INF> controls, 
if the controls are not in operation or it is not possible to document 
that the controls are operating properly; and (3) when emergency fuel 
is combusted.
    Discussion of Proposed Changes. To address the concerns about 
situations in which the current missing data procedures may be 
inappropriate, the proposed rule would add to section 2.5 of appendix E 
a requirement to calculate a fuel-specific maximum potential 
NO<INF>X</INF> emission rate (MER) for each type of fuel combusted by 
the unit and would add three new sections, 2.5.2.1, 2.5.2.2, and 
2.5.2.3, to require reporting of the fuel-specific NO<INF>X</INF> MER 
for cases (2), and (3), described above. For fuel mixtures, EPA would 
require substitution of the highest MER value for the fuels in the 
mixture.
    For case (1) described above, two reporting options would be 
allowed. Whenever the heat input rate for a given unit operating hour 
exceeds the highest heat input rate from the baseline correlation 
tests, the owner or operator could either: (a) Report the hourly 
NO<INF>X</INF> emission rate as the higher of the linear extrapolation 
of the correlation curve or the fuel-specific MER; or (b) report 1.25 
times the highest NO<INF>X</INF> emission rate on the correlation 
curve, not to exceed the fuel-specific MER. Note that for units with 
NO<INF>X</INF> emission controls, the use of an extrapolated 
NO<INF>X</INF> emission rate under (a), above, and the use of 1.25 
times the highest value on the correlation curve under (b), above, 
would be disallowed, and the MER would have to be reported for any hour 
in which the emission controls could not be documented to be in proper 
operation.
5. How Will the Appendix E Testing Requirements for Emergency Fuel Be 
Changed?
    Background. The current rule allows the designated representative 
for an appendix E unit to petition the Administrator for an exemption 
from appendix E testing for emergency fuel. Many Phase II Acid Rain 
units submitted such petitions with their initial certification 
applications, and the petitions were approved.
    Discussion of Proposed Changes. Today's proposed rule would revise 
section 2.1.4 of appendix E to remove the requirement to petition the 
Administrator to obtain an exemption from appendix E testing for 
emergency fuel. EPA believes that the petition process is unnecessary, 
provided that the unit has a federally enforceable permit which 
restricts the combustion of a particular fuel to emergency situations. 
Therefore, the proposed rule would exempt emergency fuel from appendix 
E testing if the unit has the necessary permit and if documentation is 
provided in the monitoring plan for the unit.

M. Reference Methods

1. Which Code of Federal Regulations Versions of Reference Methods Are 
To Be Used?
    Background. In the May 26, 1999 revisions to part 75, EPA specified 
that only particular versions of Reference Methods 6C, 7E, and 3A (the 
methods used for gas RATAs) be used. Those versions are the 1995, 1996, 
and 1997 Code of Federal Regulations versions of the methods. This 
provision was added

[[Page 31996]]

to the rule because EPA at that time had proposed substantive revisions 
to these methods for the New Source Performance Standards (NSPS) 
Program that were not appropriate for the Acid Rain Program. However, 
the revisions to the reference methods were never finalized, therefore 
the reference to particular versions is no longer needed. Removing the 
caveat will eliminate confusion because these reference methods have 
been basically the same in all versions of the Code of Federal 
Regulations, from 1988 through 1999.
    Discussion of Proposed Changes. Today's proposal would revise 
Sec. 75.22(a) and appendix A, section 6.5.6, to remove from the rule 
all references to the 1995, 1996, and 1997 Code of Federal Regulations 
versions of Reference Methods 6C, 7E, and 3A.
2. Are There Other Changes to Reference Methods?
    Background. Three issues have arisen regarding the part 60 
reference test methods used to certify and quality assure part 75 CEMS. 
First, when measurement of the stack gas moisture content is required 
to determine the stack gas molecular weight, Sec. 75.22(a)(4) allows 
the source to use any of the alternative moisture techniques listed in 
section 1.2 of Method 4. This includes, among other things, ``previous 
experience.'' Second, when an automated version of Method 2 is used for 
flow RATA testing, often all four available sample ports are occupied 
simultaneously with velocity probes which are bolted in place. This can 
make it difficult to obtain a moisture sample once every three runs or 
once every clock hour, as required in section 6.5.7 of appendix A. 
Third, questions have arisen regarding the manner in which 
NO<INF>X</INF> compliance tests and RATAs are performed for combustion 
turbines.
    Discussion of Proposed Changes. Today's proposed rule would revise 
Sec. 75.22(a)(4), to clarify that for purposes of determining the stack 
gas molecular weight during a part 75 flow RATA, the only acceptable 
alternative moisture methodology listed in section 1.2 of Method 4 is 
the wet bulb-dry bulb measurement technique. The other methodologies 
listed (``drying tubes,'' ``condensation techniques,'' ``stoichiometric 
calculations,'' and ``previous experience'') are not defined precisely 
enough to approve their use. In contrast, the wet bulb-dry bulb 
technique is well-established and is generally familiar to emission 
testers.
    Today's proposal would also revise section 6.5.7 of appendix A to 
allow, for purposes of determining stack gas molecular weight during 
part 75 flow RATAs, moisture measurements to be made before and after a 
series of RATA runs at a particular load level (low, mid, or high), in 
lieu of measuring moisture every three runs or once every clock hour, 
as required by the current rule. The results of the before and after 
moisture measurements would be averaged arithmetically, and the average 
value would be applied to all RATA runs in the series. Note, however, 
that this moisture measurement option could only be used if the before 
and after runs were performed no more than three hours apart. Section 
6.5.7 would be further revised by clarifying that sufficient 
measurement time must be allowed at each traverse point of a flow RATA 
to ensure that stable temperature readings are obtained, particularly 
for the first point at which data are taken after a probe is moved from 
one port to the next.
    Finally, today's proposed rule would revise Sec. 75.22 and section 
6.5.10 of appendix A, to allow the use of EPA Method 20, as an 
alternative to Method 7E, for relative accuracy test audits (RATAs) of 
NO<INF>X</INF> monitoring systems installed on combustion turbines. 
Further, the proposed rule would revise section 6.5.6(b) of appendix A, 
to allow the reference method measurement points specified in section 
6.1.2 of Method 20 to be used for a Method 7E RATA of a NO<INF>X</INF> 
monitoring system installed on a combustion turbine. EPA believes these 
added flexibilities will simplify certification and quality assurance 
testing for combustion turbines. The rationale for these two new 
provisions follows.
    Many utilities are constructing new gas turbines. Almost 
invariably, NO<INF>X</INF> monitoring systems will be installed on 
these units. EPA Method 20 is the NO<INF>X</INF> compliance test method 
for new gas turbines, under subpart GG of 40 CFR part 60, the New 
Source Performance Standards (NSPS) for stationary sources. Method 7E 
is the method currently prescribed by part 75 as the reference method 
for NO<INF>X</INF> RATAs. Today's proposed rule would allow Method 20 
data to be used for a dual purpose, that is, as compliance test data 
for NSPS and as reference method test data for the RATA of the part 75 
NO<INF>X</INF> monitoring system. This would make a second reference 
method test using Method 7E unnecessary.
    EPA believes that for a Method 7E RATA of a NO<INF>X</INF> 
monitoring system installed on a combustion turbine, allowing the 
Method 20 sample points to be used as the reference method measurement 
points is potentially beneficial, particularly if the stack or duct 
being tested is rectangular. The provisions in section 3.2 of 
Performance Specification No. 2 (PS No. 2) in appendix B of 40 CFR part 
60 specify the required reference method measurement points for gas 
monitor RATAs. However, section 3.2 of PS No. 2 only addresses the 
point layout for circular stacks. There are no clear guidelines for 
rectangular stacks or ducts. On the other hand, section 6.1.2 of Method 
20 does have a procedure for selecting reference method measurement 
points which applies to both circular and rectangular stacks or ducts.

N. Appendix G Revisions

    Background and Discussion of Proposed Changes. Today's proposed 
rule would revise section 2.3 of appendix G to expand the applicability 
of Equation G-4 to oil-fired units. Currently, section 2.3 restricts 
the use of Equation G-4 to gas-fired units (as defined in Sec. 72.2). 
There is no technical reason to prohibit the use of this equation by 
oil-fired units. Many gas-fired units that currently use Equation G-4 
occasionally combust fuel oil. During the oil-burning hours, Equation 
G-4 is still used to report CO<INF>2</INF> emissions, except that an 
F<INF>C</INF> factor of 1,420 scf/mmBtu (for oil) instead of the usual 
F<INF>C</INF> factor of 1,040 scf/mmBtu for natural gas is used. 
Allowing the use of Equation G-4 for oil-fired units would enable the 
owner or operator to report hourly CO<INF>2</INF> emissions in tons per 
hour, instead of using Equation G-1, which requires CO<INF>2</INF> 
reporting on a tons per day basis. This option would not only simplify 
emission reporting for oil-fired units but would enable EPA to perform 
meaningful electronic audits of the reported CO<INF>2</INF> emissions, 
as the hourly heat input (i.e., the term ``H'' in Equation G-4) is the 
only variable in Equation G-4 and is required to be reported each hour 
in the EDR. However, the cumbersome term W<INF>C</INF> (i.e., lbs of 
carbon burned per day) in Equation G-1 is not reported anywhere in the 
EDR.

O. Technical Changes and Corrections

    Background. An important objective of this proposed rulemaking is 
to make technical changes and corrections to part 75. These changes and 
corrections are necessary to eliminate printing, typographical, and 
grammatical errors, to correct or clarify cross references, and, in a 
few instances, to ensure that the specific rule language is consistent 
with the Agency's intent. None of these technical corrections and 
changes adds new requirements or substantively

[[Page 31997]]

affects the obligations of the entities that must comply with part 75 
requirements.
    The technical changes and corrections fall into several categories. 
In the first category are efforts to rewrite rule provisions to 
increase clarity and to accord with other provisions of part 75. In the 
second category are corrections and clarifications of equations, 
including the definitions of certain variables. The final category of 
technical changes consists of corrections of printing, typographical, 
and grammatical errors. Included in this category are repetitive words 
and phrases, misspelled words, and misplaced punctuation.
    Discussion of Proposed Changes. The technical support document 
(Docket A-2000-33, Item II-A-2) provides a specific description for 
each of these technical changes and corrections.

P. What Other Changes is EPA Proposing to the Federal NO<INF>X</INF> 
Budget Trading Program Today?

    Background and Discussion of Proposed Changes. We are proposing a 
number of minor changes to the Federal NO<INF>X</INF> Budget Trading 
Program in part 97 to correct errors or clarify provisions. For 
example, one proposed change is to correct the definition of ``percent 
monitor data availability'' in Sec. 97.2. This definition is used to 
allow units to qualify for early reduction credits in Sec. 97.43(a)(1) 
or to qualify to use data as a baseline for allowance allocations for 
opt-in units under Sec. 97.84(b). EPA intended to make this definition 
consistent with the term's use in the part 75 monitoring rule, except 
that ``percent monitor data availability'' would apply only for an 
ozone season instead of for a year's worth of data on a rolling basis. 
Some companies have pointed out that the current definition is 
inconsistent because hours when the unit does not operate are still 
used in the calculation. This means that a unit might not be able to 
meet the required 90 percent monitor data availability simply because 
the unit does not operate for many hours during the ozone season. EPA 
is proposing to revise the definition so that it refers to the 
percentage of unit operating hours with valid, quality-assured data 
during an ozone season, rather than the percentage of all 3,672 hours 
during an ozone season.
    As a further example of changes to part 97, the definition of `` 
NO<INF>X</INF> allowance'' in Sec. 97.2 provides that the term includes 
NO<INF>X</INF> allowances from an approved State NO<INF>X</INF> Budget 
Trading Program, except for purposes of certain listed sections 
relating to allocations. Section 97.40, defining the trading program 
budget, is added to that list of sections. In addition, EPA is 
correcting the reference in Sec. 97.42(e)(2) to allowances ``deducted 
under paragraph (c)(1) of this section'' to refer instead to 
``paragraph (e)(1) of this section.'' Other proposed changes to part 97 
are addressed in a technical support document (Technical Support 
Document, Docket A-2000-33, Item II-A-2). EPA believes these minor 
changes may reduce confusion and improve consistency within part 97.
    Finally, EPA is proposing a number of other minor changes to part 
78 to make existing administrative appeal procedures applicable to 
decisions of the Administrator under part 97. The changes to part 78 
are addressed in a technical support document (Technical Support 
Document, Docket A-2000-33, Item II-A-2).

IV. Administrative Requirements

A. Public Hearing

    If requested as specified in the DATES section of this document, a 
public hearing will be held to discuss the proposed regulations. 
Persons wishing to make oral presentations at the public hearing should 
contact EPA at the address given in the ADDRESSES section of this 
document. If necessary, oral presentations will be limited to 15 
minutes each. Any member of the public may file a written statement 
with EPA before, during, or within 30 days of the hearing. Written 
statements should be addressed to the Air Docket address given in the 
ADDRESSES section of this document.
    A verbatim transcript of the public hearing, if held, and all 
written statements will be available for public inspection and copying 
during normal working hours at EPA's Air Docket in Washington, DC (see 
the ADDRESSES section of this document).

B. Public Docket

    The Docket for this regulatory action is A-2000-33. The docket is 
an organized and complete file of all the information submitted to or 
otherwise considered by EPA in the development of this proposed 
rulemaking. The principal purposes of the docket are: (1) To allow 
interested parties a means to identify and locate documents so that 
they can effectively participate in the rulemaking process, and (2) to 
serve as the record in case of judicial review. The docket is available 
for public inspection at EPA's Air Docket, which is listed under the 
ADDRESSES section of this document.

C. Executive Order 12866

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), the 
Administrator must determine whether the regulatory action is 
``significant'' and therefore subject to Office of Management and 
Budget (OMB) review and the requirements of the Executive Order. The 
Order defines ``significant regulatory action'' as one that is likely 
to result in a rule that may:
    (1) Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local or tribal governments or communities;
    (2) Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
    (3) Materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs or the rights and obligations of recipients 
thereof; or
    (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    This proposed rule is not expected to have an annual effect on the 
economy of $100 million or more. However, pursuant to the terms of 
Executive Order 12866, it has been determined that this proposed rule 
is a significant action because it raises novel policy issues. As such, 
the proposed rule has been submitted for OMB review. Any written 
comments from OMB and any EPA response to OMB comments are in the 
public docket for this proposal.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 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

[[Page 31998]]

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.
    This proposed rule is not expected to result in expenditures of 
more than $100 million in any one year and, as such, is not subject to 
section 202 of the UMRA. EPA will continue to use its outreach efforts 
related to part 75 implementation, including a policy manual that is 
updated regularly, to inform, educate, and advise all potentially 
impacted small governments about compliance with part 75.

E. Paperwork Reduction Act

    The information collection requirements in 40 CFR parts 72, 75, 78 
and 97 affect two EPA programs, the Acid Rain Program and the Federal 
NO<INF>X</INF> Budget Trading Program. There are two program ICRs 
currently in place that account for the basic recordkeeping and 
reporting burdens associated with 40 CFR parts 72, 75, 78 and 97. 
First, the Acid Rain Program ICR1633.12, (OMB No. 2060-0258) addresses 
the costs for units affected by the Acid Rain Program. The 
NO<INF>X</INF> SIP Call ICR1857.02, (OMB No. 2060-0445) addresses the 
costs, including NO<INF>X</INF> mass monitoring costs, by both Acid 
Rain Program (ARP) units and non-ARP units in the NO<INF>X</INF> Budget 
Trading Program.
    Most of the changes associated with this rulemaking are aimed at 
fine tuning the regulations in response to issues raised during the 
ongoing implementation of part 75. Thus, they do not significantly 
affect the burden estimates included in the two existing ICRs. Table 1, 
below, categorizes the proposed changes to parts 72 and 75, and 
proposed associated changes to part 97, as recordkeeping and reporting 
burden/cost neutral or as burden/cost reducing; none of the changes is 
expected to significantly increase burdens or costs. (The remaining 
changes to parts 72, 78, and 97 do not affect recordkeeping and 
reporting requirements.)
    Further, the Agency expects the changes to have minimal impact on 
existing program ICRs because many of the changes merely serve to make 
additional flexibilities feasible. For example, many of the proposed 
rule revisions to the LME section will clarify how the rule applies to 
non-ARP SIP Call units that use part 75 for NO<INF>X</INF> mass 
monitoring. The existing rule language is unclear for these non-ARP 
units. The changes make use of the LME provisions feasible for non-ARP 
units so that the scope of applicability to non-ARP units is not 
expected to be significantly different than that for ARP units.
    The SIP Call ICR assumed none of the non-ARP units would take 
advantage of the reduced burdens and costs associated with the LME 
provisions because those estimates only related to burden incurred 
through the year 2002. In future years, as LMEs avail themselves of the 
proposed provisions, it is estimated that there will be burden 
reductions. These reductions will be reflected in the next revisions to 
the SIP Call ICR.

Table 1--Summary of Impacts of Major Rule Revisions

    A. Rule Revisions Assumed To Be Cost/Burden Neutral
    Pipeline natural gas definition revision, and other definition 
clarifications
    Standardization of deadlines for various activities/reports/
notices
    Data validation clarifications
    Span/range clarifications
    Bypass monitoring flexibility changes
    Clarifications for Subpart H missing data
    General LME clarifications
    Missing data options relating to fuel type, degree of control, 
and non-load based units
    Alternative bypass stack monitoring options
    Other miscellaneous changes
    B. Rule Revisions Assumed To Decrease Costs/Burdens
    Expanded clarification of LME for Subpart H monitoring

    Although not indicated in Table 1, there are two primary ways in 
which the proposed parts 72, 75 and 97 revisions could result in some 
increased burden or cost. First, the regulated industry and State and 
local agencies involved with part 75 monitoring will have to review the 
revised regulation to understand the changes. The existing ARP and SIP 
Call ICRs have accounted for this increase in a line item for ongoing 
rule review. Nevertheless, it is important to note that new units just 
initiating part 75 monitoring in response to the NO<INF>X</INF> SIP 
Call will experience less burden as a consequence of the numerous 
clarifications, the specific changes to address NO<INF>X</INF> mass 
monitoring issues, and the removal of outdated sections. Taken as a 
whole, EPA does not believe that the regulatory review burdens will be 
affected significantly.
    The second type of burden or cost increase would be associated with 
any required data acquisition and handling system (DAHS) software 
changes that may be necessary to the extent the rule revisions affect 
recording and reporting data in the required electronic data formats. 
Generally, EPA has attempted to minimize any DAHS impacts associated 
with these revisions. There are some optional elements of the proposed 
revisions that would require DAHS software changes, but only if the 
owner or operator decides to take advantage of the option for its 
circumstances. EPA believes many sources will only avail themselves of 
these types of changes as part of other routine monitoring system 
component upgrades. Consequently, the expected impact in this area is 
also expected to be minimal. An agency may not conduct or sponsor, and 
a person is not required to respond to a collection of information 
unless it displays a valid OMB control number. The OMB control numbers 
for EPA's regulations are listed in 40 CFR part 9 and 48 CFR chapter 
15.
    The Agency requests comment on its assessment of information burden 
imposed by these requirements. An ICR amendment was not prepared 
because the changes were anticipated to be minimal in the context of 
the two existing ICRs. Send comments on the ICRs to the Director, 
Collection Strategies Division; U.S. Environmental Protection Agency 
(2822); 1200 Pennsylvania Ave., NW, Washington, DC 20460; and to the 
Office of Information and Regulatory Affairs, Office of Management and 
Budget, 725 17th St., NW, Washington, DC 20503, marked ``Attention: 
Desk Officer for EPA.'' Include the ICR in any correspondence. 
Additional information in support of the Agency's estimate is contained 
in the docket for this proposed rulemaking.

F. Regulatory Flexibility

    The Regulatory Flexibility Act (RFA), 5 U.S.C. 601, et seq., 
generally requires an agency to conduct 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

[[Page 31999]]

entities. Small entities include small businesses, small not-for-profit 
enterprises, and governmental jurisdictions.
    The EPA has determined that it is not necessary to prepare a 
regulatory flexibility analysis in connection with this proposed 
action. For the Acid Rain Program, these proposed revisions would not 
result in increased impacts to small entities.
    For these reasons, I certify that today's proposed rule would not 
have a significant, economic impact on a substantial number of small 
entities.

G. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (``NTTAA''), Public Law 104-113, 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, business practices, etc.) that are developed or adopted by 
voluntary consensus standards bodies. The NTTAA requires EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards.
    EPA invites public comment on the voluntary consensus standards 
which are proposed to be incorporated by reference for use in part 75. 
EPA has not identified any additional voluntary consensus standards 
which might be applicable to this rulemaking. This does not indicate 
that other applicable standards do not exist or that any other 
standards should not be allowed. Therefore, EPA also invites public 
comment on any other voluntary consensus standards which may be 
appropriate for the proposed regulatory action. Further, if additional 
applicable voluntary consensus standards are identified in the future, 
the designated representative may petition under Sec. 75.66(c) to use 
an alternative to any standard incorporated by reference and prescribed 
in this part.

H. Executive Order 13175

    Executive Order 13175, entitled ``Consultation and Coordination 
with Indian Tribal Governments'' (65 FR 67249, November 6, 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.'' ``Policies that have tribal 
implications'' is defined in the Executive Order to include regulations 
that have ``substantial direct effects on one or more Indian tribes, on 
the relationship between the Federal government and the Indian tribes, 
or on the distribution of power and responsibilities between the 
Federal government and Indian tribes.''
    This proposed rule does not have tribal implications. 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, as specified in Executive Order 13175. 
Thus, Executive Order 13175 does not apply to this rule.
    In the spirit of Executive Order 13175, and consistent with EPA 
policy to promote communications between EPA and tribal governments, 
EPA specifically solicits additional comment on this proposed rule from 
tribal officials.

I. Executive Order 12898

    Executive Order 12898 requires that each federal agency make 
achieving environmental justice part of its mission by identifying and 
addressing, as appropriate, disproportionately high and adverse human 
health or environmental effects of its programs, policies, and 
activities on minorities and low-income populations. The technical 
revisions in this proposed rule to various monitoring and other 
requirements would have no impact on emission levels or the location of 
emission reductions. Thus, the proposed rule revisions would not have a 
disproportionately high and adverse impact on minorities or low-income 
populations.

J. Executive Order 13045

    Executive Order 13045, entitled ``Protection of Children from 
Environmental Health Risks and Safety Risks'' (62 FR 19885, April 23, 
1997), applies to any rule that the Agency determines (1) is 
``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.
    Today's proposed rule is not subject to Executive Order 13045 
because it is not expected to have an annual effect on the economy of 
$100 million or more. Further, EPA does not have reason to believe that 
the environmental health risks or safety risks addressed by this action 
present a disproportionate risk to children.

K. Executive Order 13132

    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'' are 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.''
    Under section 6 of Executive Order 13132, EPA may not issue a 
regulation that has federalism implications, that imposes substantial 
direct compliance costs, and that is not required by statute, unless 
the Federal government provides the funds necessary to pay the direct 
compliance costs incurred by State and local governments, or EPA 
consults with State and local officials early in the process of 
developing the proposed regulation. EPA also may not issue a regulation 
that has federalism implications and that preempts State law, unless 
the Agency consults with State and local officials early in the process 
of developing the proposed regulation.
    The rule revisions in this proposed action 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. This proposed action does not 
create a mandate upon State, local, or tribal governments, except to 
the extent such governments own or operate an affected source. Even in 
those cases, the proposed rule revisions do not have federalism 
implications and do not impose significant compliance costs beyond the 
costs already incurred under part 75.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communications between EPA and State and local 
governments, EPA specifically solicits comment on this proposed rule 
from State and local officials.

List of Subjects

40 CFR Part 72

    Environmental protection, Acid rain, Administrative practice and 
procedure, Air pollution control, Continuous emission monitoring, 
Electric utilities, Nitrogen oxides, Reporting and

[[Page 32000]]

recordkeeping requirements, Sulfur oxides.

40 CFR Part 75

    Environmental protection, Acid rain, Administrative practice and 
procedure, Air pollution control, Carbon dioxide, Continuous emission 
monitoring, Electric utilities, Nitrogen oxides, Reporting and 
recordkeeping requirements, Sulfur oxides.

40 CFR Part 78

    Environmental protection, Acid rain, Administrative practice and 
procedure, Air pollution control, Continuous emission monitoring, 
Electric utilities, Nitrogen oxides, Reporting and recordkeeping 
requirements, Sulfur oxides.

40 CFR Part 97

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Continuous emission monitoring, Electric 
utilities, NO<INF>X</INF> Budget Program, Reporting and recordkeeping 
requirements.

    Dated: May 16, 2001.
Christine Todd Whitman,
Administrator.

    For the reasons set out in the preamble, title 40 chapter I of the 
Code of Federal Regulations is proposed to be 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.

    2. Section 72.2 is amended by:
    a. Revising the definitions of ``Cogeneration unit'', ``Continuous 
emission monitoring system or CEMS'', ``Hour before and after'', 
``Maximum potential NO<INF>X</INF> emission rate'', ``Missing data 
period'', ``Monitor accuracy'', ``Pipeline natural gas'', ``Stack 
operating hour'', and ``Unit operating hour'';
    b. In the definition of ``Automated data acquisition and handling 
system'' by adding the words ``moisture monitors,'' before the word 
``opacity'';
    c. In the definition of ``By-pass stack'' by removing the hyphen 
from the word ``bypass'';
    d. In paragraph (1) of the definition of ``Calibration error'' by 
adding the word ``a'' before the words ``gaseous monitor'';
    e. In the definition of ``Compliance plan'' by adding a closing 
parenthesis after the second instance of the words ``part 76 of this 
chapter'';
    f. In the definition of ``Continuous opacity monitoring system or 
COMS'' by revising the words ``systems are component parts'' in the 
second sentence to read ``components are'', and in paragraph (2) by 
revising the word ``A'' to read ``An automated'';
    g. Revising paragraph (2) of the definition of ``Emergency fuel'';
    h. In the definition of ``Fuel flowmeter QA operating quarter'' by 
adding the word ``cumulative'' after the words ``at least 168'' and 
removing the words ``or more'' at the end of the definition;
    i. Remove the definition of ``Heat input'' and add in its place a 
new definition ``Heat input rate'';
    j. Remove the definition of ``Maximum rated hourly heat input'' and 
add in its place the definition for ``Maximum rated hourly heat input 
rate'';
    k. In the definition of ``Natural gas'' by revising the second 
sentence and by removing the word ``meet'', and replacing the ``%'' 
symbol with the word ``percent'' in the third sentence;
    l. In the definition of ``QA operating quarter'' by adding the word 
``cumulative'' after each occurrence of the words ``at least 168'';
    m. In the definition of ``Relative accuracy'' by adding the words 
``or moisture'' after the words ``between the pollutant'' and by adding 
the words ``or moisture monitor'' after the words ``flow monitor'';
    n. Adding in alphabetical order new definitions for ``Common 
pipe'', ``Common pipe operating time'', ``Cumulative stack operating 
hours'', ``Cumulative unit operating hours'', ``Diluent cap value'', 
``Fuel flowmeter system'', ``Fuel usage time'', ``Multiple stack 
configuration'', ``Stack operating time'', and ``Unit operating time''.
    The revisions and additions read as follows:


Sec. 72.2  Definitions.

* * * * *
    Cogeneration unit means a unit that produces electric energy and 
useful thermal energy for industrial, commercial, or heating or cooling 
purposes, through the sequential use of the original fuel energy.
* * * * *
    Common pipe means an oil or gas supply line through which the same 
type of fuel is distributed to two or more affected units.
    Common pipe operating time means the portion of a clock hour during 
which fuel flows through a common pipe. The common pipe operating time, 
in hours, is expressed as a decimal fraction, with valid values ranging 
from 0.00 to 1.00.
* * * * *
    Continuous emission monitoring system or CEMS means the equipment 
required by part 75 of this chapter used to sample, analyze, measure, 
and provide, by means of readings recorded at least once every 15 
minutes (using an automated data acquisition and handling system 
(DAHS)), a permanent record of SO<INF>2</INF>, NO<INF>X</INF>, or 
CO<INF>2</INF> emissions or stack gas volumetric flow rate. The 
following are the principal types of continuous emission monitoring 
systems required under part 75 of this chapter. Sections 75.10 through 
75.18 and Sec. 75.71(a) of this chapter indicate which type(s) of CEMS 
is required for specific applications:
    (1) A sulfur dioxide monitoring system, consisting of an 
SO<INF>2</INF> pollutant concentration monitor and an automated DAHS. 
An SO<INF>2</INF> monitoring system provides a permanent, continuous 
record of SO<INF>2</INF> emissions in units of parts per million (ppm);
    (2) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated DAHS. A flow monitoring system provides a 
permanent, continuous record of stack gas volumetric flow rate, in 
units of standard cubic feet per hour (scfh);
    (3) A nitrogen oxides ( NO<INF>X</INF>) emission rate (or 
NO<INF>X</INF>-diluent) monitoring system, consisting of a 
NO<INF>X</INF> pollutant concentration monitor, a diluent gas 
(CO<INF>2</INF> or O<INF>2</INF>) monitor, and an automated DAHS. A 
NO<INF>X</INF>-diluent monitoring system provides a permanent, 
continuous record of: NO<INF>X</INF> concentration in units of parts 
per million (ppm), diluent gas concentration in units of percent 
O<INF>2</INF> or CO<INF>2</INF> (percent O<INF>2</INF> or 
CO<INF>2</INF>), and NO<INF>X</INF> emission rate in units of pounds 
per million British thermal units (lb/mmBtu);
    (4) A nitrogen oxides concentration monitoring system, consisting 
of a NO<INF>X</INF> pollutant concentration monitor and an automated 
DAHS. A NO<INF>X</INF> concentration monitoring system provides a 
permanent, continuous record of NO<INF>X</INF> emissions in units of 
parts per million (ppm). This type of CEMS is used only in conjunction 
with a flow monitoring system to determine NO<INF>X</INF> mass 
emissions (in lb/hr) under subpart H of part 75 of this chapter;
    (5) A carbon dioxide monitoring system, consisting of a 
CO<INF>2</INF> pollutant concentration monitor (or an oxygen monitor 
plus suitable mathematical equations from which the CO<INF>2</INF> 
concentration is derived) and the automated DAHS. A carbon dioxide 
monitoring system provides a permanent, continuous record of 
CO<INF>2</INF> emissions in units of percent CO<INF>2</INF> (percent 
CO<INF>2</INF>); and
    (6) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter. A moisture monitoring system provides

[[Page 32001]]

a permanent, continuous record of the stack gas moisture content, in 
units of percent H<INF>2</INF>O (percent H<INF>2</INF>O).
* * * * *
    Cumulative stack operating hours means the sum of the stack 
operating times (as defined in this section) for a series of 
consecutive stack operating hours (as defined in this section), rounded 
to the nearest hour.
    Cumulative unit operating hours means the sum of the unit operating 
times (as defined in this section) for a series of consecutive unit 
operating hours (as defined in this section), rounded to the nearest 
hour.
* * * * *
    Diluent cap value means a default CO<INF>2</INF> or O<INF>2</INF> 
concentration which may be used to calculate the hourly NO<INF>X</INF> 
emission rate, CO<INF>2</INF> mass emission rate, or heat input rate, 
when the measured hourly average CO<INF>2</INF> or O<INF>2</INF> 
concentration is below the default value. The diluent cap values for 
boilers are 5 percent CO<INF>2</INF> and 14 percent O<INF>2</INF>. For 
combustion turbines, the diluent cap values are 1 percent 
CO<INF>2</INF> and 19 percent O<INF>2</INF>.
* * * * *
    Emergency fuel means:
* * * * *
    (2) For purposes of the requirement for stack testing for an 
excepted monitoring system under appendix E of part 75 of this chapter, 
the fuel identified in a federally-enforceable permit for a plant and 
identified by the designated representative in the unit's monitoring 
plan as the fuel which is combusted only during emergencies where the 
primary fuel is not available.
* * * * *
    Fuel flowmeter system means an excepted monitoring system (as 
defined in this section) which provides a continuous record of the flow 
rate of fuel oil or gaseous fuel, in accordance with appendix D to part 
75 of this chapter. A fuel flowmeter system consists of one or more 
fuel flowmeter components, all necessary auxiliary components (e.g., 
transmitters, transducers, etc.), and a data acquisition and handling 
system (DAHS).
* * * * *
    Fuel usage time means the portion of a clock hour during which a 
unit combusts a particular type of fuel. The fuel usage time, in hours, 
is expressed as a decimal fraction, with valid values ranging from 0.00 
to 1.00.
* * * * *
    Heat input rate means the product (expressed in mmBtu/hr) of the 
gross calorific value of the fuel (expressed in mmBtu/mass of fuel) and 
the fuel feed rate into the combustion device (expressed in mass of 
fuel/hr) and does not include the heat derived from preheated 
combustion air, recirculated flue gases, or exhaust from other sources.
    Hour before and hour after means, for purposes of the missing data 
substitution procedures of part 75 of this chapter, the quality-assured 
hourly SO<INF>2</INF> or CO<INF>2</INF> concentration, hourly flow 
rate, hourly NO<INF>X</INF> concentration, hourly moisture, hourly 
O<INF>2</INF> concentration, or hourly NO<INF>X</INF> emission rate (as 
applicable) recorded by a certified monitor during the unit or stack 
operating hour immediately before and the unit or stack operating hour 
immediately after a missing data period.
* * * * *
    Maximum potential NO<INF>X</INF> emission rate, or MER means the 
emission rate of nitrogen oxides (in lb/mmBtu) calculated in accordance 
with section 3 of appendix F to part 75 of this chapter, using the 
maximum potential nitrogen oxides concentration as defined in section 
2.1.2.1 of appendix A to part 75 of this chapter, and either the 
maximum oxygen concentration (in percent O<INF>2</INF>) or the minimum 
carbon dioxide concentration (in percent CO<INF>2</INF>) under all 
operating conditions of the unit except for unit start-up, shutdown, 
and upsets. The diluent cap value, as defined in this section, may be 
used in lieu of the maximum O<INF>2</INF> or minimum CO<INF>2</INF> 
concentration to calculate the MER.
    Maximum rated hourly heat input rate means a unit-specific maximum 
hourly heat input rate (mmBtu/hr) which is the higher of the 
manufacturer's maximum rated hourly heat input rate or the highest 
observed hourly heat input rate.
    Missing data period means the total number of consecutive hours 
during which any certified CEMS or approved alternative monitoring 
system is not providing quality-assured data, regardless of the reason.
    Monitor accuracy means the closeness of the measurement made by a 
CEMS to the reference value of the emissions or volumetric flow being 
measured, expressed as the difference between the measurement and the 
reference value.
* * * * *
    Multiple stack configuration refers to an exhaust configuration in 
which the flue gases from a particular unit discharge to the atmosphere 
through two or more stacks. The term also refers to a unit for which 
emissions are monitored in two or more ducts leading to the exhaust 
stack, in lieu of monitoring at the stack.
* * * * *
    Natural gas * * * Natural gas contains 20.0 grains or less of total 
sulfur per 100 standard cubic feet. * * *
* * * * *
    Pipeline natural gas means a naturally occurring fluid mixture of 
hydrocarbons (e.g., methane, ethane, or propane) produced in geological 
formations beneath the Earth's surface that maintains a gaseous state 
at standard atmospheric temperature and pressure under ordinary 
conditions, and which is provided by a supplier through a pipeline. 
Pipeline natural gas contains 0.5 grains or less of total sulfur per 
100 standard cubic feet. Additionally, pipeline natural gas must either 
be composed of at least 70 percent methane by volume or have a gross 
calorific value between 950 and 1100 Btu per standard cubic foot.
* * * * *
    Stack operating hour means a clock hour during which flue gases 
flow through a particular stack or duct (either for the entire hour or 
for part of the hour) while the associated unit(s) are combusting fuel.
    Stack operating time means the portion of a clock hour during which 
flue gases flow through a particular stack or duct while the associated 
unit(s) are combusting fuel. The stack operating time, in hours, is 
expressed as a decimal fraction, with valid values ranging from 0.00 to 
1.00.
* * * * *
    Unit operating hour means a clock hour during which a unit combusts 
any fuel, either for part of the hour or for the entire hour.
* * * * *
    Unit operating time means the portion of a clock hour during which 
a unit combusts any fuel. The unit operating time, in hours, is 
expressed as a decimal fraction, with valid values ranging from 0.00 to 
1.00.
* * * * *

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.


Sec. 75.1  [Amended].

    4. Section 75.1 is amended by adding the words ``(the Act)'' at the 
end of the first sentence of paragraph (a).
    5. Section 75.4 is amended by:
    a. In paragraph (b) introductory text by adding the word 
``moisture,'' after the word ``opacity,'';
    b. In paragraphs (b)(2) and (c)(2) by revising the words ``Not 
later than 90''

[[Page 32002]]

to read ``The earlier of 90 unit operating days or 180 calendar'';
    c. Remove ``or'' at the end of paragraphs (b)(1) and (c)(1) and 
remove the period at the end of paragraphs (b)(2) and (c)(2) and add 
``; or'' in its place;
    d. Adding paragraphs (b)(3) and (c)(3);
    e. In the first sentence of paragraph (d) by revising the words 
``the earlier of 45'' to read ``90'', adding the words ``(whichever 
occurs first)'' following the words ``180 calendar days'', and removing 
the words ``of the affected unit'' after the words ``recommences 
commercial operation'';
    f. In the first sentence of paragraph (e) introductory text by 
revising the words ``90 calendar days'' to read ``90 unit operating 
days or 180 calendar days (whichever occurs first)'';
    g. Revising paragraphs (f) introductory text and (f)(1);
    h. Removing and reserving paragraphs (g) and (h); and
    i. In paragraph (i) by removing the word ``or'' in paragraph (i)(1) 
and by revising paragraphs (i)(2) and (i)(3).
    The revisions and additions read as follows:


Sec. 75.4  Compliance dates.

* * * * *
    (b) * * *
    (3) The owner or operator shall determine and report SO<INF>2</INF> 
concentration, NO<INF>X</INF> emission rate, CO<INF>2</INF> 
concentration, and flow data for all unit operating hours after the 
applicable compliance date in this paragraph until all required 
certification tests are successfully completed using either:
    (i) The maximum potential concentration of SO<INF>2</INF>, the 
maximum potential NO<INF>X</INF> emission rate, as defined in section 
2.1.2.1 of appendix A to this part, the maximum potential flow rate, as 
defined in section 2.1.4.1 of appendix A to this part, or the maximum 
potential CO<INF>2</INF> concentration, as defined in section 2.1.3.1 
of appendix A to this part;
    (ii) Reference methods under Sec. 75.22(b); or
    (iii) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.
    (c) * * *
    (3) The owner or operator shall determine and report SO<INF>2</INF> 
concentration, NO<INF>X</INF> emission rate, CO<INF>2</INF> 
concentration, and flow data for all unit operating hours after the 
applicable compliance date in this paragraph until all required 
certification tests are successfully completed using either:
    (i) The maximum potential concentration of SO<INF>2</INF>, the 
maximum potential NO<INF>X</INF> emission rate, as defined in section 
2.1.2.1 of appendix A to this part, the maximum potential flow rate, as 
defined in section 2.1.4.1 of appendix A to this part, or the maximum 
potential CO<INF>2</INF> concentration, as defined in section 2.1.3.1 
of appendix A to this part;
    (ii) Reference methods under Sec. 75.22(b); or
    (iii) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.
* * * * *
    (f) In accordance with Sec. 75.20, the owner or operator of an 
affected gas-fired or oil-fired peaking unit, if planning to use 
appendix E of this part, shall ensure that the required certification 
tests for excepted monitoring systems under appendix E are completed 
for backup fuel, as defined in Sec. 72.2 of this chapter, no later than 
90 unit operating days or 180 calendar days (whichever occurs first) 
after the date that the unit first combusts the backup fuel following 
the certification testing with the primary fuel. Until all required 
certification tests are successfully completed, the owner or operator 
shall report NO<INF>X</INF> emission rate data for all unit operating 
hours that the backup fuel is combusted using either:
    (1) The fuel-specific maximum potential NO<INF>X</INF> emission 
rate;
* * * * *
    (i) * * *
    (2) For a new affected unit which has not commenced commercial 
operation by January 2, 2000, 90 unit operating days or 180 calendar 
days (whichever occurs first) after the date the unit commences 
commercial operation; or
    (3) For an existing unit that is shutdown and is not yet operating 
by April 1, 2000, 90 unit operating days or 180 calendar days 
(whichever occurs first) after the date that the unit recommences 
commercial operation.


Sec. 75.6  [Amended].

    6. In Sec. 75.6 amend paragraphs (a)(19), (a)(26), and (a)(35) by 
removing the words ``Sec. 75.15 and''.
    7. Section 75.10 is amended by:
    a. In paragraph (a)(1) by revising the word ``The'' in the first 
sentence to read ``To determine SO<INF>2</INF> emissions, the'', and by 
revising the words ``the automated'' to read ``an automated'';
    b. In paragraph (a)(2) by revising the word ``The'' in the first 
sentence to read ``To determine NO<INF>X</INF> emissions, the''; by 
revising the words ``the automated'' to read ``an automated''; and by 
revising the first occurrence of the word `` NO<INF>X</INF>'' in the 
first sentence to read `` NO<INF>X</INF>-diluent'';
    c. In paragraph (a)(3)(i) by revising the words ``the automated'' 
to read ``an automated'';
    d. In paragraph (a)(3)(iii) by revising the words ``using an 
O<INF>2</INF> concentration monitor in order'' to read ``that uses an 
O<INF>2</INF> concentration monitor'' and by revising the words ``using 
the procedures in appendix F of this part with the automated'' to read 
``(according to the procedures in appendix F of this part) with an 
automated'';
    e. Removing ``and'' at the end of paragraph (a)(3) and removing the 
period at the end of paragraph (a)(4) and adding ``; and'' in its 
place;
    f. Adding new paragraph (a)(5);
    g. In paragraph (c) by adding the word ``Rate'' after the words 
``Heat Input'' in the heading and by adding the words ``rate, in units 
of mmBtu/hr,'' after the words ``record the heat input'';
    h. In paragraph (d)(1) by removing the words ``and component 
thereof'' from the first sentence, removing the words ``SO<INF>2</INF> 
emission rate in lb/mmBtu (if applicable),'' from the second sentence, 
and by adding the word ``or'' after the words ``of this part,'' in the 
fourth sentence;
    i. In paragraph (d)(3) by revising the words ``flow monitor, or 
NO<INF>X</INF>'' to read `` NO<INF>X</INF> concentration monitor, flow 
monitor, moisture monitor, or NO<INF>X</INF>-diluent'', by revising the 
words ``An hourly average NO<INF>X</INF> or SO<INF>2</INF>'' in the 
second sentence to read ``For a NO<INF>X</INF>-diluent monitoring 
system, hourly average NO<INF>X</INF>'', by adding the word 
``NO<INF>X</INF>'' before the word ``pollutant'' and by removing the 
words ``(NO<INF>X</INF> or SO<INF>2</INF>)'' in the second sentence; 
and by revising in the fourth sentence the words ``Except for 
SO<INF>2</INF> emission rate data in lb/mmBtu, if'' to read ``If'';
    j. In paragraph (f) by removing the words ``and component 
thereof''; and
    k. Revising the capitalization in the title of paragraph (g) from 
``Minimum Recording and Recordkeeping Requirements'' to ``Minimum 
recording and recordkeeping requirements''.
    The revisions and additions read as follows:


Sec. 75.10  General operating requirements.

    (a) * * *
    (5) A single, certified flow monitoring system may be used to meet 
the requirements of paragraphs (a)(1) and (a)(3) of this section. A 
single certified diluent monitor may be used to meet the requirements 
of paragraphs (a)(2) and (a)(3) of this section. A single automated 
data acquisition and handling system may be used to meet the 
requirements of paragraphs (a)(1) through (a)(4) of this section.
* * * * *


Sec. 75.11  [Amended].

    8. Section 75.11 is amended by:

[[Page 32003]]

    a. Revising the word ``psychometric'' in paragraph (b)(2) to read 
``psychrometric'';
    b. In the second sentence of paragraph (e)(1) by adding the words 
``(according to the applicable equation in section 5.2 of appendix F to 
this part)'' after the word ``monitor'', and removing the words ``and 
equation D-5 in appendix D to this part'';
    c. In paragraph (e)(2) by revising in the first sentence the words 
``Sec. 75.55 or Sec. 75.58, as applicable,'' to read ``Sec. 75.58,'', 
and by, in the second sentence, adding the word ``rate'' after ``heat 
input'' and revising the words ``Sec. 75.54(b)(5) or Sec. 75.57(b)(5), 
as applicable,'' to read ``Sec. 75.57(b)(5)'';
    d. In paragraph (e)(3) by removing the third sentence, removing the 
period at the end of the second sentence and adding a semicolon, 
removing the words ``then on and after April 1, 2000,'' in the second 
sentence, and by revising the words ``be subject to'' to read ``meet'' 
in the second sentence; and
    e. In the first sentence of paragraph (e)(3)(iii) by adding the 
words ``bias-adjusted'' before the words ``hourly average''.
    9. Section 75.12 is amended by:
    a. Revising the section heading;
    b. In paragraph (a) by adding the word ``(CEMS)'' after the words 
``continuous emission monitoring system'' in the first sentence and by 
revising the words `` NO<INF>X</INF> continuous emission monitoring 
system'' to read `` NO<INF>X</INF>-diluent CEMS'' in the second 
sentence;
    c. In paragraph (d)(2) by revising the word `` NO<INF>X</INF>'' to 
read `` NO<INF>X</INF>-diluent'' in the second sentence and by adding a 
new third sentence; and
    d. In paragraph (e) by revising the reference to ``(c)'' to read 
``(d)''.
    The revisions and additions read as follows:


Sec. 75.12  Specific provisions for monitoring NO<INF>X</INF> emission 
rate ( NO<INF>X</INF>-diluent monitoring systems).

* * * * *
    (d) * * *
    (2) * * * If the required CEMS has not been installed and certified 
by that date, the owner or operator shall report the maximum potential 
NO<INF>X</INF> emission rate (MER) (as defined in Sec. 72.2 of this 
chapter) for each unit operating hour, starting with the first unit 
operating hour after the deadline and continuing until the CEMS has 
been provisionally certified. For each unit operating hour in which the 
MER is reported, the MER shall be specific to the type of fuel being 
combusted in the unit.
* * * * *
    10. Section 75.13 is amended by:
    a. Revising the heading and first sentence of paragraph (b); and
    b. Revising the first sentence of paragraph (c).
    The revisions and additions read as follows:


Sec. 75.13  Specific provisions for monitoring CO<INF>2</INF> 
emissions.

* * * * *
    (b) Determination of CO<INF>2</INF> emissions using appendix G to 
this part. If the owner or operator chooses to use the appendix G 
method, then the owner or operator shall follow the procedures in 
appendix G to this part for estimating daily CO<INF>2</INF> mass 
emissions based on the measured carbon content of the fuel and the 
amount of fuel combusted. * * *
    (c) Determination of CO<INF>2</INF> mass emissions using an 
O<INF>2</INF> monitor according to appendix F to this part. The owner 
or operator shall determine hourly CO<INF>2</INF> concentration and 
mass emissions with a flow monitoring system; a continuous 
O<INF>2</INF> concentration monitor; fuel F and F<INF>C</INF> factors; 
and, where O<INF>2</INF> concentration is measured on a dry basis (or 
where Equation F-14b in appendix F to this part is used to determine 
CO<INF>2</INF> concentration), either a continuous moisture monitoring 
system, as specified in Sec. 75.11(b)(2), or a fuel-specific default 
moisture percentage (if applicable), as defined in Sec. 75.11(b)(1); 
and by using the methods and procedures specified in appendix F to this 
part. * * *
* * * * *


Sec. 75.15  [ Reserved].

    11. Section 75.15 is removed and reserved.
    12. Section 75.16 is amended by:
    a. Removing and reserving all of paragraph (a);
    b. Revising paragraph (b) heading and introductory text and 
paragraph (c);
    c. Amending paragraphs (e) heading and introductory text, (e)(1), 
(e)(2), (e)(3), and (e)(4) by adding the word ``rate'' after each 
occurrence of the words ``heat input'' except for the last occurrence 
in paragraph (e)(1);
    d. In paragraph (e)(1) by revising the reference to ``(a)'' to read 
``(b)'' in the first sentence, and by removing ``(a)(1)(ii), 
(a)(2)(ii),'' and the comma after ``(b)(1)(ii)'' in the third sentence;
    e. In paragraph (e)(2) by revising the words ``appendix F of this 
part'' to read ``appendix F to this part''; and
    f. In paragraph (e)(3) by adding the words ``, in conjunction with 
the appropriate unit and stack operating times'' after the words 
``utilizing the common stack''.
    The revisions and additions read as follows:


Sec. 75.16  Special provisions for monitoring emissions from common, 
bypass, and multiple stacks for SO<INF>2</INF> emissions and heat input 
determinations.

* * * * *
    (b) Common stack procedures. The following procedures shall be used 
when more than one unit uses a common stack:
* * * * *
    (c) Unit with bypass stack. Whenever any portion of the flue gases 
from an affected unit can be routed through a bypass stack so as to 
avoid the installed SO<INF>2</INF> continuous emission monitoring 
system and flow monitoring system, the owner or operator shall either:
    (1) Install, certify, operate, and maintain separate SO<INF>2</INF> 
continuous emission monitoring systems and flow monitoring systems on 
the main stack and the bypass stack and calculate SO<INF>2</INF> mass 
emissions for the unit as the sum of the SO<INF>2</INF> mass emissions 
measured at the two stacks; or
    (2) Monitor SO<INF>2</INF> mass emissions at the main stack using 
SO<INF>2</INF> and flow rate monitoring systems and measure 
SO<INF>2</INF> mass emissions at the bypass stack using the reference 
methods in Sec. 75.22(b) for SO<INF>2</INF> and flow rate and calculate 
SO<INF>2</INF> mass emissions for the unit as the sum of the emissions 
recorded by the installed monitoring systems on the main stack and the 
emissions measured by the reference method monitoring systems; or
    (3) Install, certify, operate, and maintain SO<INF>2</INF> and flow 
rate monitoring systems only on the main stack. If this option is 
chosen, report the following values for each hour during which 
emissions pass through the bypass stack: the maximum potential 
concentration of SO<INF>2</INF> as determined under section 2.1.1.1 of 
appendix A to this part (or, if available, the SO<INF>2</INF> 
concentration measured by a certified monitor located at the control 
device inlet), and the maximum potential flow rate, as defined in 
section 2.1.4.1 of appendix A to this part. If the bypass stack is also 
unmonitored for NO<INF>X</INF>, CO<INF>2</INF>, or moisture, report the 
following values for each hour in which the bypass stack is used: the 
maximum potential CO<INF>2</INF> concentration, as defined in section 
2.1.3.1 of appendix A to this part, the maximum potential 
NO<INF>X</INF> emission rate, as defined in section 2.1.2.1(b) of 
appendix A to this part, the minimum potential moisture percentage, as 
defined in section 2.1.5 of appendix A to this part, and, if 
O<INF>2</INF> concentration is used to determine the hourly heat input 
rate, report the minimum potential O<INF>2</INF> concentration (as 
defined in section 2.1.3.2 of appendix A to this part). The maximum 
potential SO<INF>2</INF> concentration and the maximum potential 
NO<INF>X</INF>

[[Page 32004]]

emission rate shall be specific to the type of fuel combusted in the 
unit during the bypass (see Sec. 75.33(b)(5)). This option may only be 
used if use of the bypass stack is limited to unit startup, emergency 
situations (e.g., malfunction of a flue gas desulfurization system), 
and periods of routine maintenance of the flue gas desulfurization 
system or maintenance 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 Sec. 75.53, 
with respect to SO<INF>2</INF>, flow rate, or any other parameter that 
is monitored only at the main stack.
* * * * *
    13. Section 75.17 is amended by:
    a. Removing the hyphen from the word ``by-pass'' in the section 
heading;
    b. In the introductory text by revising the words ``and (c)'' to 
read ``(c), and (d)'';
    c. In paragraph (b)(1) by revising the word ``NO<INF>X</INF>'' to 
read ``NO<INF>X</INF>-diluent'';
    d. Revising the paragraph heading and first sentence of paragraph 
(c) introductory text;
    e. Revising paragraphs (c)(1) and (c)(2); and
    f. Adding new paragraph (d).
    The revisions and additions read as follows:


Sec. 75.17  Specific provisions for monitoring emissions from common, 
bypass, and multiple stacks for NO<INF>X</INF> emission rate.

* * * * *
    (c) Unit with multiple stacks or ducts. When the flue gases from an 
affected unit discharge to the atmosphere through two or more stacks or 
when flue gases from an affected unit utilize two or more ducts feeding 
into a single stack and the owner or operator chooses to monitor in the 
ducts rather than the stack, the owner or operator shall monitor the 
NO<INF>X</INF> emission rate in a way that is representative of each 
affected unit. * * *
    (1) Install, certify, operate, and maintain a NO<INF>X</INF>-
diluent continuous emission monitoring system and a flow monitoring 
system in each stack or duct and determine the NO<INF>X</INF> emission 
rate for the unit as the Btu-weighted average of the NO<INF>X</INF> 
emission rates measured in the stacks or ducts using the heat input 
estimation procedures in appendix F to this part. Alternatively, for 
units that are eligible to use the procedures of appendix D to this 
part, the owner or operator may monitor heat input and NO<INF>X</INF> 
emission rate at the unit level, in lieu of installing flow monitors on 
each stack or duct. If this alternative unit-level monitoring is 
performed, report, for each unit operating hour, the highest emission 
rate measured by any of the NO<INF>X</INF>-diluent monitoring systems 
installed on the individual stacks or ducts as the hourly 
NO<INF>X</INF> emission rate for the unit, and report the hourly unit 
heat input as determined under appendix D to this part. Also, when this 
alternative unit-level monitoring is performed, the applicable 
NO<INF>X</INF> missing data procedures in Secs. 75.31 or 75.33 shall be 
used for each unit operating hour in which a quality-assured 
NO<INF>X</INF> emission rate is not obtained for one or more of the 
individual stacks or ducts; or
    (2) Provided that the products of combustion are well-mixed, 
install, certify, operate, and maintain a NO<INF>X</INF> continuous 
emission monitoring system in one stack or duct from the affected unit 
and record the monitored value as the NO<INF>X</INF> emission rate for 
the unit. The owner or operator shall account for NO<INF>X</INF> 
emissions from the unit during all times when the unit combusts fuel. 
Therefore, this option shall not be used if the monitored stack or duct 
can be bypassed (e.g., by using dampers). Follow the procedure in 
Sec. 75.17 for units with bypass stacks. Further, this option shall not 
be used unless the monitored NO<INF>X</INF> emission rate truly 
represents the NO<INF>X</INF> emissions discharged to the atmosphere 
(e.g., the option is disallowed if there are any additional 
NO<INF>X</INF> emission controls downstream of the monitored location).
    (d) Unit with a main stack and bypass stack configuration. For an 
affected unit with a discharge configuration consisting of a main stack 
and a bypass stack, the owner or operator shall either:
    (1) Follow the procedures in paragraph (c)(1) of this section; or
    (2) Install, certify, operate, and maintain a NO<INF>X</INF>-
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 Sec. 75.53, 
with respect to NO<INF>X</INF> or any other parameter that is monitored 
only at the main stack. For each unit operating hour in which the 
bypass stack is used, report the maximum potential NO<INF>X</INF> 
emission rate (as defined in Sec. 72.2 of this chapter). The maximum 
potential NO<INF>X</INF> emission rate shall be specific to the type of 
fuel combusted in the unit during the bypass (see Sec. 75.33(c)(8)). In 
addition, if SO<INF>2</INF>, CO<INF>2</INF>, flow rate, or (if 
applicable) moisture monitoring systems are installed only on the main 
stack and not on the bypass stack, report the following values for each 
hour in which the bypass stack is used: The maximum potential values of 
SO<INF>2</INF> concentration, CO<INF>2</INF> concentration, and stack 
gas flow rate, as defined in section 2 of appendix A to this part, the 
minimum potential moisture percentage, as defined in section 2.1.5 of 
appendix A to this part, and, if O<INF>2</INF> concentration is used to 
determine the hourly heat input rate, report the minimum potential 
O<INF>2</INF> concentration (as defined in section 2.1.3.2 of appendix 
A to this part). If SO<INF>2</INF> emissions and the unit heat input 
are determined using a fuel flowmeter in accordance with appendix D to 
this part and if CO<INF>2</INF> emissions are estimated using the 
procedures in appendix G to this part, report SO<INF>2</INF> emissions 
and CO<INF>2</INF> emissions in accordance with appendices D and G to 
this part, and report the actual measured heat input rate for each hour 
in which the bypass stack is used.
    14. Section 75.19 is amended by:
    a. Revising paragraphs (a)(1)(i), (a)(1)(ii), (a)(2)(i), 
(a)(2)(ii), (b)(1), (b)(2), (b)(3), (c)(1)(iv)(A), (c)(1)(iv)(C), and 
(c)(3)(ii)(H);
    b. In paragraph (b)(4) introductory text by revising the words 
``unit commencing operation after January 1, 1997'' to read ``new or 
newly-affected unit'';
    c. In paragraph (b)(4)(ii) by revising the words `` NO<INF>X</INF>, 
and CO<INF>2</INF>'' to read ``CO<INF>2</INF>, and/or NO<INF>X</INF>'';
    d. In paragraph (b)(4)(iii) by revising the words ``and 
NO<INF>X</INF>'' in the first sentence to read ``and/or 
NO<INF>X</INF>'' and by revising the words ``tables 1, 2 and 3'' to 
read ``tables LM-1, LM-2, and LM-3'' in the second sentence;
    e. Removing and reserving paragraph (c)(1)(iv)(B)(3);
    f. In paragraph (c)(1)(iv)(B)(4) by revising the reference to 
``(c)(1)(iv)(B)(3)'' to read ``(c)(1)(iv)(B)(1)'';
    g. In the first sentence of paragraph (c)(1)(iv)(D) by revising the 
words ``, each unit in a group of units sharing a common fuel supply, 
or'' to read ``or group of'';
    h. In paragraph (c)(1)(iv)(E) by removing the words ``, each low 
mass emission unit in a group of units combusting a common fuel,'';
    i. Revising the first and last sentences of (c)(1)(iv)(G);
    j. In the first sentence of (c)(1)(iv)(H) by adding the words 
``(including units that use dry low-NO<INF>X</INF> technology),'' after 
the first occurrence of the words ``NO<INF>X</INF> emission controls'';
    k. In the last sentence of (c)(1)(iv)(H)(1) by adding the words ``, 
and the appropriate default NO<INF>X</INF> emission rate from Table LM-
2 shall be reported instead'' after the words ``for that hour'';
    l. Adding new paragraph (c)(1)(iv)(I);

[[Page 32005]]

    m. In paragraph (c)(2)(iii) by revising the word ``output'' to read 
``load'' and adding the words ``per hour'' after the words ``pounds of 
steam'';
    n. In paragraph (c)(2)(iv) by adding the words ``add-on'' after the 
words ``unit with'' and adding the words ``(including dry low-
NO<INF>X</INF> technology)'' after the words ``of any kind'';
    o. In paragraph (c)(3)(i) by adding ``HI<INF>hr</INF>,'' after the 
words ``of this section,'' in the first sentence, by revising Eq. LM-1 
and the accompanying variable definitions, and by adding a new 
paragraph (c)(3)(i)(D);
    p. Removing the word ``use'' in the second sentence of paragraph 
(c)(3)(ii)(D)(1);
    q. Adding a sentence following the first sentence of paragraphs 
(c)(3)(ii)(E), (c)(3)(ii)(G), and (c)(4)(ii)(C);
    r. In the definition of M<INF>qtr</INF> in Equation LM-2 in 
paragraph (c)(3)(ii)(E) by removing the word ``entire'';
    s. In the definition of Q<INF>g</INF> in Equation LM-3 in paragraph 
(c)(3)(ii)(E) by revising the word ``Value'' to read ``Volume'' and 
adding parentheses around the words ``standard cubic feet (scf)'';
    t. In paragraph (c)(3)(ii)(F) by adding the words ``, using 
Equation LM-4'' after the reference to ``LM-3'';
    u. Revising the definition of variables following Equations LM-7 
and LM-8 in paragraph (c)(3)(ii)(I), the definition of variables 
following Equations LM-7a and LM-8a in paragraph (c)(3)(ii)(J), and the 
definitions of the first two variables following Equation LM-10 in 
paragraph (c)(4)(ii)(A);
    v. In the definition of variable ``EF<INF>SO2</INF>'' for Equation 
LM-9 in paragraph (c)(4)(i) by revising the reference ``table 1'' to 
read ``table LM-1'';
    w. In paragraph (e)(5) by revising the words ``which have 
NO<INF>X</INF> emission controls of any kind'' to read ``which have 
add-on NO<INF>X</INF> emission controls of any kind (including dry low-
NO<INF>X</INF> technology)''; and
    x. In Table LM-5 that follows paragraph (e) by adding the word 
``Other'' before ``Natural Gas'' in the first column of the second 
entry of the table.
    The revisions and additions read as follows:


Sec. 75.19  Optional SO<INF>2</INF>, NO<INF>X</INF>, and CO<INF>2</INF> 
emissions calculation for low mass emissions units.

    (a) * * *
    (1) * * *
    (i) A low mass emissions unit is an affected unit that burns only 
natural gas or fuel oil (i.e., diesel fuel or residual oil) and for 
which:
    (A) An initial demonstration is provided, in accordance with 
paragraph (a)(2) of this section, which shows that the unit emits no 
more than:
    (1) 25 tons of SO<INF>2</INF> annually and 50 tons of 
NO<INF>X</INF> annually, for Acid Rain Program affected units 
(including units which are also subject to the provisions of subpart H 
of this part),
    (2) 50 tons of NO<INF>X</INF> annually, for units which are subject 
to the provisions of subpart H of this part and which report emissions 
data on a year-round basis, in accordance with Sec. 75.74(b), or
    (3) 25 tons of NO<INF>X</INF> per ozone season, for units which are 
subject to the provisions of subpart H of this part and which report 
emissions data only during the ozone season, in accordance with 
Sec. 75.74(b); and
    (B) An annual demonstration is provided thereafter, using one of 
the allowable methodologies in paragraph (c) of this section, showing 
that the low mass emission unit continues to emit no more than the 
applicable number of tons of SO<INF>2</INF> and/or NO<INF>X</INF> 
specified in paragraph (a)(1)(i)(A) of this section.
    (ii) Any qualifying unit must start using the low mass emissions 
excepted methodology as follows:
    (A) For a unit that reports emission data on a year-round basis, 
begin using the methodology in the first unit operating hour in the 
calendar year in which the unit (as indicated in the certification 
application) will first qualify as a low mass emissions unit; or
    (B) For a unit that is subject to subpart H of this part and that 
reports only during the ozone season according to Sec. 75.74(c), begin 
using the methodology in the first unit operating hour in the ozone 
season in which the unit (as indicated in the certification 
application) will first qualify as a low mass emissions unit.
    (2) * * *
    (i) If the designated representative submits a certification 
application to use the low mass emissions excepted methodology and the 
Administrator (or permitting authority) certifies the use of such 
methodology. The certification application shall be submitted no later 
than 45 days prior to the date on which use of the low mass emissions 
excepted methodology will commence. The certification application must 
contain, as applicable, the information in paragraph (a)(2)(i)(A), 
(a)(2)(i)(B), or (a)(2)(i)(C) of this section.
    (A) Acid Rain Program affected units. For affected units under the 
Acid Rain Program (including units which are also subject to the 
provisions of subpart H of this part), the certification application 
shall contain:
    (1) Actual SO<INF>2</INF> and NO<INF>X</INF> mass emissions data 
for each of the three calendar years prior to the calendar year in 
which the unit will first qualify as a low mass emissions unit, 
demonstrating to the satisfaction of the Administrator that the unit 
emits no more than 25 tons of SO<INF>2</INF> and no more than 50 tons 
of NO<INF>X</INF> annually; and
    (2) Calculated SO<INF>2</INF> and NO<INF>X</INF> mass emissions, 
for each of the three calendar years prior to the calendar year in 
which the unit will first qualify as a low mass emissions unit, 
demonstrating to the satisfaction of the Administrator that the unit 
emits no more than 25 tons of SO<INF>2</INF> and no more than 50 tons 
of NO<INF>X</INF> annually. The calculated emissions for each year 
shall be determined using either the maximum rated heat input 
methodology described in paragraph (c)(3)(i) of this section or the 
long term fuel flow heat input methodology described in paragraph 
(c)(3)(ii) of this section, in conjunction with the appropriate 
emission rate from paragraph (c)(1)(i) of this section for 
SO<INF>2</INF> and paragraph (c)(1)(ii) or (c)(1)(iv) of this section 
for NO<INF>X</INF>.
    (B) Non-Acid Rain subpart H units reporting on a year-round basis. 
For units that are not affected under the Acid Rain Program, but are 
subject to the provisions of subpart H of this part, and which report 
emissions data on a year-round basis, the certification application 
shall contain:
    (1) Actual NO<INF>X</INF> mass emissions data for each of the three 
calendar years prior to the calendar year in which the unit will first 
qualify as a low mass emissions unit, demonstrating to the satisfaction 
of the Administrator (or the permitting authority if subpart H is used 
under a State approved SIP) that the unit emits no more than 50 tons of 
NO<INF>X</INF> annually; and
    (2) Calculated NO<INF>X</INF> mass emissions, for each of the three 
calendar years prior to the calendar year in which the unit will first 
qualify as a low mass emissions unit, demonstrating to the satisfaction 
of the Administrator that the unit emits no more than 50 tons of 
NO<INF>X</INF> annually. The calculated emissions for each year shall 
be determined using either the maximum rated heat input methodology 
described in paragraph (c)(3)(i) of this section or the long term fuel 
flow heat input methodology described in paragraph (c)(3)(ii) of this 
section, in conjunction with the appropriate NO<INF>X</INF> emission 
rate from paragraph (c)(1)(ii) or (c)(1)(iv) of this section.
    (C) Non-Acid Rain subpart H units, reporting ozone season data 
only. For units that are not affected under the Acid Rain Program, but 
are subject to the provisions of subpart H of this part, and which 
report emissions data only

[[Page 32006]]

during the ozone season, the certification application shall contain:
    (1) Actual NO<INF>X</INF> mass emissions data for each of the three 
ozone seasons prior to the ozone season in which the unit will first 
qualify as a low mass emissions unit, demonstrating to the satisfaction 
of the Administrator (or the permitting authority if subpart H is used 
under a State approved SIP) that the unit emits no more than 25 tons of 
NO<INF>X</INF> per ozone season; and
    (2) Calculated NO<INF>X</INF> mass emissions, for each of the three 
ozone seasons prior to the ozone season in which the unit will first 
qualify as a low mass emissions unit, demonstrating to the satisfaction 
of the Administrator that the unit emits no more than 25 tons of 
NO<INF>X</INF> per ozone season. The calculated emissions for each 
ozone season shall be determined using either the maximum rated heat 
input methodology described in paragraph (c)(3)(i) of this section or 
the long term fuel flow heat input methodology described in paragraph 
(c)(3)(ii) of this section, in conjunction with the appropriate 
NO<INF>X</INF> emission rate from paragraph (c)(1)(ii) or (c)(1)(iv) of 
this section.
    (ii) When the three full years (or, if applicable, three full ozone 
seasons) of actual, historical SO<INF>2</INF> and/or NO<INF>X</INF> 
mass emissions data required under paragraph (a)(2)(i) of this section 
are not available, the designated representative may submit an 
application to use the low mass emissions excepted methodology based 
upon a combination of historical SO<INF>2</INF> and NO<INF>X</INF> mass 
emissions data and projected SO<INF>2</INF> and/or NO<INF>X</INF> mass 
emissions, totaling three years (or ozone seasons). Historical data 
must be used for any years (or ozone seasons) in which historical data 
exists and projected data should be used for any remaining future years 
(or ozone seasons). For example, if an Acid Rain Program unit commenced 
operation two years ago, the designated representative may submit 
actual, historical data for the previous two years and one year of 
projected emissions for the current calendar year or, for a new (or 
newly-affected) unit for which no actual historical data are available, 
the designated representative may submit three years of projected 
emissions, beginning with the current calendar year. Any actual or 
projected annual (or ozone season) emissions must demonstrate to the 
satisfaction of the Administrator that the unit will emit less than the 
applicable number of tons of SO<INF>2</INF> and/or NO<INF>X</INF> 
specified in paragraph (a)(1)(i)(A) of this section. Projected 
emissions shall be calculated using either the default emission rates 
in tables LM-1, LM-2, and LM-3 of this section, or, for NO<INF>X</INF> 
emission rate, a fuel-and-unit-specific NO<INF>X</INF> emission rate 
determined in accordance with the testing procedures in paragraph 
(c)(1)(iv) of this section, in conjunction with projections of unit 
operating hours or fuel type and fuel usage, according to one of the 
allowable calculation methodologies in paragraph (c) of this section.
    (b) * * *
    (1) Once a low mass emission unit has qualified for and has started 
using the low mass emissions excepted methodology, an annual 
demonstration is required, showing that the unit continues to emit no 
more than the applicable number of tons of SO<INF>2</INF> and/or 
NO<INF>X</INF> specified in paragraph (a)(1)(i)(A) of this section. The 
calculation methodology used for the annual demonstration shall be the 
same methodology, from paragraph (c) of this section, by which the unit 
initially qualified to use the low mass emissions excepted methodology. 
The annual demonstration will be based upon the emissions data which 
the Administrator used to determine whether the unit held sufficient 
allowances for the calendar year or ozone season.
    (2) If any low mass emission unit fails to provide the required 
annual demonstration under paragraph (b)(1) of this section, such that 
the calculated cumulative emissions for the unit exceed the applicable 
number of tons of SO<INF>2</INF> and/or NO<INF>X</INF> specified in 
paragraph (a)(1)(i)(A) of this section at the end of any calendar year 
or ozone season, then:
    (i) The low mass emission unit shall be disqualified from using the 
low mass emissions excepted methodology as of December 31 of the 
following calendar year (for sources that report emission data on a 
year-round basis) or as of December 31 of the calendar year in which 
the unit exceeds the number of tons of NO<INF>X</INF> specified in 
paragraph (a)(1)(i)(A)(3) of this section (for sources that report 
emission data only during the ozone season); and
    (ii) The owner or operator of the low mass emission unit shall 
install, certify, and report SO<INF>2</INF> (Acid Rain Program units 
only), NO<INF>X</INF>, and CO<INF>2</INF> (Acid Rain Program units 
only) emissions from monitoring systems that meet the requirements of 
Secs. 75.11, 75.12, and 75.13 by December 31 of the year after the unit 
exceeded the number of tons of SO<INF>2</INF> and/or NO<INF>X</INF> 
specified in paragraph (a)(1)(i)(A)(1) or paragraph (a)(1)(i)(A)(2) of 
this section (for sources that report emission data on a year-round 
basis) or by May 1 of the year after the unit exceeds the number of 
tons of NO<INF>X</INF> specified in paragraph (a)(1)(i)(A)(3) of this 
section (for sources that report emission data only during the ozone 
season). If the required monitoring systems have not been installed and 
certified by the applicable deadline, the owner or operator shall 
report the following values for each unit operating hour, beginning 
with the first operating hour after the deadline and continuing until 
the monitoring systems have been provisionally certified: the maximum 
hourly heat input for the unit, as defined in Sec. 72.2 of this 
chapter; the SO<INF>2</INF> emissions, in lb/hr, calculated using the 
applicable default SO<INF>2</INF> emission rate in Table LM-1 in this 
section and the maximum hourly unit heat input; the CO<INF>2</INF> 
emissions, in tons/hr, calculated using the applicable default CO<INF>2</INF> 
emission rate in Table LM-3 in this section and the maximum hourly unit 
heat input; and the fuel-specific maximum potential NO<INF>X</INF> 
emission rate, as defined in Sec. 72.2 of this chapter.
    (3) If a low mass emission unit that initially qualifies to use the 
low mass emissions excepted methodology under this section changes 
fuels, such that a fuel other than those allowed for use in the low 
mass emissions methodology (i.e., natural gas, diesel fuel, or residual 
oil) is combusted in the unit, the unit shall be disqualified from 
using the low mass emissions excepted methodology as of the first hour 
that the new fuel is combusted in the unit. The owner or operator shall 
install, certify, and report SO<INF>2</INF> (Acid Rain Program units 
only), NO<INF>X</INF>, and CO<INF>2</INF> (Acid Rain Program units 
only) from monitoring systems that meet the requirements of 
Secs. 75.11, 75.12, and 75.13 prior to a change to such fuel. If the 
required monitoring systems are not installed and certified prior to 
the fuel switch, the owner or operator shall report (as applicable) the 
maximum potential concentration of SO<INF>2</INF>, CO<INF>2</INF> and 
NO<INF>X</INF>, the maximum potential NO<INF>X</INF> emission rate, the 
maximum potential flowrate, the maximum potential hourly heat input and 
the maximum (or minimum, if appropriate) potential moisture percentage, 
from the date and hour of the fuel switch until the monitoring systems 
are certified or until probationary calibration error tests of the 
monitors are passed and the conditional data validation procedures in 
Sec. 75.20(b)(3) begin to be used. All maximum and minimum potential 
values shall be specific to the new fuel and shall be determined in a 
manner consistent with section 2 of appendix A to this part and 
Sec. 72.2 of this chapter. The owner or operator must notify the 
Administrator (or the permitting authority) in the case where a unit 
switches fuels without previously having installed and certified a 
SO<INF>2</INF>,

[[Page 32007]]

 NO<INF>X</INF> and CO<INF>2</INF> monitoring system meeting the 
requirements of Secs. 75.11, 75.12, and 75.13.
* * * * *
    (c) * * *
    (1) * * *
    (iv) * * * 
    (A) Except as otherwise provided in this paragraph or in paragraphs 
(c)(1)(iv)(F) and (G) of this section, determine a fuel-and-unit-
specific NO<INF>X</INF> emission rate by conducting a four load 
NO<INF>X</INF> emission rate test procedure as specified in section 2.1 
of appendix E to this part, for each type of fuel combusted in the 
unit. For a group of units sharing a common fuel supply, the appendix E 
testing must be performed on each individual unit in the group, unless 
some or all of the units in the group belong to an identical group of 
units, as defined in paragraph (c)(1)(iv)(B) of this section, in which 
case, representative testing may be conducted on units in the identical 
group of units, as described in paragraph (c)(1)(iv)(B) of this 
section. For a unit or group of identical units that qualify under 
Sec. 75.19(c)(1)(iv)(I), single load testing is allowed in lieu of the 
four load testing. For the purposes of this section, make the following 
modifications to the appendix E test procedures:
    (1) Do not measure the heat input as required under section 2.1.3 
of appendix E to this part.
    (2) Do not plot the test results as specified under section 2.1.6 
of appendix E to this part.
    (3) When using method 20 for turbines do not correct the 
NO<INF>X</INF> concentration to 15 percent O<INF>2</INF>.
    (4) If the test is performed on an uncontrolled diffusion flame 
turbine (i.e., any turbine not using dry low NO<INF>X</INF> lean 
premixed combustion technology or any turbine without steam or water 
injection) a correction to the observed average NO<INF>X</INF> 
concentration from each run of the Method 20 test must be applied using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TP13JN01.000

    Where:

NO<INF>X</INF><INF>corr</INF> = Corrected NO<INF>X</INF> concentration 
(ppm).
NO<INF>X</INF><INF>obs</INF> = Average measured NO<INF>X</INF> 
concentration for each run of the Method 20 test (ppm).
P<INF>r</INF> = Average annual atmospheric pressure (or average ozone 
season atmospheric pressure for a subpart H unit that reports data only 
during the ozone season) at the nearest weather station (e.g., a 
standardized NOAA weather station located at the airport) for the year 
(or ozone season) prior to the year of the test (in Hg).
P<INF>o</INF> = Observed atmospheric pressure during the test run (in 
Hg).
H<INF>r</INF> = Average annual atmospheric humidity ratio (or average 
ozone season humidity ratio for a subpart H unit that reports data only 
during the ozone season) at the nearest weather station, for the year 
(or ozone season) prior to the year of the test (lb moisture/lb air).
H<INF>o</INF> = Observed humidity ratio during the test run (lb 
moisture/lb air).
T<INF>r</INF> = Average annual atmospheric temperature (or average 
ozone season atmospheric temperature for a subpart H unit that reports 
data only during the ozone season) at the nearest weather station, for 
the year (or ozone season) prior to the year of the test ( deg.R).
T<INF>a</INF> = Observed atmospheric temperature during the test run 
( deg.R).
    (B) * * *
* * * * *
    (C) Based on the results of the part 75 appendix E testing, 
determine the fuel-and-unit-specific NO<INF>X</INF> emission rate as 
follows:
    (1) If a four-load test is performed for an individual low mass 
emission unit with no NO<INF>X</INF> emissions controls of any kind or 
for a turbine with water injection, steam injection, or water/fuel 
emulsion and no other type of add-on NO<INF>X</INF> controls, the 
highest three run average NO<INF>X</INF> emission rate obtained at any 
load in the part 75 appendix E test for a particular type of fuel shall 
be the fuel-and-unit-specific NO<INF>X</INF> emission rate, for that 
type of fuel.
    (2) [Reserved]
    (3) If representative four-load testing is performed according to 
paragraph (c)(1)(iv)(B)(2) of this section for a group of identical low 
mass emission units with no NO<INF>X</INF> controls of any kind on any 
of the units, or for a group of identical turbines with water 
injection, steam injection, or water/fuel emulsion on all units and no 
other type of add-on NO<INF>X</INF> controls, the fuel-and-unit-
specific NO<INF>X</INF> emission rate for all units in the group, for a 
particular type of fuel, shall be the highest three run average 
NO<INF>X</INF> emission rate obtained at any load from any unit tested 
in the group, for that type of fuel.
    (4) If a four-load test is performed for an individual low mass 
emission unit which has add-on NO<INF>X</INF> emission controls (except 
for a turbine that uses water injection, steam injection, or water/fuel 
emulsion and has no other type of add-on NO<INF>X</INF> controls), the 
fuel-and-unit-specific NO<INF>X</INF> emission rate for each type of 
fuel combusted in the unit shall be the higher of:
    (i) The highest emission rate from any load of the appendix E test 
for that type of fuel; or
    (ii) 0.15 lb/mmBtu.
    (5) [Reserved]
    (6) If representative four-load testing is performed according to 
paragraph (c)(1)(iv)(B)(2) of this section for a group of identical low 
mass emission units having identical add-on NO<INF>X</INF> controls 
(except for a group of identical turbines with water injection, steam 
injection, or water fuel emulsion and no other type of add-on 
NO<INF>X</INF> controls), the fuel-and-unit-specific NO<INF>X</INF> 
emission rate for each unit in the group of units, for a particular 
type of fuel, shall be the higher of:
    (i) The highest NO<INF>X</INF> emission rate from all appendix E 
tests of all tested units in the group, for that type of fuel; or
    (ii) 0.15 lb/mmBtu.
    (7) If a single-load test is performed according to 
Sec. 75.19(c)(1)(iv)(I) for an individual low mass emission unit with 
no NO<INF>X</INF> emissions controls of any kind or for a turbine with 
water injection, steam injection, or water/fuel emulsion and no other 
type of add-on NO<INF>X</INF> controls, the fuel-and-unit-specific 
NO<INF>X</INF> emission rate for a particular type of fuel combusted in 
the unit shall be either:
    (i) The three run average NO<INF>X</INF> emission rate obtained in 
the appendix E test for that type of fuel; or
    (ii) For an uncontrolled turbine which is tested only at base load 
and which is capable of operating at a higher load or higher internal 
operating temperature, the three run average NO<INF>X</INF> emission 
rate obtained in the appendix E tests for that type of fuel, multiplied 
by 1.15.
    (8) If representative single-load testing is performed according to 
Sec. 75.19(c)(1)(iv)(I) for a group of identical low mass emission 
units with no NO<INF>X</INF> controls of any kind on any of the units, 
or an identical group of turbines with water injection, steam

[[Page 32008]]

injection, or water/fuel emulsion and no other type of add-on 
NO<INF>X</INF> controls, the fuel-and-unit-specific NO<INF>X</INF> 
emission rate for all units in the group, for a particular type of fuel 
shall be:
    (i) The highest three run average NO<INF>X</INF> emission rate 
obtained for that type of fuel in any of the appendix E tests; or
    (ii) For a group of uncontrolled turbines which are tested only at 
base load and which are capable of operating at a higher peak load or 
higher internal operating temperature, the highest three run average 
NO<INF>X</INF> emission rate obtained in any of the appendix E tests 
for that type of fuel, multiplied by 1.15.
* * * * *
    (G) Low mass emission units for which at least 3 years of quality-
assured NO<INF>X</INF> emission rate data from a NO<INF>X</INF>-diluent 
CEMS and corresponding fuel usage data are available may determine 
fuel-and-unit-specific NO<INF>X</INF> emission rates from the actual 
data using the following procedure. * * * Use the 95th percentile value 
for each data set as the fuel-and-unit-specific NO<INF>X</INF> emission 
rate, except that for a unit with add-on NO<INF>X</INF> emission 
controls (excluding turbines with water injection, steam injection, or 
water/fuel emulsion and no other type of add-on NO<INF>X</INF> 
controls), if the 95th percentile value is less than 0.15 lb/mmBtu, a 
value of 0.15 lb/mmBtu shall be used as the fuel-and-unit-specific 
NO<INF>X</INF> emission rate.
* * * * *
    (I) Notwithstanding the requirements in paragraph (c)(1)(iv)(A) of 
this section, for a unit (or group of identical units) with no 
NO<INF>X</INF> controls of any kind or for a turbine (or group of 
identical turbines) with water injection, steam injection, water/fuel 
emulsion, and no other type of add-on NO<INF>X</INF> controls, single-
load appendix E testing at the normal operating load may be performed 
instead of a four load test, if the unit has operated (or if all units 
in the group of identical units have operated) at a single load level 
for at least 85.0 percent of all operating hours in the previous three 
years (12 calendar quarters) prior to the calendar quarter of the 
appendix E test. To determine whether a unit qualifies for single-load 
testing, proceed as follows. Determine the range of operation of the 
unit, according to section 6.5.2.1 of appendix A to this part. Divide 
the range of operation into four equal load bands. For example, if the 
range of operation extends from 20 MW to 100 MW, the four equal load 
bands would be: band #1: 20 MW to 40 MW; band #2: 41 MW to 60 MW; band 
#3: 61 MW to 80 MW; and band #4: 81 to 100 MW. Then, perform a 
historical load analysis for all unit operating hours in the 12 
calendar quarters preceding the quarter of the test. Determine the 
percentage of the data that fall in each load band. For a unit which is 
not part of a group of identical units, if 85.0 percent or more of the 
data fall within one load band, this is the normal load level for the 
unit and single-load testing may be performed at any point within that 
load band. For a group of identical units, if each unit in the group 
meets the 85.0 percent criterion, then representative single-load 
testing within the normal load band(s) may be performed. For combustion 
turbines that are operated to produce approximately constant output (in 
MW) but which use internal operating and exhaust temperatures and not 
the actual output in MW to control operation of the turbine, the 
internal operating temperature setpoint may be used as a surrogate for 
load in demonstrating that the unit qualifies for single-load testing. 
To qualify for single load testing, the owner or operator must document 
that the unit has operated within <plus-minus>10 percent of the 
setpoint temperature for 85.0 percent of the unit operating hours in 
the previous 12 calendar quarters. If the setpoint temperature rather 
than unit load is used to justify single-load testing, the designated 
representative must certify in the monitoring plan for the unit that 
this is the manner of operation and must document the setpoint 
temperature. If the unit normally operates at a base load setpoint 
temperature but is capable of operating in a higher output peak load 
when demand requires, then the test must either be performed at peak 
load or a multiplier of 1.15 shall be used to adjust a base load test 
result to approximate a peak load test result.
* * * * *
    (3) * * *
    (i) * * *
    (B) * * *
    [GRAPHIC] [TIFF OMITTED] TP13JN01.030
    
Where:

n = Number of unit operating hours in the quarter.
HI<INF>hr</INF> = Hourly heat input under paragraph (c)(3)(i)(A) of 
this section (mmBtu).
* * * * *
    (D) 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 heat input 
for the second calendar quarter of the year shall include only the heat 
input for the months of May and June, and the cumulative ozone season 
heat input shall be the sum of the quarterly heat input values for the 
second and third calendar quarters of the year.
    (ii) * * *
    (E) * * * 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 
heat input for the second calendar quarter of the year shall include 
only the heat input for the months of May and June. * * *
* * * * *
    (G) * * * 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 cumulative 
ozone season heat input shall be the sum of the quarterly heat input 
values for the second and third calendar quarters of the year.
    (H) For each low mass emission unit or each low mass emission unit 
in an identical group of units, the owner or operator shall determine 
the cumulative quarterly unit load in megawatts or thousands of pounds 
of steam per hour. 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 Equation 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.

[[Page 32009]]

[GRAPHIC] [TIFF OMITTED] TP13JN01.031

Where:

MW<INF>qtr</INF> = Sum of all unit operating loads recorded during the 
quarter by the unit (MW).
ST<INF>fuel-qtr</INF> = 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 (MW).
ST = Unit steam load for a particular unit operating hour (klb of 
steam/hr).

    (I) * * *
(Eq LM-8 for steam output) * * *
Where:

HI<INF>hr</INF> = Hourly heat input to the unit (mmBtu).
MW<INF>hr</INF> = Hourly operating load for the unit (MW).
ST<INF>hr</INF> = Hourly steam load for the unit (klb of steam/hr).

    (J) * * *
(Eq LM-8a for steam output) * * *
Where:

HI<INF>hr</INF> = Hourly heat input to the individual unit (mmBtu).
MW<INF>hr</INF> = Hourly operating load for the individual unit (MW).
ST<INF>hr</INF> = Hourly steam load for the individual unit (klb of 
steam/hr).
<greek-S>MW<INF>qtr</INF> all-units = Sum of the quarterly operating 
loads (from Eq. LM-5) for all units in the group (MW).
<greek-S>ST<INF>qtr</INF> all-units = Sum of the quarterly steam loads 
(from Eq. LM-6) for all units in the group (klb of steam/hr).

    (4) * * *
    (ii) * * *
    (A) * * *
(Eq LM-10) * * *
W<INF>NOX</INF> = Hourly NO<INF>X</INF> mass emissions (lbs).
EF<INF>NOX</INF> = Either the NO<INF>X</INF> emission factor from Table 
LM-2 of this section or the fuel- and unit-specific NO<INF>X</INF> 
emission rate determined under paragraph (c)(1)(iv) of this section 
(lb/mmBtu). * * *
* * * * *
    (C) * * * 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 ozone 
season NO<INF>X</INF> mass emissions for the unit shall be the sum of 
the quarterly NO<INF>X</INF> mass emissions, as determined under 
paragraph (c)(4)(ii)(B) of this section, for the second and third 
calendar quarters of the year.
* * * * *
    15. Section 75.20 is amended by:
    a. Revising paragraphs (b)(2), (b)(3)(i), (c)(2)(ii), (c)(2)(iii), 
(c)(4) introductory text, (c)(4)(i) through (iii), (g)(2), (h)(3), 
(h)(4) introductory text, (h)(4)(i) and (h)(4)(ii);
    b. In the first sentence of paragraph (a) by removing the words ``, 
which includes the automated data acquisition and handling system, and, 
where applicable, the CO<INF>2</INF> continuous emission monitoring 
system,'';
    c. In the first sentence of paragraph (a)(3) by revising the words 
``section for each continuous emission or opacity monitoring system or 
component thereof,'' to read ``section, each'', removing the words ``or 
component thereof'' after each of the two additional occurrences of the 
words ``opacity monitoring system'' in paragraph (a)(3), and adding the 
word ``conditional'' before the words ``data validation'' in the last 
sentence;
    d. In paragraph (a)(4)(iii) by removing each occurrence of the 
words ``or component thereof'', by adding the word ``conditional'' 
immediately before each occurrence of ``data validation'', and by 
removing the words ``, until the date and time that the owner or 
operator completes subsequently approved initial certification or 
recertification tests'' that appear at the end of the second sentence;
    e. In paragraph (a)(4)(iv) by removing the words ``or component 
thereof,'';
    f. In the first sentence of paragraph (a)(5)(i) by removing the 
words ``or component thereof'' and by adding the words ``(or, if the 
conditional data validation procedures in paragraphs (b)(3)(ii) through 
(b)(3)(ix) of this section are used, until a probationary calibration 
error test is passed following corrective actions in accordance with 
paragraph (b)(3)(ii) of this section)'' after the words ``successfully 
completed'';
    g. In paragraphs (b)(3)(iv)(A), (b)(3)(iv)(B), and (b)(3)(vii)(A) 
by revising each occurrence of the word ``consecutive'' to read 
``cumulative'';
    h. Revising the third and fourth sentences of paragraph (b)(5);
    i. Removing the second paragraph labeled (c)(1)(v) and paragraph 
(h)(4)(iii);
    j. Adding new paragraphs (c)(2)(iv) and (h)(5);
    k. In paragraph (d)(2)(iii) by removing the words ``or 
SO<INF>2</INF>-diluent'' in the third sentence and by adding the word 
``cumulative'' after ``168'' in the fifth sentence;
    l. In paragraph (d)(2)(v) by adding the words ``(or 720 hours in 
any ozone season, for sources that report emission data only during the 
ozone season, in accordance with Sec. 75.74(c))'' after the words ``one 
calendar year'' in the first sentence and by adding the words ``(or 
ozone season, as applicable)'' after the words ``per calendar year'' in 
the second sentence;
    m. In the third sentence of (d)(2)(vii) by adding the words ``, 
beginning with the letters ``LK'' (e.g., ``LK1,'' ``LK2,'' etc.)'' 
after the words ``replacement analyzer'' and by adding the word 
``shall'' before the word ``specify'';
    n. Adding a sentence to the end of paragraph (g)(1)(i);
    o. In paragraph (g)(5) by adding the words ``(or recertified)'' 
after the word ``certified'' in the first sentence, adding the words 
``or for disapproval of a recertification request'' and ``or denial of 
a recertification request'' after, respectively, the first and second 
occurrence of the words ``loss of certification'' in the second 
sentence, removing the word ``either'' from the second sentence, adding 
the words ``(or recertified)'' after the word ``certified'' in the 
final sentence; and
    p. In the last sentence of paragraph (h)(1) by adding the word 
``acceptable'' before the word ``water-to-fuel''.
    The revisions and additions read as follows:


Sec. 75.20  Initial certification and recertification procedures.

* * * * *
    (b) * * *
    (2) Notification of recertification test dates. The owner, operator 
or designated representative shall submit notice of testing dates for 
recertification under this paragraph as specified in 
Sec. 75.61(a)(1)(ii).
    (3) * * *
    (i) The owner or operator shall either use substitute data, 
according to the

[[Page 32010]]

standard missing data procedures in Secs. 75.33 through 75.37, or shall 
report emission data using a reference method or another monitoring 
system that has been certified or approved for use under this part, in 
the period extending from the hour of the replacement, modification or 
change made to a monitoring system that triggers the need to perform 
recertification testing until the hour of successful completion of all 
of the required recertification tests. Alternatively, if conditional 
data validation is used, as provided in paragraphs (b)(3)(ii) through 
(b)(3)(ix) of this section, the owner or operator shall either use 
substitute data or shall report data from a certified CEMS or reference 
method, beginning with the hour of the replacement, modification, or 
change made to the monitoring system until the hour in which a 
probationary calibration error test (according to paragraph (b)(3)(ii) 
of this section) is passed. Notwithstanding this requirement, if the 
replacement, modification, or change requiring recertification of the 
CEMS is such that the historical data stream is no longer 
representative (e.g., where the SO<INF>2</INF> concentration and stack 
flow rate change significantly after installation of a wet scrubber), 
the owner or operator shall substitute for missing data as follows, in 
lieu of using the standard missing data procedures in Secs. 75.33 
through 75.37: for a change that results in a significantly higher 
concentration or flow rate, substitute maximum potential values 
according to the procedures in paragraph (a)(5) of this section; or for 
a change that results in a significantly lower concentration or flow 
rate, substitute data using the standard missing data procedures. The 
owner or operator shall then use the initial missing data procedures in 
Sec. 75.31, beginning with the first hour of quality assured data 
obtained with the recertified monitoring system, unless otherwise 
provided by Sec. 75.34 for units with add-on emission controls. The 
first hour of quality-assured data for the recertified monitoring 
system shall either be the hour after all recertification tests have 
been completed or, if conditional data validation is used, the first 
quality-assured hour shall be determined in accordance with paragraphs 
(b)(3)(ii) through (b)(3)(ix) of this section.
* * * * *
    (5) Approval or disapproval of request for recertification. * * * 
In the event that a recertification application is disapproved, data 
from the monitoring system are invalidated and the applicable missing 
data procedures in Secs. 75.31 or 75.33 shall be used from the date and 
hour of receipt of the disapproval notice back to the hour of the 
adjustment or change to the CEMS that triggered the need for 
recertification testing or, if the conditional data validation 
procedures in paragraphs (b)(3)(ii) through (b)(3)(ix) of this section 
were used, back to the hour of the probationary calibration error test 
that began the recertification test period. Data from the monitoring 
system remain invalid until all required recertification tests have 
been passed or until a subsequent probationary calibration error test 
is passed, beginning a new recertification test period. * * *
    (c) * * *
    (2) * * *
    (ii) Relative accuracy test audits, as follows:
    (A) For a flow monitor installed on a peaking unit or bypass stack, 
a single-load RATA at the normal load level, as defined in section 
6.5.2.1(d) of appendix A to this part; or
    (B) For all other flow monitors, a RATA at each of the three load 
levels (or operational levels) corresponding to the three flue gas 
velocities described in section 6.5.2(a) of appendix A to this part;
    (iii) A bias test for the single-load flow RATA described in 
paragraph (c)(2)(ii)(A) of this section; and
    (iv) A bias test (or bias tests) for the 3-level flow RATA 
described in paragraph (c)(2)(ii)(B) of this section, at the following 
load or operational level(s):
    (A) At each load level designated as normal under section 
6.5.2.1(d) of appendix A to this part, for units that produce 
electrical or thermal output; or
    (B) At the operational level identified as normal in section 
6.5.2.1(d) of appendix A to this part, for units that do not produce 
electrical or thermal output.
* * * * *
    (4) For each CO<INF>2</INF> pollutant concentration monitor, each 
CO<INF>2</INF> monitoring system that uses an O<INF>2</INF> monitor to 
determine CO<INF>2</INF> concentration, and each diluent gas monitor 
used only to monitor heat input rate:
    (i) A 7-day calibration error test;
    (ii) A linearity check;
    (iii) A relative accuracy test audit, where, for an O<INF>2</INF> 
monitor used to determine CO<INF>2</INF> concentration, the CO<INF>2</INF> 
reference method shall be used for the RATA; and
* * * * *
    (g) * * *
    (1) * * *
    (i) * * * For orifice, nozzle, and venturi-type flowmeters, the 
results of primary element visual inspections and/or calibrations of 
the transmitters or transducers shall also be provided.
* * * * *
    (2) Initial certification, recertification, and QA testing 
notification. The designated representative shall provide initial 
certification testing notification, recertification testing 
notification, and routine periodic retesting notification for an 
excepted monitoring system under appendix E to this part as specified 
in Sec. 75.61. Initial certification testing notification, 
recertification testing notification, or periodic quality assurance 
testing notification is not required for an excepted monitoring system 
under appendix D to this part.
* * * * *
    (h) * * *
* * * * *
    (3) Approval of certification applications. The provisions for the 
certification application formal approval process in the introductory 
text of paragraph (a)(4) and in paragraphs (a)(4)(i), (ii), and (iv) of 
this section shall apply, except that ``continuous emission or opacity 
monitoring system'' shall be replaced with ``low mass emissions 
excepted methodology.'' Provisional certification status for the low 
mass emissions methodology begins when a complete certification 
application is received, and the methodology is considered to be 
certified either upon receipt of a written approval notice from the 
Administrator or, if such notice is not provided, at the end of the 
Administrator's 120 day review period. However, in contrast to CEM 
systems or appendix D and E monitoring systems, a provisionally 
certified or certified low mass emissions excepted methodology may not 
be used to report data under the Acid Rain Program or in a 
NO<INF>X</INF> mass emissions reduction program under subpart H of this 
part prior to the applicable commencement date specified in 
Sec. 75.19(a)(1)(ii).
    (4) Disapproval of low mass emissions unit certification 
applications. If the Administrator determines that the certification 
application for a low mass emissions unit does not demonstrate that the 
unit meets the requirements of Secs. 75.19(a) and (b), the 
Administrator shall issue a written notice of disapproval of the 
certification application within 120 days of receipt. By issuing the 
notice of disapproval, the provisional certification is invalidated by 
the Administrator, and any emission data reported using the excepted 
methodology during the Administrator's 120-day review period shall be 
considered invalid. The owner or operator shall use the following

[[Page 32011]]

procedures when a certification application is disapproved:
    (i) The owner or operator shall substitute the following values, as 
applicable, for each hour of unit operation in which data were reported 
using the low mass emissions methodology until such time, date, and 
hour as continuous emission monitoring systems or excepted monitoring 
systems, where applicable, are installed and provisionally certified: 
the maximum potential concentration of SO<INF>2</INF>, as defined in 
section 2.1.1.1 of appendix A to this part; the maximum potential fuel 
flowrate, as defined in section 2.4.2 of appendix D to this part; the 
maximum potential values of fuel sulfur content, GCV, and density (if 
applicable) in Table D-6 of appendix D to this part; the maximum 
potential NO<INF>X</INF> emission rate, as defined in Sec. 72.2 of this 
chapter; the maximum potential flow rate, as defined in section 2.1.4.1 
of appendix A to this part; or the maximum potential CO<INF>2</INF> 
concentration as defined in section 2.1.3.1 of appendix A to this part. 
For a unit subject to a State or federal NO<INF>X</INF> mass reduction 
program where the owner or operator intends to monitor NO<INF>X</INF> 
mass emissions with a NO<INF>X</INF> pollutant concentration monitor 
and a flow monitoring system, substitute for NO<INF>X</INF> 
concentration using the maximum potential concentration of 
NO<INF>X</INF>, as defined in section 2.1.2.1 of appendix A to this 
part, and substitute for volumetric flow using the maximum potential 
flow rate, as defined in section 2.1.4.1 of appendix A to this part; 
and
    (ii) The designated representative shall submit a notification of 
certification test dates for the required monitoring systems, as 
specified in Sec. 75.61(a)(1)(ii), and shall submit a certification 
application according to the procedures in paragraph (a)(2) of this 
section.
    (5) Recertification. Recertification of an approved low mass 
emissions excepted methodology is not required. Once the Administrator 
has approved the methodology for use, the owner or operator is subject 
to the on-going qualification and disqualification procedures in 
Sec. 75.19(b)(1), on an annual basis.


Sec. 75.21  [Amended].

    16. Section 75.21 is amended by:
    a. In paragraph (a)(7) by adding the words ``only for infrequent, 
non-routine operation (e.g.,'' after the words ``higher sulfur 
fuel(s)'' in the first sentence, by adding a closing parenthesis after 
the words ``short-term testing'' in the first sentence, and by revising 
in the last sentence the words ``720 unit (or stack) operating hour 
grace period'' to read ``grace period of 720 cumulative unit or stack 
operating hours'';
    b. In paragraph (a)(8) by removing the words ``On and after April 
1, 2000'' and by capitalizing the initial occurrence of the word 
``the'';
    c. In paragraph (a)(9) by revising in the first sentence the words 
``exempted under paragraphs (a)(6) or (a)(7) of this section from the 
SO<INF>2</INF> RATA requirements of this part'' to read ``exempted from 
the SO<INF>2</INF> RATA requirements of this part under paragraphs 
(a)(6) or (a)(7) of this section'', and by revising in the last 
sentence the words ``720 unit (or stack) operating hour grace period'' 
to read ``grace period of 720 cumulative unit or stack operating 
hours''; and
    d. In paragraph (e)(2) by removing the word ``another''.
    17. Section 75.22 is amended by:
    a. Removing the last sentence of paragraph (a) introductory text;
    b. In the last sentence of paragraph (a)(4) by revising the word 
``techniques'' to read ``wet bulb-dry bulb technique''; and
    c. Adding a sentence to the end of paragraph (a)(5).
    The revisions and additions read as follows:


Sec. 75.22  Reference test methods.

    (a) * * *
    (5) * * * Alternatively, Method 20 may be used as the reference 
method for relative accuracy test audits of NO<INF>X</INF> CEMS 
installed on combustion turbines.
* * * * *
    18. Section 75.24 is amended by:
    a. Revising paragraph (a)(1); and
    b. In paragraph (c)(2) by removing the words ``or certified 
portable monitor or''.
    The revisions read as follows:


Sec. 75.24  Out-of-control periods and adjustment for system bias.

    (a) * * *
    (1) For daily calibration error tests, an out-of-control period 
occurs when the calibration error of a pollutant concentration monitor 
exceeds the applicable specification in section 2.1.4 of appendix B to 
this part.
* * * * *
    19. Section 75.30 is amended by:
    a. In paragraph (a)(6) by removing the period at the end of the 
paragraph and replacing it with ``; or'';
    b. Adding new paragraphs (a)(7) and (a)(8);
    c. In the first sentence of paragraph (b) by adding the words 
``percent moisture,'' after the words ``flow rate,''; and
    d. In paragraphs (d)(1) and (d)(2) by removing the words 
``Sec. 75.54(b)(5) or'' and the words ``as applicable,''.
    The revisions and additions read as follows:


Sec. 75.30  General provisions.

    (a) * * *
    (7) A valid, quality-assured hour of moisture data (in percent 
H<INF>2</INF>O) has not been measured or recorded for an affected unit, 
either by a certified moisture monitoring system or an approved 
alternative monitoring method under subpart E of this part. This 
requirement does not apply when a default percent moisture value, as 
provided in Secs. 75.11(b) or 75.12(b), is used to account for the 
hourly moisture content of the stack gas; or
    (8) A valid, quality-assured hour of heat input rate data (in 
mmBtu/hr) has not been measured and recorded for a unit from a 
certified flow monitor and a certified diluent (CO<INF>2</INF> or 
O<INF>2</INF>) monitor or by an approved alternative monitoring system 
under subpart E of this part.
* * * * *
    20. Section 75.31 is amended by:
    a. Revising the first sentence of paragraph (a);
    b. Revising paragraphs (c) introductory text and (c)(1);
    c. Adding a new sentence to the beginning of paragraph (c)(2);
    d. In paragraph (c)(3) by adding the words ``(or for non-load-based 
units using operational bins, when no prior quality-assured data exist 
in the corresponding operational bin)'' after the words ``higher load 
range''; and
    e. Adding a new paragraph (d).
    The revisions and additions read as follows:


Sec. 75.31  Initial missing data procedures.

    (a) During the first 720 quality-assured monitor operating hours 
following initial certification of the required SO<INF>2</INF>, 
CO<INF>2</INF>, O<INF>2</INF> or moisture monitoring system(s) at a 
particular unit or stack location (i.e., the date and time at which 
quality assured data begins to be recorded by CEMS(s) installed at that 
location), and during the first 2,160 quality-assured monitor operating 
hours following initial certification of the required NO<INF>X</INF>-
diluent, NO<INF>X</INF> concentration, or flow monitoring system(s) at 
the unit or stack location, the owner or operator shall provide 
substitute data required under this subpart according to the procedures 
in paragraphs (b) and (c) of this section. * * *
* * * * *
    (c) Volumetric flow and NO<INF>X</INF> emission rate or 
NO<INF>X</INF> concentration data (load ranges or operational bins 
used). The procedures in this paragraph apply to affected units for 
which load-based

[[Page 32012]]

ranges or non-load-based operational bins, as defined, respectively, in 
sections 2 and 3 of appendix C to this part are used to provide 
substitute NO<INF>X</INF> and flow rate data. For each hour of missing 
volumetric flow rate data, NO<INF>X</INF> emission rate data, or 
NO<INF>X</INF> concentration data used to determine NO<INF>X</INF> mass 
emissions:
    (1) Whenever prior quality-assured data exist in the load range (or 
operational bin) corresponding to the operating load (or operating 
conditions) at the time of the missing data period, the owner or 
operator shall substitute, by means of the automated data acquisition 
and handling system, for each hour of missing data, the arithmetic 
average of all of the prior quality-assured hourly flow rates, 
NO<INF>X</INF> emission rates, or NO<INF>X</INF> concentrations in the 
corresponding load range (or operational bin) as determined using the 
procedure in appendix C to this part. When non-load-based operational 
bins are used, if essential operating or parametric data are 
unavailable for any hour in the missing data period, such that the 
operational bin cannot be determined, the owner or operator shall, for 
that hour, substitute (as applicable) the maximum potential flow rate 
as specified in section 2.1.4.1 of appendix A to this part or the 
maximum potential NO<INF>X</INF> emission rate or the maximum potential 
NO<INF>X</INF> concentration as specified in section 2.1.2.1 of 
appendix A to this part.
    (2) This paragraph (c)(2) does not apply to non-load-based units 
using operational bins. * * *
* * * * *
    (d) Non-load-based volumetric flow and NO<INF>X</INF> emission rate 
or NO<INF>X</INF> concentration data (operational bins not used). The 
procedures in this paragraph apply only to affected units that do not 
produce electrical output (in megawatts) or thermal output (in klb/hr 
of steam) and for which operational bins are not used. For each hour of 
missing volumetric flow rate data, NO<INF>X</INF> emission rate data, 
or NO<INF>X</INF> concentration data used to determine NO<INF>X</INF> 
mass emissions:
    (1) Whenever prior quality-assured data exist at the time of the 
missing data period, the owner or operator shall substitute, by means 
of the automated data acquisition and handling system, for each hour of 
missing data, the arithmetic average of all of the prior quality-
assured hourly average flow rates or NO<INF>X</INF> emission rates or 
NO<INF>X</INF> concentrations.
    (2) Whenever no prior quality-assured flow rate, NO<INF>X</INF> 
emission rate, or NO<INF>X</INF> concentration data exist, the owner or 
operator shall, as applicable, substitute for each hour of missing 
data, the maximum potential flow rate as specified in section 2.1.4.1 
of appendix A to this part or the maximum potential NO<INF>X</INF> 
emission rate or the maximum potential NO<INF>X</INF> concentration as 
specified in section 2.1.2.1 of appendix A to this part.
    21. Section 75.32 is amended by:
    a. Revising paragraph (a) introductory text;
    b. In paragraph (a)(1) by adding the words ``or stack'' after the 
word ``unit'' and revising the word ``equation'' to read ``Equation''; 
and
    c. Revising paragraph (a)(2) and the first three sentences of 
paragraph (a)(3).
    The revisions and additions read as follows:


Sec. 75.32  Determination of monitor data availability for standard 
missing data procedures.

    (a) Following initial certification of the required SO<INF>2</INF>, 
CO<INF>2</INF>, O<INF>2</INF> or moisture monitoring system(s) at a 
particular unit or stack location (i.e., the date and time at which 
quality assured data begins to be recorded by CEMS(s) at that 
location), the owner or operator shall, upon completion of the first 
720 quality-assured monitor operating hours, calculate and record, by 
means of the automated data acquisition and handling system, the 
percent monitor data availability for the SO<INF>2</INF> pollutant 
concentration monitor, the CO<INF>2</INF> pollutant concentration 
monitor, the O<INF>2</INF> or CO<INF>2</INF> diluent monitor used to 
calculate heat input, and the moisture monitoring system (as 
applicable). Similarly, following initial certification of the required 
NO<INF>X</INF>-diluent, NO<INF>X</INF> concentration, or flow 
monitoring system(s) at a unit or stack location, the owner or operator 
shall, upon completion of the first 2,160 quality-assured monitor 
operating hours, calculate and record, by means of the automated data 
acquisition and handling system, the percent monitor data availability 
for the flow monitor, the NO<INF>X</INF>-diluent monitoring system, and 
the NO<INF>X</INF> concentration monitoring system (as applicable). 
Notwithstanding these requirements, if three years (26,280 clock hours 
) have elapsed since the date and hour of initial certification and 
fewer than 720 (or 2,160, as applicable) quality-assured monitor 
operating hours have been recorded, the owner or operator shall begin 
calculating and recording the percent monitor data availability. The 
percent monitor data availability shall be calculated for each 
monitored parameter at each unit or stack location, as follows:
* * * * *
    (2) Upon completion of 8,760 unit or stack operating hours 
following initial certification and thereafter, the owner or operator 
shall, for the purpose of applying the standard missing data procedures 
of Sec. 75.33, use Equation 9 to calculate, hourly, percent monitor 
data availability. Notwithstanding this requirement, if three years 
(26,280 clock hours) have elapsed since initial certification and fewer 
than 8,760 unit or stack operating hours have been accumulated, the 
owner or operator shall begin using a modified version of Equation 9, 
as described in paragraph (a)(3) of this section.
[GRAPHIC] [TIFF OMITTED] TP13JN01.032

    (3) When calculating percent monitor data availability using 
Equation 8 or 9, the owner or operator shall include all unit operating 
hours, and all monitor operating hours for which quality-assured data 
were recorded by a certified primary monitor; a certified redundant or 
non-redundant backup monitor or a reference method for that unit; or by 
an approved alternative monitoring system under subpart E of this part. 
No hours from more than three years (26,280 clock hours) earlier shall 
be used in Equation 9. For a unit that has accumulated fewer than 8,760 
unit or stack operating hours in the previous three years (26,280 clock 
hours), use the words ``in the previous three years'' instead of 
``during previous 8,760 unit or stack operating hours'' in Equation 9, 
and use ``total unit or stack operating

[[Page 32013]]

hours in the previous three years'' instead of ``8,760.'' * * *
* * * * *
    22. Section 75.33 is amended by:
    a. Revising paragraphs (a) and (c) introductory text;
    b. Adding paragraphs (b)(5), (b)(6), (b)(7), (c)(7), (c)(8), 
(c)(9), (c)(10), (d), and (e);
    c. In paragraphs (c)(1) introductory text and (c)(2) introductory 
text by removing the words ``or continuous emission monitoring 
system'';
    d. In paragraphs (c)(1)(i), (c)(1)(ii)(A), (c)(2)(i), 
(c)(2)(ii)(A), and (c)(3) by adding the words ``or operational bin'' 
after each occurrence of the words ``unit load range'';
    e. In paragraph (c)(3) by removing the words ``section 2 of'';
    f. In paragraph (c)(4) by adding a sentence to the end of the 
paragraph;
    g. In paragraph (c)(5) by adding a new first sentence and by adding 
the words ``recording during the previous 2,160 quality-assured monitor 
operating hours'' before the words ``at the next'';
    h. In paragraph (c)(6) by revising the words ``or a higher load 
range'' to read ``(or a higher load range) or for the corresponding 
operational bin''; and
    i. Redesignating Tables 1 and 2 from paragraph to follow paragraph 
(c)(9) and revising them.
    The revisions and additions read as follows:


Sec. 75.33  Standard missing data procedures for SO<INF>2</INF>, 
NO<INF>X</INF> and flow rate.

    (a) Following initial certification of the required SO<INF>2</INF>, 
NO<INF>X</INF>, and flow rate monitoring system(s) at a particular unit 
or stack location (i.e., the date and time at which quality assured 
data begins to be recorded by CEMS(s) at that location) and upon 
completion of the first 720 quality-assured monitor operating hours 
(for SO<INF>2</INF> ) or the first 2,160 quality assured monitor 
operating hours (for flow, NO<INF>X</INF> emission rate, or 
NO<INF>X</INF> concentration), the owner or operator shall provide 
substitute data required under this subpart according to the procedures 
in paragraphs (b) and (c) of this section and depicted in Table 1 
(SO<INF>2</INF>) and Table 2 of this section ( NO<INF>X</INF>, flow). 
Notwithstanding these requirements, if three years (26,280 clock hours) 
have elapsed since the date and hour of initial certification, and 
fewer than 720 (or 2,160, as applicable) quality assured monitor 
operating hours have been recorded, the owner or operator shall begin 
using the missing data procedures of this section. The owner or 
operator of a unit shall substitute for missing data using quality-
assured monitor operating hours of data from no earlier than three 
years (26,280 clock hours) prior to the date and time of the missing 
data period.
    (b) * * *
    (5) The owner or operator may, for units that combust more than one 
type of fuel, elect to implement the missing data routines in 
paragraphs (b)(1) through (b)(4) of this section on a fuel-specific 
basis. If this option is selected, the owner or operator shall document 
this in the monitoring plan required under Sec. 75.53. To implement 
this option, the owner or operator shall create and maintain a separate 
SO<INF>2</INF> concentration database for each type of fuel (or blend), 
in order to obtain the appropriate substitute data values when that 
fuel (or blend) is combusted. Also, for the purposes of providing 
substitute data under paragraph (b)(4) of this section, a separate, 
fuel-specific maximum potential SO<INF>2</INF> concentration (MPC) 
value shall be determined for each type of fuel (or blend) combusted in 
the unit, in a manner consistent with section 2.1.1.1 of appendix A to 
this part. For fuel that qualifies as pipeline natural gas or natural 
gas (as defined in Sec. 72.2 of this chapter), the owner or operator 
shall, for the purposes of determining the MPC, either determine the 
maximum total sulfur content and minimum gross calorific value (GCV) of 
the gas by fuel sampling and analysis or shall use a default total 
sulfur content of 0.05 percent by weight (dry basis) and a default GCV 
value of 950 Btu/scf. The exact methodology used to determine each 
fuel-specific MPC value shall be documented in the monitoring plan for 
the unit or stack.
    (6) If the owner or operator elects to switch from non-fuel-
specific missing data routines to fuel-specific routines (as described 
in paragraph (b)(5) of this section) and if, at the time of the change, 
the initial missing data procedures of Sec. 75.31 have previously been 
completed on a non-fuel-specific basis and the calculation of percent 
monitor data availability and use of the standard missing data 
procedures has begun in accordance with Secs. 75.32 and 75.33, the 
owner or operator need not repeat the initial missing data procedures 
on a fuel-specific basis. Rather, the calculation of percent monitor 
data availability may continue uninterrupted, and the fuel-specific 
SO<INF>2</INF> concentration databases may be created prospectively, 
beginning at the time of the change. Alternatively, the databases may 
be created from historical CEM data, if records are available 
documenting the type of fuel combusted during each quality-assured 
monitor operating hour. If, at the time of the missing data period, 
there is at least one, but fewer than 720 quality-assured monitor 
operating hours of fuel-specific SO<INF>2</INF> concentration data in a 
particular database, use whatever data are in the database, for the 
purposes of the lookback periods described in Sec. 75.33, paragraphs 
(b)(1)(ii)(A), (b)(2)(ii)(A), and (b)(3). If there are no quality-
assured monitor operating hours of fuel-specific SO<INF>2</INF> 
concentration data in a particular database, report the fuel-specific 
MPC value determined under paragraph (b)(5) of this section for each 
hour of the missing data period.
    (7) Table 1 of this section summarizes the provisions of paragraphs 
(b)(1) through (b)(6) of this section.
    (c) Volumetric flow rate, NO<INF>X</INF> emission rate and NO<INF>X</INF> 
concentration data. Use the procedures in this paragraph to provide 
substitute NO<INF>X</INF> and flow rate data for all affected units for 
which load-based ranges have been defined in accordance with section 2 
of appendix C to this part. For units that do not produce electrical or 
thermal output (i.e., non-load-based units), use the procedures in this 
paragraph only to provide substitute data for volumetric flow rate, and 
only if operational bins have been defined for the unit, as described 
in section 3 of appendix C to this part. Otherwise, use the applicable 
missing data procedures in paragraph (d) or (e) of this section for 
non-load-based units. For each hour of missing volumetric flow rate 
data, NO<INF>X</INF> emission rate data, or NO<INF>X</INF> 
concentration data used to determine NO<INF>X</INF> mass emissions:
* * * * *
    (4) * * * In addition, when non-load-based operational bins are 
used, the owner or operator shall substitute (as applicable) the 
maximum potential flow rate for any hour in the missing data period in 
which essential operating or parametric data are unavailable and the 
operational bin cannot be determined.
    (5) This paragraph does not apply to non-load-based affected units 
using operational bins. * * *
* * * * *
    (7) If there are fewer than 2,160 quality-assured monitor operating 
hours in a load range or operational bin, use whatever data are in the 
load range or bin for purposes of the lookback periods described in 
paragraphs (c)(1)(i), (c)(1)(ii)(A), (c)(2)(i), (c)(2)(ii)(A), (c)(3), 
and (c)(5) of this section.
    (8) This paragraph (c) (8) does not apply to affected units using 
non-load-based operational bins. The owner or operator may, for units 
that combust more than one type of fuel, elect to implement the missing 
data routines in paragraphs (c)(1) through (c)(7) of this section on a 
fuel-specific basis. If this option is selected, the owner or operator

[[Page 32014]]

shall document this in the monitoring plan required under Sec. 75.53. 
To implement this option, the owner or operator shall (as applicable) 
create and maintain a separate flow rate, NO<INF>X</INF> emission rate, 
or NO<INF>X</INF> concentration database for each type of fuel, in 
order to obtain the appropriate substitute data values when that fuel 
is combusted. Also, for the purposes of providing substitute data under 
paragraph (c)(4) of this section, a separate, fuel-specific maximum 
potential concentration (MPC), maximum potential NO<INF>X</INF> 
emission rate (MER), or maximum potential flow rate (MPF) value (as 
applicable) shall be determined for each type of fuel combusted in the 
unit, in a manner consistent with section 2.1.2.1 or 2.1.4.1 of 
appendix A to this part. The exact methodology used to determine each 
fuel-specific MPC, MPF, or MER value shall be documented in the 
monitoring plan for the unit or stack.
    (9) This paragraph (c)(9) does not apply to affected units using 
non-load-based operational bins. If the owner or operator elects to 
switch from non-fuel-specific missing data routines to fuel-specific 
routines (as described in paragraph (b)(8) of this section) and if, at 
the time of the change, the initial missing data procedures of 
Sec. 75.31 have previously been completed on a non-fuel-specific basis 
and the calculation of percent monitor data availability and use of the 
standard missing data procedures has begun in accordance with 
Secs. 75.32 and 75.33, the owner or operator need not repeat the 
initial missing data procedures on a fuel-specific basis. Rather, the 
calculation of percent monitor data availability may continue 
uninterrupted, and the fuel-specific NO<INF>X</INF> or flow rate 
databases may be created prospectively, beginning at the time of the 
change. Alternatively, the databases may be created from historical CEM 
data, if records are available documenting the type of fuel combusted 
during each quality-assured monitor operating hour. If, at the time of 
the missing data period, there is at least one, but fewer than 2,160 
quality-assured monitor operating hours of fuel-specific NO<INF>X</INF> 
or flow rate data in a particular load range, use whatever data are in 
the load range, for the purposes of the lookback periods described in 
paragraphs (c)(1)(i), (c)(1)(ii)(A), (c)(2)(i), (c)(2)(ii)(A), and 
(c)(3) of this section. If there are no quality-assured monitor 
operating hours of fuel-specific NO<INF>X</INF> or flow rate data in a 
particular load range (or a higher range), report the appropriate fuel-
specific maximum potential value determined under paragraph 
(c)(2)(ii)(B)(8) of this section. Tables 1 and 2 follow:

Table 1.--Missing Data Procedure for SO<INF>2</INF> CEMS, CO<INF>2</INF> CEMS, Moisture CEMS and Diluent (CO<INF>2</INF> or O<INF>2</INF>) Monitors for Heat
                                               Input Determination
----------------------------------------------------------------------------------------------------------------
                     Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
     Monitor data availability        Duration (N) of CEMS
             (percent)                 outage  (hours) \2\              Method                Lookback period
----------------------------------------------------------------------------------------------------------------
95 or more.........................  N <ls-thn-eq> 24......  Average....................  \y\ HB/HA
                                     N > 24................  For SO<INF>2</INF>, CO<INF>2</INF>, and H<INF>2</INF>O**,     ......................
                                                              the greater of.
                                                             Average....................  HB/HA.
                                                             90th percentile \1\........  *720 hours.
                                                             For O<INF>2</INF> and H<INF>2</INF>O\x\, the       ......................
                                                              lesser of.
                                                             Average....................  HB/HA.
                                                             10th percentile............  *720 hours.
90 or more, but below 95...........  N <ls-thn-eq> 8.......  Average....................  \y\ HB/HA
                                     N > 8.................  For SO<INF>2</INF>, CO<INF>2</INF>, and H<INF>2</INF>O**,
                                                              the greater of:.
                                                             Average....................  HB/HA.
                                                             95th percentile \1\........  *720 hours.
                                                             For O<INF>2</INF> and H<INF>2</INF>O \x\, the
                                                              lesser of:.
                                                             Average....................  HB/HA.
                                                             5th percentile.............  *720 hours.
80 or more, but below 90...........  N > 0.................  For SO<INF>2</INF>, CO<INF>2</INF>, and H<INF>2</INF>O **,    *720 hours.
                                                              Maximum value \1\.
                                                             For O<INF>2</INF> and H<INF>2</INF>O \x\: Minimum  *720 hours.
                                                              value \1\.
Below 80...........................  N > 0.................  Maximum potential            None.
                                                              concentration \3\ or %
                                                              (for SO<INF>2</INF>, CO<INF>2</INF>, and H<INF>2</INF>O **)
                                                              or Minimum potential
                                                              concentration or % (for O<INF>2</INF>
                                                              and H<INF>2</INF>O \x\).
----------------------------------------------------------------------------------------------------------------
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 (or ozone seasons)
  prior to the missing data period.
\1\ For units with add-on SO<INF>2</INF> emission controls, the owner or operator may maintain separate databases of
  controlled and uncontrolled emissions and provide substitute data from the appropriate database according to
  whether the add-on controls are documented to be operating properly during the missing data period.
\2\ During unit operating hours.
\3\ For units with add-on SO<INF>2</INF> controls, you may (if available) report the SO<INF>2</INF> concentration from a certified
  inlet monitor, in lieu of reporting the MPC.
\X\ Use this algorithm for moisture except when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part
  60 of this chapter is used for NO<INF>X</INF> emission rate.
**Use this algorithm for moisture only when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of
  this chapter is used for NO<INF>X</INF> emission rate.
\y\ For units with add-on SO<INF>2</INF> controls, if the missing data procedures of Sec.  75.34(a)(2) are used, report the
  maximum SO<INF>2</INF> concentration in the previous 720 quality-assured monitor operating hours in the uncontrolled
  database in lieu of HB/HA average value, for each missing data hour in which the add-on controls are not
  documented to be operating properly.


[[Page 32015]]


        Table 2.--Missing Data Procedure for NO<INF>X</INF>-Diluent CEMS, NO<INF>X</INF> Concentration CEMS and Flow Rate CEMS
----------------------------------------------------------------------------------------------------------------
                 Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
                                   Duration (N) of                               Lookback
   Monitor data availability         CEMS outage              Method            period  (in       Load ranges
           (percent)                 (hours) \2\                                  hours)
----------------------------------------------------------------------------------------------------------------
95 or more.....................  N <ls-thn-eq> 24..  Average................            2160  Yes.
                                 N > 24............  The greater of:
                                                     Average................           HB/HA  No.
                                                     90th percentile........           *2160  Yes.
90 or more, but below 95.......  N <ls-thn-eq> 8...  Average................           *2160  Yes.
                                 N > 8.............  The greater of:
                                                     Average................           HB/HA  No.
                                                     95th percentile........           *2160  Yes.
80 or more, but below 90.......  N > 0.............  Maximum value \1\......           *2160  Yes.
Below 80.......................  N > 0.............  Maximum NO<INF>X</INF> emission               None  No.
                                                      rate; or maximum
                                                      potential NO<INF>X</INF>
                                                      concentration \3\; or
                                                      maximum potential flow
                                                      rate.
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
*Quality-assured, monitor operating hours, in the corresponding load range (``load bin'') for each hour of the
  missing data period. May be either fuel-specific or non-fuel-specific. If there are  2,160 hours of data in
  the load bin, use all data in the bin for the lookback. 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 (or ozone seasons) prior to the missing data period.
\1\ For units with add-on NO<INF>X</INF> emission controls, the owner or operator may maintain separate databases of
  controlled and uncontrolled emissions and provide substitute data from the appropriate database according to
  whether the add-on controls are documented to be operating properly during the missing data period.
\2\ During unit operating hours.
\3\ For units with add-on NO<INF>X</INF> controls, you may report the NO<INF>X</INF> concentration from a certified inlet monitor (if
  available) in lieu of reporting the MPC.

    (10) The load-based provisions of paragraphs (c)(1) through (c)(9) 
of this section are summarized in Table 2 of this section. The non-
load-based provisions for volumetric flow rate, found in paragraphs 
(c)(1) through (c)(4), (c)(6), and (c)(7) of this section, are 
presented in Table 4 of this section.
    (d) Non-load-based NO<INF>X</INF> emission rate and NO<INF>X</INF> 
concentration data. Use the procedures in this paragraph to provide 
substitute NO<INF>X</INF> data for affected units that do not produce 
electrical output (in megawatts) or thermal output (in klb/hr of 
steam). For each hour of missing NO<INF>X</INF> emission rate data, or 
NO<INF>X</INF> concentration data used to determine NO<INF>X</INF> mass 
emissions:
    (1) Whenever the monitor data availability is equal to or greater 
than 95.0 percent, the owner or operator shall calculate substitute 
data by means of the automated data acquisition and handling system for 
each hour of each missing data period according to the following 
procedures:
    (i) For a missing data period less than or equal to 24 hours, 
substitute, as applicable, for each missing hour, the arithmetic 
average of the NO<INF>X</INF> emission rates or NO<INF>X</INF> 
concentrations recorded by a monitoring system in a 2,160 hour lookback 
period. The lookback period may be comprised of either:
    (A) The previous 2,160 quality assured monitor operating hours, or
    (B) The previous 2,160 quality-assured monitor operating hours at 
the corresponding operational bin, if operational bins, as defined in 
section 3 of appendix C to this part, are used.
    (ii) For a missing data period greater than 24 hours, substitute, 
as applicable, for each missing hour, the greater of:
    (A) The 90th percentile NO<INF>X</INF> emission rate or the 90th 
percentile NO<INF>X</INF> concentration recorded by a monitoring system 
during the previous 2,160 quality assured monitor operating hours (or 
during the previous 2,160 quality-assured monitor operating hours at 
the corresponding operational bin, if operational bins are used), or
    (B) The arithmetic average of the hourly NO<INF>X</INF> emission 
rates or NO<INF>X</INF> concentrations recorded by a monitoring system 
during the previous 2,160 quality-assured monitor operating hours (or 
during the previous 2,160 quality-assured monitor operating hours at 
the corresponding operational bin, if operational bins are used).
    (2) Whenever the monitor data availability is at least 90.0 percent 
but less than 95.0 percent, the owner or operator shall calculate 
substitute data by means of the automated data acquisition and handling 
system for each hour of each missing data period according to the 
following procedures:
    (i) For a missing data period of less than or equal to eight hours, 
substitute, as applicable, the arithmetic average of the hourly 
NO<INF>X</INF> emission rates or NO<INF>X</INF> concentrations recorded 
by a monitoring system during the previous 2,160 quality-assured 
monitor operating hours (or during the previous 2,160 quality-assured 
monitor operating hours at the corresponding operational bin, if 
operational bins are used).
    (ii) For a missing data period greater than eight hours, 
substitute, as applicable, for each missing hour, the greater of:
    (A) The 95th percentile hourly flow rate or the 95th percentile 
NO<INF>X</INF> emission rate or the 95th percentile NO<INF>X</INF> 
concentration recorded by a monitoring system during the previous 2,160 
quality-assured monitor operating hours (or during the previous 2,160 
quality-assured monitor operating hours at the corresponding 
operational bin, if operational bins are used), or
    (B) The arithmetic average of the hourly NO<INF>X</INF> emission 
rates or NO<INF>X</INF> concentrations recorded by a monitoring system 
during the previous 2,160 quality-assured monitor operating hours (or 
during the previous 2,160 quality-assured monitor operating hours at 
the corresponding operational bin, if operational bins are used).
    (3) Whenever the monitor data availability is at least 80.0 percent 
but less than 90.0 percent, the owner or operator shall, by means of 
the automated data acquisition and handling system, substitute, as 
applicable, for each hour of each missing data period, the maximum 
hourly NO<INF>X</INF> emission rate or the maximum hourly 
NO<INF>X</INF> concentration

[[Page 32016]]

recorded during the previous 2,160 quality-assured monitor operating 
hours (or during the previous 2,160 quality-assured monitor operating 
hours at the corresponding operational bin, if operational bins are 
used).
    (4) Whenever the monitor data availability is less than 80.0 
percent, the owner or operator shall substitute, as applicable, for 
each hour of each missing data period, the maximum NO<INF>X</INF> 
emission rate, as defined in section 2.1.2.1 of appendix A to this 
part, or the maximum potential NO<INF>X</INF> concentration, as defined 
in section 2.1.2.1 of appendix A to this part. In addition, when 
operational bins are used, the owner or operator shall substitute (as 
applicable) the maximum potential NO<INF>X</INF> emission rate or the 
maximum potential NO<INF>X</INF> concentration for any hour in the 
missing data period in which essential operating or parametric data are 
unavailable and the operational bin cannot be determined.
    (5) If operational bins are used and no prior quality-assured 
NO<INF>X</INF> concentration data or NO<INF>X</INF> emission rate data 
exist for the corresponding operational bin, the owner or operator 
shall substitute, as applicable, either the maximum potential 
NO<INF>X</INF> emission rate or the maximum potential NO<INF>X</INF> 
concentration, as defined in section 2.1.2.1 of appendix A to this 
part.
    (6) If operational bins are used and there is at least one, but 
fewer than 2,160 quality-assured monitor operating hours of 
NO<INF>X</INF> emission rate or NO<INF>X</INF> concentration data in a 
particular operational bin, use whatever data are in the bin, for the 
purposes of the lookback periods described in paragraphs (d)(1)(i)(B), 
(d)(1)(ii)(A), (d)(1)(ii)(B), (d)(2)(i), (d)(2)(ii)(A), (d)(2)(ii)(B), 
and (d)(3) of this section.
    (7) Table 3 of this section summarizes the provisions of paragraphs 
(d)(1) through (d)(6) of this section.
    (e) Non-load-based volumetric flow rate data. (1) If operational 
bins, as defined in section 3 of appendix C to this part, are used for 
a non-load-based unit, use the missing data procedures in paragraph (c) 
of this section to provide substitute volumetric flow rate data for the 
unit.
    (2) If operational bins are not used for a non-load-based unit, 
modify the procedures in paragraph (c) of this section as follows:
    (i) In paragraphs (c)(1) through (c)(3), the words ``previous 2,160 
quality-assured monitor operating hours'' shall apply rather than 
``previous 2,160 quality-assured monitor operating hours at the 
corresponding unit load range or operational bin, as determined using 
the procedure in appendix C to this part;''
    (ii) The last sentence in paragraph (c)(4) does not apply;
    (iii) Paragraphs (c)(5), (c)(7), (c)(8), and (c)(9) are not 
applicable; and
    (iv) In paragraph (c)(6), the words, ``for either the corresponding 
load range (or a higher load range) or for the corresponding 
operational bin'' do not apply.
    (3) Table 4 of this section summarizes the provisions of paragraphs 
(e)(1) and (e)(2) of this section. Tables 3 and 4 follow:

         Table 3.--Non-Load-Based Missing Data Procedure for NO<INF>X</INF>-Diluent CEMS and NO<INF>X</INF> Concentration CEMS
----------------------------------------------------------------------------------------------------------------
                        Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
                                                                                                     Lookback
 Monitor data availability  (percent)      Duration (N) of CEMS                Method               period (in
                                           outage  (hours) \1\                                        hours)
----------------------------------------------------------------------------------------------------------------
95 or more............................  N<ls-thn-eq>24...........  Average......................           *2160
                                                                   The greater of:
                                        N>24.....................  Average......................           *2160
                                                                   90th percentile..............           *2160
90 or more, but below 95..............  N<ls-thn-eq>8............  Average......................           *2160
                                        N>8......................  The greater of:
                                                                   Average......................           *2160
                                                                   95th percentile..............           *2160
80 or more, but below 90..............  N>0......................  Maximum value................           *2160
Below 80, or operational bin            N>0......................  Maximum NO<INF>X</INF> emission rate or            None
 indeterminable.                                                    maximum potential NO<INF>X</INF>
                                                                    concentration.
----------------------------------------------------------------------------------------------------------------
* If operational bins are used, the lookback period is 2,160 quality-assured, monitor operating hours in the
  corresponding operational bin. If there are  2,160 hours of data in the operational bin, use all data in the
  bin for the lookback. If operational bins are not used, the lookback period is the previous 2,160 quality-
  assured monitor operating hours. For units for which data are reported 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 (or ozone seasons) prior to the missing data period.
\1\ During unit operating hours.


                       Table 4.--Non-Load-Based Missing Data Procedure for Flow Rate CEMS
----------------------------------------------------------------------------------------------------------------
                     Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
     Monitor data availability        Duration (N) of CEMS                                 Lookback period  (in
             (percent)                 outage  (hours) \1\              Method                    hours)
----------------------------------------------------------------------------------------------------------------
95 or more.........................  N<ls-thn-eq>24........  Average....................  *2160
                                     N>24..................  The greater of:
                                                             Average....................  HB/HA
                                                             90th percentile............  *2160

[[Page 32017]]

 
90 or more, but below 95...........  N<ls-thn-eq>8.........  Average....................  *2160
                                     N>8...................  The greater of:
                                                             Average....................  HB/HA.
                                                             95th percentile............  *2160
80 or more, but below 90...........  N>0...................  Maximum value..............  *2160
Below 80, or operational bin         N>0...................  Maximum potential flow rate  None
 indeterminable.
----------------------------------------------------------------------------------------------------------------
*If operational bins are used, the lookback period is the previous 2,160 quality-assured, monitor operating
  hours in the corresponding operational bin. If there are  2,160 hours of data in the operational bin, use all
  data in the bin for the lookback. 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 (or ozone seasons) prior to the missing data period.
\1\ During unit operating hours.

    23. Section 75.34 is amended by:
    a. Revising paragraphs (a) introductory text, (a)(1), (a)(2), and 
(d);
    b. Redesignating paragraph (a)(3) as (a)(4) and adding new 
paragraph (a)(3);
    c. In the second sentence of newly redesignated paragraph (a)(4) by 
removing the words ``Sec. 75.55(b) or'' and ``, as applicable''; and
    d. In paragraph (c) by revising the word `` NO<INF>X2</INF>'' to 
read `` NO<INF>X</INF>''.
    The revisions and additions read as follows:


Sec. 75.34  Units with add-on emission controls.

    (a) The owner or operator of an affected unit equipped with add-on 
SO<INF>2</INF> and/or NO<INF>X</INF> emission controls (including 
turbines that use dry low- NO<INF>X</INF> (DLN) technology) shall use 
one of the following options for each hour in which quality-assured 
data from the outlet SO<INF>2</INF> and/or NO<INF>X</INF> monitoring 
system(s) are not obtained, and shall document which option is selected 
in the monitoring plan required under Sec. 75.53:
    *(1) The owner or operator may use the missing data substitution 
procedures specified in Secs. 75.31 through 75.33 to provide substitute 
data for any missing data hour(s) in which the add-on emission 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, for each missing data period, record 
parametric data to verify the proper operation of the SO<INF>2</INF> or 
NO<INF>X</INF> add-on emission controls during each hour, as described 
in paragraph (d) of this section. For any missing data hour(s) in which 
such parametric data are either not provided or, if provided, do not 
demonstrate that proper operation of the SO<INF>2</INF> or 
NO<INF>X</INF> add-on emission controls has been maintained, the owner 
or operator shall substitute (as applicable) the maximum potential 
NO<INF>X</INF> concentration (MPC) as defined in section 2.1.2.1 of 
appendix A to this part, the maximum potential NO<INF>X</INF> emission 
rate, as defined in Sec. 72.2 of this chapter, or the maximum potential 
concentration for SO<INF>2</INF>, as defined by section 2.1.1.1. 
Alternatively, for SO<INF>2</INF> or NO<INF>X</INF>, the owner or 
operator may substitute, if available, the hourly SO<INF>2</INF> or 
NO<INF>X</INF> concentration recorded by a certified inlet monitor, in 
lieu of the MPC. For each hour in which data from an inlet monitor are 
reported, the owner or operator shall use a method of determination 
code (MODC) of ``22'' (see Table 4a in Sec. 75.57). In addition, under 
Sec. 75.64(c), the designated representative shall submit as part of 
each electronic quarterly report, a certification statement, verifying 
the proper operation of the SO<INF>2</INF> or NO<INF>X</INF> add-on 
emission control for each missing data period in which the missing data 
procedures of Secs. 75.31 through 75.33 were applied; or
    (2) The owner or operator may use the missing data procedures in 
Secs. 75.31 through 75.33 for all missing data hours if:
    (i) For purposes of the data lookback periods described in 
Sec. 75.33, two separate historical databases are created and 
maintained. The first (controlled) database shall consist of quality-
assured monitor operating hours of SO<INF>2</INF> concentration, 
NO<INF>X</INF> concentration, or NO<INF>X</INF> emission rate (as 
applicable) recorded downstream of the add-on emission controls, when 
the add-on controls are in operation (i.e., on). For a unit with more 
than one type of add-on controls (e.g., a unit with steam injection and 
SCR), the emission data for any hour(s) in which any of the add-on 
controls are operating shall be included in the controlled database. 
The second (uncontrolled) database shall consist of quality-assured 
monitor operating hours of SO<INF>2</INF> concentration, NO<INF>X</INF> 
concentration, or NO<INF>X</INF> emission rate (as applicable) recorded 
when none of the add-on emission controls are in operation (i.e., off). 
Alternatively, the uncontrolled database may consist of quality-assured 
monitor operating hours of data recorded by a certified monitoring 
system located at the control device inlet or by a certified monitoring 
system installed on a bypass stack (for exhaust configurations in which 
the flue gases are occasionally routed through an auxiliary stack, 
bypassing the add-on emission controls);
    (ii) For each hour of each missing data period, when the 
appropriate mathematical algorithm from Table 1 or Table 2 in 
Sec. 75.33 requires a lookback for the 90th percentile value, or the 
95th percentile value, or the maximum value from the previous 720 (or 
2,160) quality-assured monitor operating hours, the value is obtained 
from the appropriate database (i.e., from the controlled database if 
the add-on controls are documented to be operating properly during the 
hour or from the uncontrolled database if the add-on controls are 
either not in operation or not documented to be operating properly 
during the hour). To provide the necessary documentation, the owner or 
operator shall, for each missing data period, record parametric data, 
as described in paragraph (d) of this section;
    (iii) For SO<INF>2</INF>, when substitution of the average of the 
hour-before and hour-after values is required under 
Secs. 75.33(b)(1)(i) or (b)(2)(i), the maximum SO<INF>2</INF> 
concentration recorded in the previous 720 quality-assured monitoring 
hours in the uncontrolled database is substituted in lieu of the hour-
before and hour-after value, for each hour of the missing data period 
in

[[Page 32018]]

which the add-on controls are either not in operation or are not 
documented to be operating properly;
    (iv) When the percent monitor data availability (calculated 
according to Sec. 75.32) is 80 percent, the maximum potential 
SO<INF>2</INF> or NO<INF>X</INF> concentration or the maximum potential 
NO<INF>X</INF> emission rate (as applicable) is substituted for each 
hour of the missing data period, in accordance with Sec. 75.33(b)(4) 
and (c)(4); and
    (v) The designated representative, in accordance with 
Sec. 75.64(c), submits as part of each electronic quarterly report a 
certification statement verifying the proper operation of the 
SO<INF>2</INF> or NO<INF>X</INF> add-on emission controls during each 
missing data hour in which substitute data values from the first 
(controlled) database are reported, and (if applicable) for 
SO<INF>2</INF>, during each missing data hour in which the average of 
the hour before and hour after values is reported.
    (3) If the owner or operator elects to switch from the missing data 
option in paragraph (a)(1) of this section to the option in paragraph 
(a)(2) of this section, and if, at the time of the change, the initial 
missing data procedures in Sec. 75.31 have been previously completed 
and use of the standard missing data procedures of Sec. 75.33 has 
begun, the owner or operator need not repeat the initial missing data 
procedures. Rather, calculation of the percent monitor data 
availability may continue uninterrupted and the two databases 
(controlled and uncontrolled) may be created prospectively, beginning 
at the time of the change. Alternatively, the databases may be created 
from historical CEM data, if records are available documenting the 
operational status (i.e., on or off) of the emission controls during 
each quality-assured monitor operating hour. If, at the time of the 
missing data period, there are no quality-assured monitor operating 
hours of SO<INF>2</INF> or NO<INF>X</INF> data in the appropriate 
database for the lookback periods described in Sec. 75.33(b)(1)(ii)(A), 
(b)(2)(ii)(A), (b)(3), (c)(1)(i), (c)(1)(i)(A), (c)(2)(i), 
(c)(2)(ii)(A), and (c)(3), report the appropriate maximum potential 
SO<INF>2</INF> or NO<INF>X</INF> concentration or the maximum potential 
NO<INF>X</INF> emission rate (as applicable) for each hour of the 
missing data period. If there is at least one, but fewer than the 
requisite number of quality-assured monitor operating hours of 
SO<INF>2</INF> or NO<INF>X</INF> data in the appropriate database for 
the lookback periods (i.e., either 720 or 2,160 hours, as applicable) 
the owner or operator shall use all available data in the database for 
the lookbacks.
* * * * *
    (d) In order to implement the option in paragraphs (a)(1) and 
(a)(2) of this section, the owner or operator shall keep records of 
information as described in Sec. 75.58(b)(3)(i) to verify the proper 
operation of all add-on SO<INF>2</INF> or NO<INF>X</INF> emission 
controls (including dry low- NO<INF>X</INF> technology), during all 
periods of SO<INF>2</INF> or NO<INF>X</INF> emission missing data. The 
owner or operator shall document in the quality assurance/quality 
control (QA/QC) program required by section 1 of appendix B to this 
part, the parameters monitored and (as applicable) the ranges and 
combinations of parameters that indicate proper operation of the 
controls. If any of the following control methods are used: wet or dry 
limestone scrubbing, limestone injection, steam or water injection, 
selective catalytic or non-catalytic reduction (i.e., SCR or SNCR), or 
any other control method involving injection of water, steam, or 
chemical reagents into the combustion chamber or flue gas stream, at 
least one key parameter directly related to the control device removal 
efficiency shall be monitored. Examples of such key parameters include 
the water-to-fuel ratio, the ammonia injection rate, and the slurry 
flow rate. Irrespective of which specific parameter(s) are monitored, a 
demonstrable correlation between the parametric data and control device 
removal efficiency shall be established, as part of the QA/QC program. 
The correlation shall be based on parametric data recorded during unit 
operation, with the add-on controls in-service and the SO<INF>2</INF> 
or NO<INF>X</INF> monitor (as applicable) at the control device outlet 
providing quality-assured data. EPA recommends that the correlation be 
based on a minimum of 720 hours of such data, obtained at various load 
levels, covering the range of operation of the unit. The correlation 
shall serve as the basis for determining whether to use substitute data 
values from the controlled database or from the uncontrolled database, 
during periods of missing SO<INF>2</INF> or NO<INF>X</INF> data. The 
owner or operator shall provide the information recorded under 
Sec. 75.58(b)(3) and the related QA/QC program information to the 
Administrator, to the EPA Regional Office, or to an auditor from EPA or 
from the appropriate State or local agency, upon request.
    24. Section 75.35 is revised to read as follows:


Sec. 75.35  Missing data procedures for CO<INF>2</INF>.

    (a) The owner or operator of a unit with a CO<INF>2</INF> 
continuous emission monitoring system for determining CO<INF>2</INF> 
mass emissions in accordance with Sec. 75.10 (or an O<INF>2</INF> 
monitor that is used to determine CO<INF>2</INF> concentration in 
accordance with appendix F to this part) shall substitute for missing 
CO<INF>2</INF> pollutant concentration data using the procedures of 
paragraphs (b) and (d) of this section.
    (b) During the first 720 quality assured monitor operating hours 
following initial certification at a particular unit or stack location 
(i.e., the date and time at which quality assured data begins to be 
recorded by a CEMS at that location), or (when implementing these 
procedures for a previously certified CO<INF>2</INF> monitoring system) 
during the 720 quality assured monitor operating hours preceding 
implementation of the standard missing data procedures in paragraph (d) 
of this section, the owner or operator shall provide substitute 
CO<INF>2</INF> pollutant concentration data according to the procedures 
in Sec. 75.31(b).
    (c) [Reserved]
    (d) Upon completion of 720 quality assured monitor operating hours 
using the initial missing data procedures of Sec. 75.31(b), the owner 
or operator shall provide substitute data for CO<INF>2</INF> 
concentration data or substitute CO<INF>2</INF> data for heat input 
determination, as applicable, in accordance with the procedures in 
Sec. 75.33(b) except that the term ``CO<INF>2</INF> concentration'' 
shall apply rather than ``SO<INF>2</INF> concentration,'' the term 
``CO<INF>2</INF> pollutant concentration monitor'' or ``CO<INF>2</INF> 
diluent monitor'' shall apply rather than ``SO<INF>2</INF> pollutant 
concentration monitor,'' and the term ``maximum potential 
CO<INF>2</INF> concentration, as defined in section 2.1.3.1 of appendix 
A to this part'' shall apply, rather than ``maximum potential 
SO<INF>2</INF> concentration.''
    25. Section 75.36 is amended by:
    a. Revising the section heading;
    b. In paragraph (a) by adding the word ``rate'' after the words 
``hourly heat input'' in the first sentence, by adding the word 
``rate'' after the words ``heat input'' in the second and third 
sentences, removing the words ``On and after April 1, 2000,'' in the 
third sentence and capitalizing ``When'' to begin that sentence, and by 
removing the last sentence;
    c. Revising paragraph (b);
    d. Removing and reserving paragraph (c); and
    e. In paragraph (d) by adding the word ``rate'' after each 
occurrence of the word ``input''.
    The revisions and additions read as follows:

[[Page 32019]]

Sec. 75.36  Missing data procedures for heat input rate determinations.

* * * * *
    (b) During the first 720 quality assured monitor operating hours 
following initial certification at a particular unit or stack location 
(i.e., the date and time at which quality assured data begins to be 
recorded by a CEMS at that location), or (when implementing these 
procedures for a previously certified CO<INF>2</INF> or O<INF>2</INF> 
monitor) during the 720 quality assured monitor operating hours 
preceding implementation of the standard missing data procedures in 
paragraph (d) of this section, the owner or operator shall provide 
substitute CO<INF>2</INF> or O<INF>2</INF> data, as applicable, for the 
calculation of heat input (under section 5.2 of appendix F to this 
part) according to Sec. 75.31(b).
* * * * *
    26. Section 75.37 is amended by:
    a. In paragraph (a) by revising the words ``On and after April 1, 
2000, the'' to read ``The'' in the first sentence and by removing the 
second sentence;
    b. Revising paragraphs (c) and (d)(2)(i); and
    c. In paragraph (d) introductory text by removing the words ``of 
the moisture monitoring system''.
    The revisions and additions read as follows:


Sec. 75.37  Missing data procedures for moisture.

* * * * *
    (c) During the first 720 quality assured monitor operating hours 
following initial certification at a particular unit or stack location 
(i.e., the date and time at which quality assured data begins to be 
recorded by a moisture monitoring system at that location), the owner 
or operator shall provide substitute data for moisture according to 
Sec. 75.31(b).
    (d) * * *
    (2) * * *
    (i) Provided that none of the following equations is used to 
determine SO<INF>2</INF> emissions, CO<INF>2</INF> emissions or heat 
input: Equation F-2, F-14b, F-16, F-17, or F-18 in appendix F to this 
part, or Equation 19-5 or 19-9 in Method 19 in appendix A to part 60 of 
this chapter, use the missing data procedures in Sec. 75.33(b), except 
that the term ``moisture percentage'' shall apply rather than 
``SO<INF>2</INF> concentration,'' the term ``moisture monitoring 
system'' shall apply rather than ``SO<INF>2</INF> pollutant 
concentration monitor,'' and the term ``maximum potential moisture 
percentage, as defined in section 2.1.6 of appendix A to this part'' 
shall apply, rather than ``maximum potential SO<INF>2</INF> 
concentration;'' or
* * * * *
    27. Section 75.41 is amended by adding the words ``(Eq. 22)'' 
immediately before ``where,'' in paragraph (b)(2)(v)(B) and by revising 
Equation 27 in paragraph (c)(2)(ii) to read as follows:


Sec. 75.41  Precision criteria.

* * * * *
    (c) * * *
    (2) * * *
    (ii) * * *
    [GRAPHIC] [TIFF OMITTED] TP13JN01.001
    
    28. Section 75.53 is amended by:
    a. Removing and reserving paragraphs (c) and (d);
    b. Revising paragraphs (a)(1), (e)(1)(viii), (f)(1)(i)(F), and 
(f)(2)(i)(H);
    c. In paragraph (b) by adding the words ``, by the applicable 
deadline specified in Sec. 75.62 or elsewhere in this part'' prior to 
the period at the end of the paragraph;
    d. In paragraph (e)(1)(i)(D) by adding the words ``emergency/
startup'' after the words ``primary/secondary'';
    e. In paragraph (e)(1)(i)(E) by adding the words ``primary/
secondary controls indicator;'' after the words ``(if applicable);'';
    f. In paragraph (e)(1)(ix) by revising the words ``Part 75 
monitoring'' to read ``Monitoring'', adding the words ``ARP/Subpart H 
facility ORISPL number,'' after the words ``boiler identification 
number,'', and adding the words ``(or equivalent)'' after the words 
``reporting indicator'';
    g. In paragraph (f)(2)(i)(F) by adding the word ``rate'' after the 
word ``input'' and the word ``emission'' after the word `` 
NO<INF>X</INF>'';
    h. Adding a sentence to the end of paragraph (f)(5)(i); and
    i. Adding paragraphs (f)(5)(i)(A) through (H).
    The revisions and additions read as follows:


Sec. 75.53  Monitoring plan.

    (a) * * *
    (1) The owner or operator shall meet the requirements of paragraphs 
(a), (b), (e), and (f) of this section.
* * * * *
    (e) * * *
    (1) * * *
    (viii) Stack exit height (ft) above ground level and ground level 
elevation above sea level.
* * * * *
    (f) * * *
    (1) * * *
    (i) * * *
    (F) The method used to demonstrate that the unit qualifies for 
monthly GCV sampling or daily fuel sampling for sulfur content, if 
applicable.
* * * * *
    (2) * * *
    (i) * * *
    (H) To document the unit qualifies as a peaking unit, current 
calendar year or ozone season, capacity factor data as specified in the 
definition of peaking unit in Sec. 72.2 of this chapter, and an 
indication of whether the data are actual, projected, or operating 
data.
* * * * *
    (5) * * *
    (i) * * * The following items should be included:
    (A) Current calendar year of application;
    (B) Type of qualification;
    (C) Years one, two, and three;
    (D) Annual or ozone season measured or projected NO<INF>X</INF> 
mass emissions for years one, two, and three;
    (E) Annual or ozone season NO<INF>X</INF> mass calculated from 
emission factors for years one, two, and three;
    (F) Annual measured or projected SO<INF>2</INF> mass emissions for 
years one, two, and three;
    (G) Annual SO<INF>2</INF> mass calculated from emission factors for 
years one, two, and three; and
    (H) Annual or ozone season operating hours for years one, two, and 
three.
* * * * *


Sec. 75.54  [Reserved]

    29. Section 75.54 is removed and reserved.


Sec. 75.55  [Reserved]

    30. Section 75.55 is removed and reserved.


Sec. 75.56  [Reserved]

    31. Section 75.56 is removed and reserved.

[[Page 32020]]

    32. Section 75.57 is amended by:
    a. Revising the introductory paragraph;
    b. In paragraph (a)(3) by removing the words ``Sec. 75.55 or'' and 
``as applicable,'';
    c. In paragraph (a)(4) by removing both occurrences of the words 
``Sec. 75.56 or'';
    d. Revising Table 4a at the end of paragraph (c)(4);
    e. Revising paragraph (d)(6); and
    f. Revising the first sentence of paragraph (d)(7).
    The revisions read as follows:


Sec. 75.57  General recordkeeping provisions.

    The owner or operator shall meet all of the applicable 
recordkeeping requirements of this section.
* * * * *
    (c) * * *
    (4) * * *

                         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:
                                              SO<INF>2</INF>: Method 6C.
                                              Flow: Method 2 or its allowable alternatives under appendix A to
                                               part 60 of this chapter.
                                              NO<INF>X</INF>: Method 7E.
                                              CO<INF>2</INF> or O<INF>2</INF>: Method 3A.
5...........................................  For units with add-on SO2 and/or NO<INF>X</INF> emission controls: SO2
                                               concentration or NO<INF>X</INF> emission rate estimate from Agency
                                               preapproved parametric monitoring method.
6...........................................  Average of the hourly SO<INF>2</INF> concentrations, CO<INF>2</INF> concentrations, O<INF>2</INF>
                                               concentrations, NO<INF>X</INF> concentrations, flow rates, moisture
                                               percentages or NO<INF>X</INF> emission rates for the hour before and the
                                               hour following a missing data period.
7...........................................  Average of the hourly SO<INF>2</INF> concentration, CO<INF>2</INF> concentration, O<INF>2</INF>
                                               concentration, NO<INF>X</INF> concentration, moisture percentage, flow rate,
                                               or NO<INF>X</INF> emission rate for the hour before and the hour following a
                                               missing data period, using initial missing data procedures.
8...........................................  90th percentile hourly SO<INF>2</INF> concentration, CO<INF>2</INF> concentration, NO<INF>X</INF>
                                               concentration, flow rate, moisture percentage, or NO<INF>X</INF> emission
                                               rate or 10th percentile hourly O<INF>2</INF> 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 SO<INF>2</INF> concentration, CO<INF>2</INF> concentration, NO<INF>X</INF>
                                               concentration, flow rate, moisture percentage, or NO<INF>X</INF> emission
                                               rate or 5th percentile hourly O<INF>2</INF> 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 SO<INF>2</INF> concentration, CO<INF>2</INF> concentration, NO<INF>X</INF>
                                               concentration, flow rate, moisture percentage, or NO<INF>X</INF> emission
                                               rate or minimum hourly O<INF>2</INF> 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, NO<INF>X</INF> concentrations or NO<INF>X</INF> emission
                                               rates in corresponding load range (or, if applicable, a higher
                                               load range), for the applicable lookback period, using the
                                               initial missing data procedures.
12..........................................  Maximum potential concentration of SO<INF>2</INF>, maximum potential
                                               concentration of CO<INF>2</INF>, maximum potential concentration of NO<INF>X</INF>
                                               maximum potential flow rate, maximum potential NO<INF>X</INF> emission rate,
                                               maximum potential moisture percentage, minimum potential O<INF>2</INF>
                                               concentration or minimum potential moisture percentage, as
                                               determined using 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..........................................  [Reserved].
14..........................................  Diluent cap value (if the cap is replacing a CO<INF>2</INF> measurement, use
                                               5.0 percent for boilers and 1.0 percent for turbines; if it is
                                               replacing an O<INF>2</INF> measurement, use 14.0 percent for boilers and
                                               19.0 percent for turbines).
15..........................................  [Reserved].
16..........................................  SO<INF>2</INF> concentration value of 2.0 ppm during hours when only ``very
                                               low sulfur fuel'', as defined in Sec.  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 SO<INF>2</INF> concentration, NO<INF>X</INF> concentration, percent
                                               moisture, or NO<INF>X</INF> emission rate replaced with zero.
22..........................................  Hourly average SO<INF>2</INF> or NO<INF>X</INF> concentration, measured by a certified
                                               monitor at the control device inlet (units with add-on emission
                                               controls only).
23..........................................  Maximum potential SO<INF>2</INF> concentration, NO<INF>X</INF> concentration or NO<INF>X</INF>
                                               emission rate or flow rate, for an hour in which flue gases are
                                               discharged through an unmonitored bypass stack.
25..........................................  Maximum potential NO<INF>X</INF> emission rate (MER). (Use only when a NO<INF>X</INF>
                                               concentration full-scale exceedance occurs and the diluent
                                               monitor is unavailable.)
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.
----------------------------------------------------------------------------------------------------------------

    (d) * * *
    (6) Hourly average NO<INF>X</INF> emission rate (for 
NO<INF>X</INF>-diluent monitoring systems only, in units of lb/mmBtu, 
rounded to the nearest thousandth);
    (7) Hourly average NO<INF>X</INF> emission rate (for 
NO<INF>X</INF>-diluent monitoring systems only, in units of lb/mmBtu, 
rounded to the nearest thousandth), adjusted for bias if bias 
adjustment factor is required, as provided in Sec. 75.24(d). * * *
* * * * *
    33. Section 75.58 is amended by:
    a. Revising the introductory paragraph;
    b. In paragraphs (b)(1)(i) and (c) by removing the words 
``Sec. 75.54(c) or'';
    c. In paragraph (b)(1)(xi) and (b)(2)(vii) by removing the words 
``Codes 1-15 in Table 4 of Sec. 75.54 or'';

[[Page 32021]]

    d. Revising paragraph (b)(3);
    e. Adding a period to the end of paragraph (c)(7)(ii);
    f. In paragraph (d) by removing the words ``paragraph 75.54(d) 
or'';
    g. In paragraph (e)(1) by removing the words ``Secs. 75.54(c)(1) 
and (c)(3) or''; and
    h. In paragraph (f) by removing the words ``Secs. 75.54(b) through 
(e) or''.
    The revisions read as follows:


Sec. 75.58  General recordkeeping provisions for specific situations.

    The owner or operator shall meet all of the applicable 
recordkeeping requirements of this section.
* * * * *
    (b) * * *
    (3) For units with add-on SO<INF>2</INF> or NO<INF>X</INF> emission 
controls following the provisions of Sec. 75.34(a)(1) or (a)(2), the 
owner or operator shall record:
    (i) Parametric data which demonstrate, for each hour of missing 
SO<INF>2</INF> or NO<INF>X</INF> emission data, the proper operation of 
the add-on emission controls, as described in the quality assurance/
quality control program for the unit. The parametric data shall be 
maintained on site and shall be submitted, upon request, to the 
Administrator, EPA Regional office, State, or local agency;
    (ii) A flag indicating, for each hour of missing SO<INF>2</INF> or 
NO<INF>X</INF> emission data, either that the add-on emission controls 
are operating properly, as described in the quality assurance/quality 
control program, or that the add-on emission controls are not operating 
properly; and
    (iii) For the purposes of creating the controlled and uncontrolled 
databases described under Sec. 75.34(a)(2), a flag indicating whether 
the add-on emission controls are operating (on) or not operating (off) 
during each unit operating hour.
* * * * *
    34. Section 75.59 is amended by:
    a. Revising the introductory paragraph;
    b. Revising paragraphs (a)(1)(vii), (a)(7)(ii)(P) and 
(a)(7)(iii)(F);
    c. In the second sentence of paragraph (a)(7) by adding the words 
``of this section'' after the words ``through (a)(7)(vi)'';
    d. In paragraph (a)(10)(i)(E) by revising the reference to 
``(a)(7)(iii)(A)'' to read ``(a)(7)(iii)'';
    e. In paragraph (b)(2)(v) by adding the word ``level'' after the 
word ``high'';
    f. In paragraphs (b)(4)(ii)(K) and (b)(5)(i)(N) by removing the 
word ``and'' after the semicolon;
    g. In paragraph (b)(4)(ii)(L) by removing the period and adding in 
its place ``; and'';
    h. In paragraph (b)(5)(i)(O) by removing the period and adding in 
its place a semicolon;
    i. Adding paragraphs (b)(4)(ii)(M), (b)(5)(i)(P), and (b)(5)(i)(Q);
    j. In paragraph (c)(1) by removing the words ``Sec. 75.55(b) or'';
    k. In paragraph (d)(1) by revising the word ``under'' to read 
``using the procedures of'';
    l. Adding the word ``and'' at the end of paragraph (d)(1)(xi);
    m. Removing paragraphs (d)(1)(xiii) through (d)(1)(xvi);
    n. Redesignating existing paragraph (d)(2) as (d)(3) and adding a 
new paragraph (d)(2); and
    o. In newly designated paragraph (d)(3)(x) by removing the words 
``and (3)''.
    The revisions and additions read as follows:


Sec. 75.59  Certification, quality assurance, and quality control 
record provisions.

    The owner or operator shall meet all of the applicable 
recordkeeping requirements of this section.
    (a) * * *
    (1) * * *
    (vii) Reference signal or calibration gas level;
* * * * *
    (7) * * *
    (ii) * * *
    (P) Average stack flow rate, adjusted, if applicable, for wall 
effects (scfh, wet basis);
* * * * *
    (iii) * * *
    (F) Average velocity differential pressure at traverse point 
(inches of H<INF>2</INF>O) or the average of the square roots of the 
velocity differential pressures at the traverse point ((inches of 
H<INF>2</INF>O)<SUP>1/2</SUP>);
* * * * *
    (b) * * *
    (4) * * *
    (ii) * * *
    (M) Number of hours excluded due to co-firing.
* * * * *
    (5) * * *
    (i) * * *
    (P) Flag to indicate highest NO<INF>X</INF> emission rate for unit-
specific, fuel-specific NO<INF>X</INF> emission rate testing; and
    (Q) Adjusted NO<INF>X</INF> default rate (for low mass emission 
unit default testing).
* * * * *
    (d) * * *
    (2) For each single-load or four-load appendix E test, record the 
following:
    (i) The three-run average NO<INF>X</INF> emission rate for each 
load level;
    (ii) An indicator that the average NO<INF>X</INF> emission rate is 
the highest NO<INF>X</INF> average emission rate recorded at any load 
level of the test (if appropriate);
    (iii) The default NO<INF>X</INF> emission rate (highest three run 
average NO<INF>X</INF> emission rate at any load level, multiplied by 
1.15, if appropriate;
    (iv) An indicator that the add-on NO<INF>X</INF> emission controls 
were operating or not operating during each run of the test; and
    (v) Parameter data indicating the use and efficacy of control 
equipment during the test.
* * * * *
    35. Section 75.60 is amended by adding paragraph (b)(7) to read as 
follows:


Sec. 75.60  General provisions.

* * * * *
    (b) * * *
    (7) Routine appendix E retest reports. If requested by the 
applicable EPA Regional Office, appropriate State, and/or appropriate 
local air pollution control agency, the designated representative shall 
submit a hardcopy report within 45 days after completing a required 
periodic retest according to section 2.2 of appendix E to this part, or 
within 15 days of receiving the request, whichever is later. The 
designated representative shall report the hardcopy information 
required by Sec. 75.59(b)(5) to the applicable EPA Regional Office, 
appropriate State, and/or appropriate local air pollution control 
agency that requested the hardcopy report.
* * * * *
    36. Section 75.61 is amended by:
    a. In paragraph (a)(1) by removing the words ``and except for 
testing only of the data acquisition and handling system'' from the end 
of that paragraph, by adding a period to the end of the first sentence, 
and by adding two new sentences to the end of the paragraph;
    b. In paragraph (a)(1)(i) by revising the number ``45'' to read 
``21'';
    c. Revising paragraphs (a)(1)(ii) and (a)(1)(iii);
    d. In paragraph (a)(1)(iv) by revising both references to 
``(a)(1)'' to read ``(a)(1)(ii)'', by adding the words ``or other 
retests'' to the end of the first sentence, and by adding the words 
``(or other retests)'' after the words ``recertification tests'' in the 
second sentence;
    e. In the first sentence of paragraph (a)(2) introductory text by 
adding the words ``, or will become affected,'' after the words 
``commercial operation'';
    f. In paragraph (a)(4) by removing ``(a)'' after the second and 
third occurrences of ``Sec. 75.4'';
    g. Revising the first sentence of paragraph (a)(5) introductory 
text;
    h. In paragraph (a)(5)(ii) by adding the words ``, appendix E 
retest, or low mass

[[Page 32022]]

emissions unit retest'' after the words ``relative accuracy test''; and
    i. Revising paragraph (a)(6).
    The revisions and additions read as follows:


Sec. 75.61  Notifications.

    (a) * * *
    (1) * * * The owner or operator shall also provide written 
notification of testing performed under Sec. 75.19(c)(1)(iv)(A) to 
establish fuel and unit-specific NO<INF>X</INF> emission rates for low 
mass emissions units. Such notifications are not required, however, for 
initial certifications and recertifications of excepted monitoring 
systems under appendix D to this part.
* * * * *
    (ii) Notification of certification retesting, recertification 
testing, and retesting of low mass emissions units. For retesting 
required following a loss of certification under Sec. 75.20(a)(5), for 
recertification testing required under Sec. 75.20(b), or for retesting 
required under Sec. 75.19(c)(1)(iv)(D), notice of the date of any 
required RATA testing, any required retesting under section 2.3 in 
appendix E to this part, or any required retesting to determine new 
fuel and unit-specific NO<INF>X</INF> emission rates for low mass 
emissions units shall be submitted either in writing or by telephone at 
least 21 days prior to the first scheduled day of testing. Testing may 
be performed on a date other than that already provided in a notice 
under this paragraph (a)(1)(ii) as long as notice of the new date is 
provided by telephone or other means at least 7 days prior to the 
original scheduled test date or the revised test date, whichever is 
earlier.
    (iii) Repeat of testing without notice. Notwithstanding the above 
notice requirements, the owner or operator may elect to repeat a 
certification or recertification test or low mass emissions unit retest 
immediately, without advance notification, whenever the owner or 
operator has determined during the certification or recertification 
testing or low mass emissions unit retesting that a test was failed or 
must be aborted, or that a second test is necessary in order to attain 
a reduced relative accuracy test frequency.
* * * * *
    (5) Periodic relative accuracy test audits, appendix E retests, and 
low mass emissions unit retests. 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, and of periodic retesting of 
low mass emissions units performed under Sec. 75.19(c)(1)(iv)(D), no 
later than 21 days prior to the first scheduled day of testing. * * *
* * * * *
    (6) Notice of combustion of emergency fuel under appendix D or E. 
The designated representative of an oil-fired unit or gas-fired unit 
using appendix D or E of this part shall, for each calendar quarter in 
which emergency fuel is combusted, provide notice of the combustion of 
the emergency fuel in the cover letter (or electronic equivalent) which 
transmits the next quarterly report submitted under Sec. 75.64. The 
notice shall specify the exact dates and hours during which the 
emergency fuel was combusted.
* * * * *
    37. Section 75.62 is amended by:
    a. Revising paragraph (a)(1); and
    b. In the third sentence of paragraph (a)(2) by adding the words 
``certification and'' after the words ``with any'' and the words 
``certification or'' after the words ``associated with the''.
    The revisions and additions read as follows:


Sec. 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, by a method specified by the Administrator, as 
follows: no later than 45 days prior to the initial certification 
tests; at the time of each certification or recertification application 
submission; in each electronic quarterly report; and whenever an update 
of the electronic monitoring plan information is required, either under 
Sec. 75.53(b) or elsewhere in this part (for such required updates, 
submit the updated electronic monitoring plan within 30 days of the 
event with which the monitoring plan change is associated, unless 
otherwise specified in this part).
* * * * *
    38. Section 75.63 is amended by:
    a. Revising paragraphs (a)(1)(i) and (ii), and removing paragraph 
(a)(1)(iii);
    b. In paragraph (a)(2)(i) by adding the words ``under 
Sec. 75.20(b)'' after the words ``recertification tests'' and the words 
``of this section'' after the words ``paragraph (b)(1)'';
    c. Revising the first and second sentences of paragraph (a)(2)(ii);
    d. In paragraph (a)(2)(iii) by adding the words ``rather than 
certification testing'' after the words ``are required'';
    e. Revising paragraph (b)(1)(i);
    f. In paragraph (b)(1)(ii) by removing the words ``Sec. 75.56 or'' 
and ``as applicable,''; and
    g. Revising the first sentence of paragraphs (b)(2)(i) and (c).
    The revisions and additions read as follows:


Sec. 75.63  Initial certification or recertification application.

    (a) * * *
    (1) * * *
    (i) For CEM systems or excepted monitoring systems under appendix D 
or E to this part, within 45 days after completing all initial 
certification tests, submit:
    (A) To the Administrator, the electronic information required by 
paragraph (b)(1) of this section and a hardcopy certification 
application form (EPA form 7610-14). The results of the certification 
tests shall also be included in the appropriate electronic quarterly 
report submittal under Sec. 75.64. Except for subpart E applications 
for alternative monitoring systems or unless specifically requested by 
the Administrator, do not submit a hardcopy of the test data and 
results to the Administrator.
    (B) To the applicable EPA Regional Office and the appropriate State 
and/or local air pollution control agency, the hardcopy information 
required by paragraph (b)(2) of this section.
    (ii) For units for which the owner or operator is applying for 
certification approval of the optional excepted methodology under 
Sec. 75.19 for low mass emissions units, submit, no later than 45 days 
prior to commencing use of the methodology:
    (A) To the Administrator, the electronic information required by 
paragraph (b)(1)(i) of this section, and a hardcopy certification 
application form (EPA form 7610-14); and
    (B) To the applicable EPA Regional Office and appropriate State 
and/or local air pollution control agency, the hardcopy information 
required by Sec. 75.19(a)(2), the hardcopy results of any appendix E 
(of this part) tests or any CEMS data analysis used to derive a fuel 
and unit specific default NO<INF>X</INF> emission rate, and the 
hardcopy information in paragraphs (b)(2)(i), (iii), and (iv) of this 
section.
    (2) * * *
    (ii) Within 45 days after completing all recertification tests 
under Sec. 75.20(b), submit the hardcopy information required by 
paragraph (b)(2) of this section to the applicable EPA Regional

[[Page 32023]]

Office and the appropriate State and/or local air pollution control 
agency. The applicable EPA Regional Office or appropriate State or 
local air pollution control agency may waive the requirement to provide 
hardcopy recertification test data and results. * * *
* * * * *
    (b) * * *
    (1) * * *
    (i) A complete, up-to-date version of the electronic portion of the 
monitoring plan, according to Sec. 75.53(e) and (f), in the format 
specified in Sec. 75.62(c).
* * * * *
    (2) * * *
    (i) Any changed portions of the hardcopy monitoring plan 
information required under Sec. 75.53(e) and (f). * * *
* * * * *
    (c) Format. The electronic portion of each certification or 
recertification application shall be submitted in a format to be 
specified by the Administrator and by a method specified by the 
Administrator. * * *
    39. Section 75.64 is amended by:
    a. Revising the first and third sentences of paragraph (a) 
introductory text and revising paragraph (a)(2) introductory text;
    b. In paragraph (a)(2)(iii) by removing the words ``Sec. 75.54(f) 
or'';
    c. In paragraph (a)(2)(iv) by removing the words ``Sec. 75.55(b)(3) 
or'';
    d. In paragraph (a)(2)(vi) by removing the words ``Sec. 75.54(g) 
or'';
    e. In paragraph (a)(2)(vii) by removing the words ``Sec. 75.56 
or'';
    f. In paragraph (a)(2)(viii) by removing the words 
``Sec. 75.56(a)(5)(vii), Sec. 75.56(a)(5)(ix),'';
    g. In paragraph (a)(2)(xi) by removing the words ``Sec. 75.56(a)(7) 
or'';
    h. In paragraph (a)(4) by removing the words ``hundredth prior to 
April 1, 2000 and to the nearest'' and the words ``on and after April 
1, 2000'';
    i. Removing and reserving paragraphs (a)(2)(v), (a)(8), and (e);
    j. In paragraph (d) by removing the words ``or hardcopy''; and
    k. In paragraph (f) by removing the words ``modem and''.
    The revisions read as follows:


Sec. 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 Sec. 75.4(a), (b), or (c). * * * For an affected unit 
subject to Sec. 75.4(d) that is shutdown on the relevant compliance 
date in Sec. 75.4(a) or has been placed in long-term cold storage, 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). * * *
* * * * *
    (2) The information and hourly data required in Sec. 75.53 and 
Secs. 75.57 through 75.59, excluding the following:
* * * * *


Sec. 75.65  [Amended].

    40. Section 75.65 is amended by removing the words ``Sec. 75.54(f) 
or'' and ``, as applicable,''.


Sec. 75.66  [Amended]

    41. Section 75.66 is amended by:
    a. In paragraph (e) by removing the words ``Sec. 75.55(b) or'' and 
``, as applicable,''; and
    b. Removing and reserving paragraph (i).
    42. Section 75.70 is amended by:
    a. Adding a hyphen to the term ``non-affected'' in paragraph 
(a)(1);
    b. In paragraph (d)(1) by adding the words ``in Sec. 75.20'' after 
the words ``recertification procedures'';
    c. Revising paragraphs (e), (f) introductory text, and (f)(1) 
introductory text;
    d. In paragraphs (f)(1)(i), (ii), and (iii) by adding a comma after 
the word ``valid'' and revising the words ``quality assured'' to read 
``quality-assured'';
    e. In paragraphs (f)(1)(ii) and (iii) by removing the word ``or'' 
from the end of each paragraph;
    f. In paragraph (f)(1)(iii) by adding the word ``rate'' before the 
word ``data'', revising the word ``mmBtu'' to read ``mmBtu/hr'', and 
revising the word ``accepted'' to read ``excepted'';
    g. In paragraph (f)(1)(iv) by revising the words ``volumetric flow 
monitor, and without a diluent monitor'' to read ``flow monitor'', by 
adding a comma after the reference to ``Sec. 75.32'', and by removing 
the period and adding ``; or'' to the end of the paragraph;
    h. Adding new paragraph (f)(1)(v);
    i. In paragraph (g)(1) by adding the word ``rate'' after the words 
``and heat input'';
    j. In paragraph (g)(2) by revising the words ``of the unit under 
section 2.1'' to read ``, as defined in section 2.1.4.1''; and
    k. Revising paragraph (g)(6).
    The revisions and additions read as follows:


Sec. 75.70   NO<INF>X</INF> mass emissions provisions.

* * * * *
    (e) Quality assurance and quality control requirements. For units 
that use continuous emission monitoring systems to account for 
NO<INF>X</INF> mass emissions, the owner or operator shall meet the 
applicable quality assurance and quality control requirements in 
Sec. 75.21, appendix B to this part, and Sec. 75.74(c) for the 
NO<INF>X</INF>-diluent continuous emission monitoring systems, flow 
monitoring systems, NO<INF>X</INF> concentration monitoring systems, 
moisture monitoring systems, and diluent monitors required under 
Sec. 75.71. Units using the low mass emissions excepted methodology 
under Sec. 75.19 shall meet the applicable quality assurance 
requirements of that section, except as otherwise provided in 
Sec. 75.74(c). Units using excepted monitoring methods under appendices 
D and E to this part shall meet the applicable quality assurance 
requirements of those appendices.
    (f) Missing data procedures. Except as provided in 
Sec. 75.74(c)(7), the owner or operator shall provide substitute data 
from monitoring systems required under Sec. 75.71 for each affected 
unit as follows:
    (1) For an owner or operator using a continuous emissions 
monitoring system, substitute for missing data in accordance with the 
applicable missing data procedures in Secs. 75.31 through 75.37 
whenever the unit combusts fuel and:
* * * * *
    (v) A valid, quality-assured hour of moisture data (in percent 
H<INF>2</INF>O) has not been measured or recorded for an affected unit, 
either by a certified moisture monitoring system or an approved 
alternative monitoring method under subpart E of this part. This 
requirement does not apply when a default percent moisture value, as 
provided in Secs. 75.11(b) or 75.12(b), is used to account for the 
hourly moisture content of the stack gas.
* * * * *
    (g) * * *
    (6) For any unit using continuous emissions monitors, the 
conditional data validation procedures in Sec. 75.20(b)(3)(ii) through 
(b)(3)(ix).
* * * * *
    43. Section 75.71 is amended by:
    a. In paragraph (a)(1) by adding the word ``rate'' after the words 
``heat input'' and by removing the hyphen after each occurrence of the 
words ``O<INF>2</INF>'' and ``CO<INF>2</INF>'';
    b. In the second sentence of paragraph (a)(2) by adding the word 
``rate'' after

[[Page 32024]]

the words ``measure heat input'', by removing the word ``use'' after 
the words ``if applicable,'', and by adding the words ``may be used'' 
after the words ``appendix D to this part'';
    c. In paragraph (b)(1) by revising ``i.e.'' to read ``e.g.'' and by 
adding the words ``or to calculate the heat input rate'' before the 
words ``, the owner'';
    d. In paragraph (b)(3) by adding the word ``rate'' after the word 
``input'' and by adding a comma after the word ``maintain'';
    e. In the first and second sentences of paragraph (c)(2) by adding 
the word ``rate'' after the words ``heat input''; and
    f. In paragraph (d)(2) by removing the words ``or, if applicable, 
paragraph (e) of this section'', by revising the reference in 
``paragraph (c)'' to read ``paragraph (c)(1) or (c)(2)'', and by adding 
two new sentences to the end of the paragraph.
    The revisions and additions read as follows:


Sec. 75.71  Specific provisions for monitoring NO<INF>X</INF> and heat 
input for the purpose of calculating NO<INF>X</INF> mass emissions.

* * * * *
    (d) * * *
    (2) * * * If the required CEMS are not installed and certified by 
that date, the owner or operator shall report hourly NO<INF>X</INF> 
mass emissions as the product of the maximum potential NO<INF>X</INF> 
emission rate (MER) and the maximum hourly heat input of the unit (as 
defined in Sec. 72.2 of this chapter), starting with the first unit 
operating hour after the deadline and continuing until the CEMS are 
provisionally certified. For each unit operating hour in which the MER 
is used for NO<INF>X</INF> mass reporting, the MER shall be specific to 
the type of fuel being combusted in the unit.
* * * * *
    44. Section 75.72 is amended by:
    a. Revising the first sentence of the introductory paragraph to the 
section;
    b. Revising paragraphs (a)(1) introductory text and (a)(1)(i);
    c. Redesignating paragraph (a)(1)(ii) as paragraph (a)(1)(iii) and 
adding a new paragraph (a)(1)(ii);
    d. In the newly redesignated paragraph (a)(1)(iii)(A) by adding the 
word ``rate'' after the words ``heat input'' and by adding the words 
``and a diluent monitor'' after the word ``system'' in newly 
redesignated paragraph (a)(1)(iii)(B);
    e. In paragraph (a)(2) introductory text by adding the words ``, 
for purposes of heat input determination,'' after the words ``from each 
unit and'';
    f. In paragraph (a)(2)(ii)(A) by adding the word ``rate'' after the 
words ``heat input'';
    g. In paragraph (b)(1) introductory text by removing the semicolon 
and adding the words ``, for purposes of heat input determination,'' at 
the end of the paragraph;
    h. In paragraph (b)(2)(ii)(B) by adding the word ``rate'' after the 
words ``heat input'' in the first sentence;
    i. In paragraph (b)(2)(iii) by adding the words ``, in accordance 
with paragraph (a) of this section'' after the word ``purposes'';
    j. Revising paragraph (c);
    k. Revising paragraph (d);
    l. In paragraph (e) introductory text by revising the first 
sentence, adding a new second sentence, and revising the words 
``appendix F of `` to read ``appendix F to'' in the third sentence;
    m. In paragraph (e)(1) introductory text by revising the second 
sentence and adding a new third sentence;
    n. In paragraph (e)(1)(i) by adding the word ``rate'' after ``heat 
input'' and by revising the reference to ``Sec. 75.16(e)(5)'' to read 
``Sec. 75.16(e)(3)'';
    o. In paragraph (e)(2) by adding the word ``rate'' after the words 
``heat input'' in the first sentence; and
    p. In paragraph (g) by removing the words ``the owner or operator 
should'' and by revising the reference to ``Sec. 75.16(e)(5)'' to read 
``Sec. 75.16(e)(3)''.
    The revisions and additions read as follows:


Sec. 75.72  Determination of NO<INF>X</INF> mass emissions.

    Except as provided in paragraphs (e) and (f) of this section, the 
owner or operator of an affected unit shall calculate hourly 
NO<INF>X</INF> mass emissions (in lbs) by multiplying the hourly 
NO<INF>X</INF> emission rate (in lbs/mmBtu) by the hourly heat input 
rate (in mmBtu/hr) and the unit or stack operating time (as defined in 
Sec. 72.2). * * *
    (a) * * *
    (1) Install, certify, operate, and maintain a NO<INF>X</INF>-
diluent continuous emissions monitoring system and a flow monitoring 
system and diluent monitor in the common stack, record the combined 
NO<INF>X</INF> mass emissions for the units exhausting to the common 
stack, and, for the purposes of determining the hourly unit heat input 
rates, either:
    (i) Apportion the common stack heat input rate to the individual 
units according to the procedures in Sec. 75.16(e)(3);
    (ii) Install, certify, operate, and maintain a flow monitoring 
system and diluent monitor in the duct to the common stack from each 
unit; or
* * * * *
    (c) Unit with a main stack and a bypass stack. Whenever any portion 
of the flue gases from an affected unit can be routed through a bypass 
stack to avoid the installed NO<INF>X</INF>-diluent continuous 
emissions monitoring system or NO<INF>X</INF> concentration monitoring 
system, the owner and operator shall either:
    (1) Install, certify, operate, and maintain separate 
NO<INF>X</INF>-diluent continuous emissions monitoring systems and flow 
monitoring systems on the main stack and the bypass stack and calculate 
NO<INF>X</INF> mass emissions for the unit as the sum of the 
NO<INF>X</INF> mass emissions measured at the two stacks;
    (2) Monitor NO<INF>X</INF> mass emissions at the main stack using a 
NO<INF>X</INF>-diluent CEMS and a flow monitoring system and measure 
NO<INF>X</INF> mass emissions at the bypass stack using the reference 
methods in Sec. 75.22(b) for NO<INF>X</INF> concentration, flow rate, 
and diluent gas concentration, or NO<INF>X</INF> concentration and flow 
rate, and calculate NO<INF>X</INF> mass emissions for the unit as the 
sum of the emissions recorded by the installed monitoring systems on 
the main stack and the emissions measured by the reference method 
monitoring systems; or
    (3) Install, certify, operate, and maintain a NO<INF>X</INF>-
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 Sec. 75.53, since only the main stack is monitored. For 
each unit operating hour in which the bypass stack is used, report 
NO<INF>X</INF> mass emissions as follows. If the unit heat input is 
determined using a flow monitor and a diluent monitor, report 
NO<INF>X</INF> mass emissions using the maximum potential 
NO<INF>X</INF> emission rate, the maximum potential flow rate, and 
either the maximum potential CO<INF>2</INF> concentration or the 
minimum potential O<INF>2</INF> concentration (as applicable). The 
maximum potential NO<INF>X</INF> emission rate shall be specific to the 
type of fuel combusted in the unit during the bypass (see 
Sec. 75.33(c)(8)). If the unit heat input is determined using a fuel 
flowmeter, in accordance with appendix D to this part, report 
NO<INF>X</INF> mass emissions as the product of the fuel-specific 
maximum potential NO<INF>X</INF> emission rate and the actual measured 
hourly heat input rate.
    (d) Unit with multiple stack or duct configuration. When the flue 
gases from an affected unit discharge to the atmosphere through more 
than one stack, or when the flue gases from an affected unit utilize 
two or more ducts feeding into a single stack and the owner or operator 
chooses to monitor in the ducts rather than in the stack, the owner or 
operator shall either:
    (1) Install, certify, operate, and maintain a NO<INF>X</INF>-
diluent continuous

[[Page 32025]]

emission monitoring system and a flow monitoring system in each of the 
multiple stacks and determine NO<INF>X</INF> mass emissions from the 
affected unit as the sum of the NO<INF>X</INF> mass emissions recorded 
for each stack. If another unit also exhausts flue gases into one of 
the monitored stacks, the owner or operator shall comply with the 
applicable requirements of paragraphs (a) and (b) of this section, in 
order to properly determine the NO<INF>X</INF> mass emissions from the 
units using that stack;
    (2) Install, certify, operate, and maintain a NO<INF>X</INF>-
diluent continuous emissions monitoring system and a flow monitoring 
system in each of the ducts that feed into the stack, and determine 
NO<INF>X</INF> mass emissions from the affected unit using the sum of 
the NO<INF>X</INF> mass emissions measured at each duct; or
    (3) If the unit is eligible to use the procedures in appendix D to 
this part and if the conditions and restrictions of Sec. 75.17(c)(2) 
are fully met, install, certify, operate, and maintain a 
NO<INF>X</INF>-diluent continuous emissions monitoring system in one of 
the ducts feeding into the stack or in one of the multiple stacks, (as 
applicable) in accordance with Sec. 75.17(c)(2), and use the procedures 
in appendix D to this part to determine heat input rate for the unit.
    (e) Units using a NO<INF>X</INF> concentration monitoring system 
and a flow monitoring system to determine NO<INF>X</INF> mass. The 
owner or operator may use a NO<INF>X</INF> concentration monitoring 
system and a flow monitoring system to determine NO<INF>X</INF> mass 
emissions for the cases described in paragraphs (a) through (c) of this 
section and in paragraph (d)(1) or paragraph (d)(2) of this section (in 
place of a NO<INF>X</INF>-diluent continuous emissions monitoring 
system and a flow monitoring system). However, this option may not be 
used for the case described in paragraph (d)(3) of this section. * * *
    (1) * * * In addition, the owner or operator must provide heat 
input rate values for each unit utilizing a common stack. The owner or 
operator may either:
* * * * *
    45. Section 75.73 is amended by:
    a. In the second sentence of paragraph (a) by adding the word 
``compliance'' before the word ``deadline'', and by revising the 
reference to ``Sec. 75.70'' to read ``Sec. 75.70(b)'';
    b. Revising paragraph (a)(6) introductory text;
    c. Adding new paragraphs (a)(8), (a)(9), (d)(6), (f)(1)(vii), and 
(f)(1)(viii);
    d. Revising all of paragraph (c)(3) except for the heading and the 
first sentence;
    e. Revising paragraph (e)(1); and
    f. In paragraph (e)(2) by adding the words ``certification or'' 
before the words ``recertification application'' in the third sentence, 
and by adding a new sentence to the end of the paragraph.
    The revisions and additions read as follows:


Sec. 75.73  Recordkeeping and reporting.

    (a) * * *
    (6) Specific heat input record provisions for gas-fired or oil-
fired units using the procedures in appendix D to this part. In lieu of 
the information required in Sec. 75.57(c)(2), the owner or operator 
shall record the information in Sec. 75.58(c) for each affected gas-
fired or oil-fired unit and each non-affected gas-or oil-fired unit 
under Sec. 75.72(b)(2)(ii) for which the owner or operator is using the 
procedures in appendix D to this part for estimating heat input.
* * * * *
    (8) Total NO<INF>X</INF> mass emissions for the hour.
    (9) Formulas from monitoring plan for total NO<INF>X</INF> mass.
* * * * *
    (c) * * *
    (3) * * * In addition, to the extent applicable, each monitoring 
plan shall contain the information in Sec. 75.53, paragraphs (f)(1)(i), 
(f)(2)(i), and (f)(4) in electronic format and the information in 
Sec. 75.53, paragraphs (f)(1)(ii) and (f)(2)(ii) in hardcopy format. 
For units using the low mass emissions excepted methodology under 
Sec. 75.19, the monitoring plan shall include the additional 
information in Sec. 75.53, paragraphs (f)(5)(i) and (f)(5)(ii). The 
monitoring plan also shall identify, in electronic format, the 
reporting schedule for the affected unit (ozone season or quarterly), 
the beginning and end dates for the reporting schedule, seasonal 
controls indicator, ozone season fuel switching flag, and whether year-
round reporting for the unit is required by a State or local agency.
    (d) * * *
    (6) Routine appendix E retest reports. If requested by the 
applicable EPA Regional Office, appropriate State, and/or appropriate 
local air pollution control agency, the designated representative shall 
submit a hardcopy report within 45 days after completing a required 
periodic retest according to section 2.2 of appendix E to this part, or 
within 15 days of receiving the request, whichever is later. The 
designated representative shall report the hardcopy information 
required by Sec. 75.59(b)(5) to the applicable EPA Regional Office, 
appropriate State, and/or appropriate local air pollution control 
agency that requested the hardcopy report.
    (e) * * *
    (1) Electronic submission. The designated representative for an 
affected unit shall submit to the Administrator, by a method specified 
by the Administrator, a complete, electronic, up-to-date monitoring 
plan file (except for hardcopy portions identified in paragraph (e)(2) 
of this section) for each affected unit or group of units monitored at 
a common stack and each non-affected unit under Sec. 75.72(b)(2)(ii) to 
the permitting authority, no later than 45 days prior to the initial 
certification test; at the time of a certification or recertification 
application submission; and whenever an update of the electronic 
monitoring plan is required, either under Sec. 75.53 or elsewhere in 
this part. Submit the updated electronic monitoring plan within 30 days 
of the event with which the monitoring plan is associated, unless 
otherwise specified in this part.
    (2) * * * Electronic submittal of all monitoring plan information, 
including hardcopy portions, is permissible provided that a paper copy 
of the hardcopy portions can be furnished upon request.
    (f) * * *
    (1) * * *
    (vii) Reporting period heat input.
    (viii) New reporting frequency and begin date of the new reporting 
frequency.
* * * * *
    46. Section 75.74 is amended by:
    a. Revising paragraph (c)(2)(i)(D)(1);
    b. Adding a new second sentence to paragraph (c)(2)(ii);
    c. In the third sentence of paragraph (c)(2)(ii)(C) by revising the 
words ``in every period of five consecutive calendar'' to read ``every 
five'';
    d. Revising paragraph (c)(2)(ii)(H)(1);
    e. Revising the second sentence of paragraph (c)(3)(iii);
    f. In the second sentence of paragraph (c)(3)(iv) by adding the 
words ``the cumulative'' after the word ``only'' and by revising the 
words ``included when determining'' to read ``used to determine'';
    g. In paragraph (c)(3)(v) by adding a new second sentence;
    h. In paragraph (c)(3)(vi)(B) by removing the quotation marks 
around the words ``probationary calibration error test'' in the first 
sentence, by revising the reference to ``Sec. 75.20(b)(3)'' to read 
``Sec. 75.20(b)(3)(ii)'' in the first sentence, and by adding the words 
``(subject to the restrictions in paragraph (c)(3)(xii) of this 
section)'' after the words ``Sec. 75.20(b)(3)'' in the third sentence;

[[Page 32026]]

    i. In paragraph (c)(3)(viii) by adding the word ``cumulative'' 
after the number ``168'';
    j. In paragraph (c)(3)(x) by adding the words ``, if applicable,'' 
after the words ``Sec. 75.20(b)(3) and'';
    k. In paragraph (c)(3)(xi) by adding a comma after each occurrence 
of the word ``diagnostic'', by revising the words ``Sec. 75.31 or 
Sec. 75.33'' in the third sentence to read ``Sec. 75.31, Sec. 75.33, or 
Sec. 75.37'', and by adding the words ``conditional data validation'' 
before the word ``provisions'' in the fifth sentence;
    l. In paragraphs (c)(3)(xii)(A) and (B) by revising each occurrence 
of the words ``Sec. 75.31 or Sec. 75.33'' to read ``Sec. 75.31, 
Sec. 75.33, or Sec. 75.37'', by adding a comma after the occurrence of 
the word ``diagnostic'' in each paragraph, and by adding the words 
``conditional data validation'' before the word ``provisions'' in the 
second sentence of paragraph (c)(3)(xii)(B).
    m. In paragraph (c)(4) by adding the word ``rate'' after the words 
``heat input'' in the first sentence and by adding a new third 
sentence;
    n. In paragraph (c)(5) by adding the word ``rate'' after the words 
``heat input'';
    o. Revising paragraphs (c)(6)(v), (c)(7)(ii), and (c)(8)(ii);
    p. Adding a new paragraph (c)(7)(iii);
    q. In the second sentence of paragraph (c)(10)(ii) by revising the 
word ``monitoring'' to read ``monitored''; and
    r. In the second sentence of paragraph (c)(11) by revising the word 
``calender'' to read ``calendar''.
    The revisions and additions read as follows:


Sec. 75.74  Annual and ozone season monitoring and reporting 
requirements.

* * * * *
    (c) * * *
    (2) * * *
    (i) * * *
    (D) * * *
    (1) If the monitor passed a linearity check on or after January 1 
of the previous year and the unit or stack on which the monitor is 
located operated for fewer than 336 cumulative unit or stack operating 
hours (as defined in Sec. 72.2 of this chapter) in the previous ozone 
season, the owner or operator may have a grace period of up to 168 
cumulative unit or stack operating hours to perform a linearity check, 
subject to the restrictions in this paragraph and in paragraph 
(c)(3)(xii) of this section, and the owner or operator may continue to 
submit quality assured data from that monitor as long as all other 
required quality assurance tests are passed. If the unit or stack 
operates for more than the allowable grace period of 168 cumulative 
operating hours in the current ozone season without a linearity check 
of the monitor having been performed, the owner or operator of the unit 
shall either report data from a certified backup monitoring system or 
reference method or shall report substitute data using the missing data 
procedures under paragraph (c)(7) of this section, starting with the 
first unit or stack operating hour after the grace period expires and 
continuing until the successful completion of a linearity check. Note 
that the grace period shall not extend beyond the end of the third 
calendar quarter.
* * * * *
    (ii) * * * Notwithstanding this requirement, a pre-ozone season 
RATA need not be performed between October 1 and April 30, if a RATA 
was passed during the previous ozone season and if the conditions in 
paragraph (a)(3)(vii) of this section are met, thereby ensuring that 
the data from the CEMS are quality-assured at the beginning of the 
current ozone season.
* * * * *
    (H) * * *
    (1) If the monitoring system passed a RATA on or after January 1 of 
the previous year and the unit or stack on which the monitor is located 
operated for fewer than 336 cumulative unit or stack operating hours 
(as defined in Sec. 72.2 of this chapter) in the previous ozone season, 
the owner or operator may have a grace period of up to 720 cumulative 
unit or stack operating hours to perform a RATA, subject to the 
restrictions in this paragraph and in paragraph (c)(3)(xii) of this 
section, and the owner or operator may continue to report quality 
assured data from that monitor as long as all other required quality 
assurance tests are passed. If the unit or stack operates for more than 
the allowable grace period of 720 cumulative unit or stack operating 
hours in the current ozone season, without a RATA of the monitoring 
system having been performed, the owner or operator of the unit or 
stack shall either report data from a certified backup monitoring 
system or reference method or shall report substitute data using the 
missing data procedures under paragraph (c)(7) of this section, 
starting with the first unit operating hour after the grace period 
expires and continuing until the successful completion of the RATA. 
Note that the grace period shall not extend beyond the end of the third 
calendar quarter.
* * * * *
    (3) * * *
    (iii) * * * If the flow-to-load ratio test for the second calendar 
quarter is failed, the owner or operator shall follow the procedures in 
section 2.2.5(c)(8) of appendix B to this part. * * *
* * * * *
    (v) * * * Automatic deadline extensions may be claimed for the two 
calendar quarters outside the ozone season (the first and fourth 
calendar quarters), since a fuel flow-to-load ratio test is not 
required in those quarters. * * *
* * * * *
    (4) * * * The owner or operator shall include all calendar quarters 
in the year when determining the deadline for visual inspection of the 
primary fuel flowmeter element, as specified in section 2.1.6(c) of 
appendix D to this part.
* * * * *
    (6) * * *
    (v) The results of RATAs (and any other quality assurance test(s) 
required under paragraph (c)(2) or (c)(3) of this section) which affect 
data validation for the current ozone season, but which were performed 
outside the ozone season (i.e., between October 1 of the previous 
calendar year and April 30 of the current calendar year), shall be 
reported in the quarterly report for the second quarter of the current 
calendar year (or in the report for the third calendar quarter of the 
current calendar year, if the unit or stack does not operate in the 
second quarter).
    (7) * * *
    (ii) The standard missing data procedures of Secs. 75.31 through 
75.37 shall be used, with one exception. When a fuel which has a 
significantly higher NO<INF>X</INF> emission rate than any of the 
fuel(s) combusted in prior ozone seasons is combusted in the unit, and 
no quality-assured NO<INF>X</INF> data have been recorded in the 
current or any previous ozone season while combusting the new fuel, the 
owner or operator shall substitute the maximum potential NO<INF>X</INF> 
emission rate, as defined in Sec. 72.2 of this chapter, from a 
NO<INF>X</INF>-diluent continuous emission monitoring system, or the 
maximum potential concentration of NO<INF>X</INF>, as defined in 
section 2.1.2.1 of appendix A to this part, from a NO<INF>X</INF> 
concentration monitoring system. The maximum potential value used shall 
be specific to the new fuel. The owner or operator shall substitute the 
maximum potential value for each hour of missing NO<INF>X</INF> data 
until the first hour that quality-assured NO<INF>X</INF> data are 
obtained while combusting the new fuel, and then shall resume use of 
the standard missing data routines, either on a fuel-specific or non-
fuel-specific basis; and
    (iii) In order to apply the missing data routines described in 
Secs. 75.31 through

[[Page 32027]]

75.37 on an ozone season-only basis, the procedures in those sections 
shall be modified as follows:
    (A) The use of the initial missing data procedures in Sec. 75.31 
shall commence with the first unit operating hour in the first ozone 
season for which emissions data are required to be reported under 
Sec. 75.64.
    (B) In Sec. 75.31(a), the phrases, ``during the first 720 quality-
assured monitor operating hours within the ozone season'' and ``during 
the first 2,160 quality-assured monitor operating hours within the 
ozone season.'' apply respectively instead of the phrases ``during the 
first 720 quality-assured monitor operating hours'' and ``during the 
first 2,160 quality-assured monitor operating hours.''
    (C) The sentence, ``The owner or operator of a unit shall use these 
procedures for no longer than three ozone seasons following initial 
certification'' applies instead of the last sentence of Sec. 75.31(a).
    (D) In Sec. 75.32(a), the phrases ``the first 720 quality-assured 
monitor operating hours within the ozone season,'' ``the first 2,160 
quality-assured monitor operating hours within the ozone season,'' and 
``three ozone seasons'' apply, respectively, instead of the phrases 
``the first 720 quality-assured monitor operating hours,'' ``the first 
2,160 quality-assured monitor operating hours,'' and ``three years 
(26,280 clock hours).''
    (E) In Sec. 75.32(a)(1), the phrase ``Following initial 
certification, prior to completion of 3,672 unit operating hours within 
the subsequent ozone season(s)'' applies instead of the phrase ``Prior 
to completion of 8,760 unit operating hours following initial 
certification.''
    (F) In Equation 8, the phrase ``Total unit operating hours within 
the ozone season'' applies instead of the phrase ``Total unit operating 
hours.''
    (G) In Sec. 75.32(a)(2), phrase, ``3,672 unit operating hours 
within the ozone season,'' applies instead of the phrase, ``8,760 unit 
operating hours'', and the phrase, ``three ozone seasons'' applies 
instead of the phrase, ``three years (26,280 clock hours).''
    (H) In the numerator of Equation 9, the phrase, ``Total unit 
operating hours within the ozone season'' applies instead of the phrase 
``Total unit operating hours'', and the phrase, ``3,672 unit operating 
hours within the ozone season'' applies instead of the phrase, ``8,760 
unit operating hours''. In the denominator of Equation 9, the number 
``3,672'' applies instead of ``8,760.''
    (I) Use the following instead of the first three sentences in 
Sec. 75.32(a)(3): ``When calculating percent monitor data availability 
using Equation 8 or 9, the owner or operator shall include all unit 
operating hours within the ozone season, and all monitor operating 
hours within the ozone season for which quality-assured data were 
recorded by a certified primary monitor; a certified redundant or non-
redundant backup monitor or a reference method for that unit; or by an 
approved alternative monitoring system under subpart E of this part. No 
hours from more than three ozone seasons earlier shall be used in 
Equation 9.'' For a unit that has accumulated fewer than 3,672 unit 
operating hours in the previous three ozone seasons, use the following 
in the numerator of Equation 9, ``Total unit operating hours for which 
quality-assured data were recorded in the previous three ozone 
seasons'', and in the denominator of Equation 9 use ``Total unit 
operating hours in the previous three ozone seasons.''
    (J) In Sec. 75.33(a), the phrases ``the first 720 quality-assured 
monitor operating hours within the ozone season,'' ``the first 2,160 
quality-assured monitor operating hours within the ozone season,'' and 
``three ozone seasons'' apply, respectively, instead of the phrases 
``the first 720 quality-assured monitor operating hours,'' ``the first 
2,160 quality-assured monitor operating hours,'' and ``three years 
(26,280 clock hours).''
    (K) Instead of the last sentence of Sec. 75.33(a), use ``For the 
purposes of missing data substitution, the owner or operator of a unit 
shall not use quality-assured monitor operating hours of data that were 
recorded more than three ozone seasons prior to the ozone season in 
which the missing data period occurs.''
    (L) In Secs. 75.33(b), 75.33(c), 75.35, 75.36, and 75.37, the 
phrases, ``720 quality-assured monitor operating hours within the ozone 
season'' and ``2,160 quality-assured monitor operating hours within the 
ozone season'' apply, respectively, instead of the phrases ``720 
quality-assured monitor operating hours'' and ``2,160 quality-assured 
monitor operating hours.''
    (M) In Sec. 75.34(a)(2), the phrases, ``720 (or 2,160) quality-
assured monitor operating hours within the ozone season,'' ``previous 
720 quality-assured monitor operating hours recorded within the ozone 
season in the uncontrolled database,'' and ``the requisite number of 
quality-assured monitor operating hours of SO<INF>2</INF> or 
NO<INF>X</INF> data recorded within the ozone season in the appropriate 
database for the lookback periods,'' apply respectively instead of 
``720 (or 2,160) quality-assured monitor operating hours,'' ``previous 
720 quality-assured monitor operating hours in the uncontrolled 
database,'' and ``the requisite number of quality-assured monitor 
operating hours of SO<INF>2</INF> or NO<INF>X</INF> data in the 
appropriate database for the lookback periods.''
    (8) * * *
    (ii) For units with add-on emission controls, using the missing 
data option in Sec. 75.34(a)(1), the range of operating parameters for 
add-on emission controls, as described in Sec. 75.34(a) and information 
for verifying proper operation of the add-on emission controls during 
missing data periods, as described in Sec. 75.34(d). For units using 
the missing data option in Sec. 75.34(a)(2), information documenting 
the operating status of the add-on emission controls during unit 
operation, as described in Sec. 75.34(d).
* * * * *


Appendix A Section 1  [Amended].

    47. Section 1 of Appendix A to Part 75 is amended by:
    a. In section heading 1.1 by revising the words ``Pollutant 
Concentration and CO<INF>2</INF> or O<INF>2</INF>'' to read ``Gas'';
    b. In the second sentence of section 1.1 by revising the words 
``SO<INF>2</INF> pollutant concentration monitor or NO<INF>X</INF>'' to 
read ``SO<INF>2</INF>, CO<INF>2</INF>, O<INF>2</INF>, or NO<INF>X</INF> 
concentration monitoring system or NO<INF>X</INF>-diluent'';
    c. In section heading 1.1.1 by removing the words ``Pollutant 
Concentration and CO<INF>2</INF> or O<INF>2</INF>'';
    d. In section heading 1.1.2 by removing the words ``Pollutant 
Concentration and CO<INF>2</INF> or O<INF>2</INF> Gas'';
    e. In the fourth sentence of section 1.2 by revising the words 
``section 6.5.2'' to read ``section 6.5.2.1''; and
    f. Removing the first sentence of section 1.2.2.
    48. Section 2 of Appendix A to Part 75 is amended by:
    a. Revising the second and third sentences of section 2.1;
    b. In the first sentence of section 2.1.1 by revising the words 
``this section 2'' to read ``sections 2.1.1.1 through 2.1.1.5 of this 
appendix'';
    c. Moving Equations A-1a and A-1b and the variable equations and 
Note following them from paragraph (c) of section 2.1.1.1 to the end of 
paragraph (a) of section 2.1.1.1;
    d. Revising the definition of the variable ``%S'' in Equation A-1b 
of paragraph (a) of section 2.1.1.1;
    e. Adding a definition for the variable ``GCV'' after the 
definition of the variable ``%CO<INF>2W</INF>'' in Equation A-1b in 
paragraph (a) of section 2.1.1.1;
    f. Adding two sentences to the end of paragraph (b) of section 
2.1.1.1;

[[Page 32028]]

    g. Adding three sentences to the end of paragraph (a) of section 
2.1.1.2;
    h. In the definition of MPC in Equation A-2 in paragraph (c) of 
section 2.1.1.2 by adding the words ``in section 2.1.1.1 of this 
appendix'' after the words ``as determined by Eq. A-1a or A-1b'';
    i. Revising the fifth and tenth sentences of section 2.1.1.3;
    j. In paragraph (c) of section 2.1.1.4 by adding a sentence after 
the first sentence;
    k. Removing the first sentence of paragraph (d) of section 2.1.1.4 
and adding three sentences in its place;
    l. In the first sentence of section 2.1.1.5 by revising the words 
``paragraphs (a) and (b)'' to read ``paragraphs (a), (b), and (c)'';
    m. In paragraph (c) of section 2.1.1.5 by revising the final 
sentence;
    n. In section 2.1.2 by revising the words ``section 2.1.2.1'' to 
read ``sections 2.1.2.1 through 2.1.2.5 of this appendix'';
    o. In paragraph (a) of section 2.1.2.1 by adding two new sentences 
at the end of Option 1, by removing the word ``or'' from Option 3, by 
revising the period at the end of Option 4 to read ``; or'', and by 
adding a new Option 5;
    p. Adding two new sentences to the end of paragraph (c) of section 
2.1.2.1;
    q. Revising the first sentence of paragraph (d) of section 2.1.2.1;
    r. Revising the second sentence of paragraph (e) and Table 2-2 in 
section 2.1.2.1;
    s. Revising paragraph (a) of section 2.1.2.2;
    t. In the third sentence of paragraph (b) of section 2.1.2.2 by 
adding the words ``(if applicable)'' after the words `` NO<INF>X</INF> 
emissions'';
    u. Revising the second and third sentences of paragraph (c) of 
section 2.1.2.2;
    v. Revising the fourth sentence of paragraph (a) of section 
2.1.2.3;
    w. In the first sentence of paragraph (b) of section 2.1.2.3 by 
revising the words ``requires a span'' to read ``requires or allows the 
use of a span value'';
    x. Revising the second sentence of paragraph (b) of section 2.1.2.4 
and adding a new sentence after the first sentence;
    y. Removing the first sentence of paragraph (c) of section 2.1.2.4 
and adding three sentences in its place;
    z. In the third sentence of section 2.1.2.5 by revising the words 
``paragraphs (a) and (b)'' to read ``paragraphs (a), (b), and (c)'';
    aa. In paragraph (c) of section 2.1.2.5 by adding the word 
``diagnostic'' before the words ``linearity test'' in the fifth 
sentence and by revising the final sentence;
    bb. Amending section 2.1.3 by adding a sentence to the end of the 
section;
    cc. In section 2.1.3.3 by adding two new sentences to the beginning 
of the section;
    dd. In the fifth sentence of section 2.1.4.2 by adding the words 
``, as specified in section 2.2.2.1 of this appendix'' after the words 
``of the calibration span value'';
    ee. In section 2.1.6 by adding a sentence to the end of that 
section; and
    ff. Revising section 2.2.

    The revisions and additions read as follows:

Appendix A to Part 75--Specifications and Test Procedures

* * * * *

2. Equipment Specifications

2.1 Instrument Span and Range

    * * * To meet these objectives, select the range such that the 
majority of the readings obtained during typical unit operation are 
kept, to the extent practicable, between 20.0 and 80.0 percent of 
the full-scale range of the instrument. These guidelines do not 
apply to: (1) SO<INF>2</INF> readings obtained during the combustion 
of very low sulfur fuel (as defined in Sec. 72.2 of this chapter); 
(2) SO<INF>2</INF> or NO<INF>X</INF> readings recorded on the high 
measurement range, for units with SO<INF>2</INF> or NO<INF>X</INF> 
emission controls and two span values, unless the emission controls 
are operated seasonally (for example, only during the ozone season); 
or (3) SO<INF>2</INF> or NO<INF>X</INF> readings less than 20.0 
percent of full-scale on the low measurement range for a dual span 
unit, provided that the maximum expected concentration (MEC), low-
scale span value, and low-scale range settings have been determined 
according to sections 2.1.1.2, 2.1.1.4(a), (b), and (g) of this 
appendix (for SO<INF>2</INF>), or according to sections 2.1.2.2, 
2.1.2.4(a) and (f) of this appendix (for NO<INF>X</INF>).

2.1.1  SO<INF>2</INF> Pollutant Concentration Monitors * * *

2.1.1.1  Maximum Potential Concentration

    (a) * * *

Where, * * *
%S = Maximum sulfur content of fuel to be fired, wet basis, weight 
percent, as determined according to the applicable method in 
paragraph (c) of section 2.1.1.1.
* * * * *
GCV = Minimum gross calorific value of the fuel or blend to be 
combusted, based on historical fuel sampling and analysis data or, 
if applicable, based on the fuel contract specifications (Btu/lb). 
If based on fuel sampling and analysis, the GCV shall be determined 
according to the applicable method in paragraph (c) of section 
2.1.1.1.
* * * * *
    (b) * * * Note that the initial MPC value is subject to periodic 
review under section 2.1.1.5 of this appendix. If an MPC value is 
found to be either inappropriately high or low, the MPC shall be 
adjusted in accordance with section 2.1.1.5, and corresponding span 
and range adjustments shall be made, if necessary.
* * * * *

2.1.1.2  Maximum Expected Concentration

    (a) * * * Each initial MEC value shall be documented in the 
monitoring plan required under Sec. 75.53. Note that each initial 
MEC value is subject to periodic review under section 2.1.1.5 of 
this appendix. If an MEC value is found to be either inappropriately 
high or low, the MEC shall be adjusted in accordance with section 
2.1.1.5, and corresponding span and range adjustments shall be made, 
if necessary.
* * * * *

2.1.1.3  Span Value(s) and Range(s)

    * * * If the SO<INF>2</INF> span concentration is <ls-thn-eq> 
500 ppm, the span value may either be rounded upward to the next 
highest multiple of 10 ppm, or to the next highest multiple of 100 
ppm. * * * If an existing State, local, or federal requirement for 
span of an SO<INF>2</INF> pollutant concentration monitor requires 
or allows the use of a span value lower than that required by this 
section or by section 2.1.1.4 of this appendix, the State, local, or 
federal span value may be used if a satisfactory explanation is 
included in the monitoring plan, unless span and/or range 
adjustments become necessary in accordance with section 2.1.1.5 of 
this appendix. * * *

2.1.1.4  Dual Span and Range Requirements

* * * * *
    (c) * * * Alternatively, if RATAs are performed and passed on 
both measurement ranges, the owner or operator may use two separate 
SO<INF>2</INF> analyzers connected to separate probes and sample 
interfaces. * * *
    (d) The owner or operator shall designate the monitoring systems 
and components in the monitoring plan under Sec. 75.53 as follows: 
when a single probe and sample interface are used, either designate 
the low and high monitor ranges as separate SO<INF>2</INF> 
components of a single, primary SO<INF>2</INF> monitoring system; 
designate the low and high monitor ranges as the SO<INF>2</INF> 
components of two separate, primary SO<INF>2</INF> monitoring 
systems; designate the normal monitor range as a primary monitoring 
system and the other monitor range as a non-redundant backup 
monitoring system; or, when a single, dual-range SO<INF>2</INF> 
analyzer is used, designate the low and high ranges as a single 
SO<INF>2</INF> component of a primary SO<INF>2</INF> monitoring 
system (if this option is selected, use a special dual-range 
component type code, as specified by the Administrator, to satisfy 
the requirements of Sec. 75.53(e)(1)(iv)(D)). When two 
SO<INF>2</INF> analyzers are connected to separate probes and sample 
interfaces, designate the analyzers as the SO<INF>2</INF> components 
of two separate, primary SO<INF>2</INF> monitoring systems. For 
units with SO<INF>2</INF> controls, if the default high range value 
is used, designate the low range analyzer as the SO<INF>2</INF> 
component of a primary SO2 monitoring system. * * *
* * * * *

2.1.1.5  Adjustment of Span and Range

* * * * *

[[Page 32029]]

    (c) * * * Use the data validation procedures in 
Sec. 75.20(b)(3), beginning with the hour in which the span is 
changed.
* * * * *

2.1.2.1  Maximum Potential Concentration

    (a) * * *
    Option 1: * * * For cement kilns, use 2000 ppm as the MPC. For 
process heaters, use 200 ppm if the unit burns only gaseous fuel and 
500 ppm if the unit burns oil;
* * * * *
    Option 5: If a reliable estimate of the uncontrolled 
NO<INF>X</INF> emissions from the unit is available from the 
manufacturer, the estimated value may be used.
* * * * *
    (c) * * * Note that whichever MPC option in section 2.1.2.1(a) 
of this appendix is selected, the initial MPC value is subject to 
periodic review under section 2.1.2.5 of this appendix. If an MPC 
value is found to be either inappropriately high or low, the MPC 
shall be adjusted in accordance with section 2.1.2.5, and 
corresponding span and range adjustments shall be made, if 
necessary.
    (d) For units with add-on NO<INF>X</INF> controls (whether or 
not the unit is equipped with low-NO<INF>X</INF> burner technology), 
or for units equipped with dry low-NO<INF>X</INF> (DLN) technology, 
NO<INF>X</INF> emission testing may only be used to determine the 
MPC if testing can be performed either upstream of the add-on 
controls or during a time or season when the add-on controls or DLN 
are not in operation. * * *
    (e) * * * For a unit with add-on NO<INF>X</INF> controls 
(whether or not the unit is equipped with low-NO<INF>X</INF> burner 
technology), or for a unit equipped with dry low-NO<INF>X</INF> 
(DLN) technology, historical CEM data may only be used to determine 
the MPC if the 720 quality assured monitor operating hours of CEM 
data are collected upstream of the add-on controls or if the 720 
hours of data include periods when the add-on controls or DLN are 
not in operation. * * *

 Table 2-2.--Maximum Potential Concentration for NO<INF>X</INF>--Gas- and Oil-Fired
                                  Units
------------------------------------------------------------------------
                                                              Maximum
                                                             potential
                        Unit type                          concentration
                                                           for NO<INF>X</INF> (ppm)
------------------------------------------------------------------------
Tangentially-fired dry bottom............................           380
Wall-fired dry bottom....................................           600
Roof-fired (vertically-fired) dry bottom, arch-fired.....           550
Existing combustion turbine..............................           200
New combustion turbine, permitted to fire either oil or             200
 natural gas.............................................
New combustion turbine, permitted to fire only natural              150
 gas.....................................................
Others...................................................        (\1\)
------------------------------------------------------------------------
\1\ As approved by the Administrator.

2.1.2.2  Maximum Expected Concentration

    (a) Make an initial determination of the maximum expected 
concentration (MEC) of NO<INF>X</INF> during normal operation for 
affected units with add-on NO<INF>X</INF> controls of any kind 
(e.g., steam injection, water injection, SCR, or SNCR) and for 
turbines that use dry low- NO<INF>X</INF> technology. Also determine 
the MEC for uncontrolled units and units that use only low 
NO<INF>X</INF> burners (LNB) for NO<INF>X</INF> control, if more 
than one type of fuel is combusted in the unit. Determine a separate 
MEC value for each type of fuel (or blend) combusted in the unit, 
except for fuels that are only used for unit startup and/or flame 
stabilization and except for the fuel or blend that was used to 
determine the MPC under section 2.1.2.1 of this appendix. Calculate 
the MEC of NO<INF>X</INF> using Equation A-2, if applicable, 
inserting the maximum potential concentration, as determined using 
the procedures in section 2.1.2.1 of this appendix. Where Equation 
A-2 is not applicable, set the MEC either by: (1) Measuring the 
NO<INF>X</INF> concentration using the testing procedures in this 
section; (2) using historical CEM data over the previous 720 (or 
more) quality assured monitor operating hours; or (3) if the unit 
has add-on NO<INF>X</INF> controls or uses dry low NO<INF>X</INF> 
technology, and has a federally-enforceable permit limit for 
NO<INF>X</INF> concentration, the permit limit may be used as the 
MEC. Include in the monitoring plan for the unit each MEC value and 
the method by which the MEC was determined. Note that each initial 
MEC value is subject to periodic review under section 2.1.2.5 of 
this appendix. If an MEC value is found to be either inappropriately 
high or low, the MEC shall be adjusted in accordance with section 
2.1.2.5, and corresponding span and range adjustments shall be made, 
if necessary.
* * * * *
    (c) * * * The data base for the MEC shall not include any CEM 
data recorded during unit startup, shutdown, or malfunction or (for 
units with add-on NO<INF>X</INF> controls or turbines using dry low 
NO<INF>X</INF> technology) during any NO<INF>X</INF> control device 
malfunctions or outages. All NO<INF>X</INF> control devices and 
methods used to reduce NO<INF>X</INF> emissions (if applicable) must 
be operating properly during each hour. * * *

2.1.2.3  Span Value(s) and Range(s)

    (a) * * * If the NO<INF>X</INF> span concentration is 
<ls-thn-eq>500 ppm, the span value may either be rounded upward to 
the next highest multiple of 10 ppm, or to the next highest multiple 
of 100 ppm. * * *
* * * * *

2.1.2.4  Dual Span and Range Requirements

* * * * *
    (b) * * * Two separate NO<INF>X</INF> analyzers connected to 
separate probes and sample interfaces may be used if RATAs are 
passed on both ranges. For units with add-on NO<INF>X</INF> emission 
controls (e.g., steam injection, water injection, SCR, or SNCR) or 
units equipped with dry low-NO<INF>X</INF> technology, the owner or 
operator may use a low range analyzer and a ``default high range 
value,'' as described in section 2.1.2.4(e) of this appendix, in 
lieu of maintaining and quality assuring a high-scale range. * * *
    (c) The owner or operator shall designate the monitoring systems 
and components in the monitoring plan under Sec. 75.53 as follows: 
When a single probe and sample interface are used, either designate 
the low and high ranges as separate NO<INF>X</INF> components of a 
single, primary NO<INF>X</INF> monitoring system; designate the low 
and high ranges as the NO<INF>X</INF> components of two separate, 
primary NO<INF>X</INF> monitoring systems; designate the normal 
range as a primary monitoring system and the other range as a non-
redundant backup monitoring system; or, when a single, dual-range 
NO<INF>X</INF> analyzer is used, designate the low and high ranges 
as a single NO<INF>X</INF> component of a primary NO<INF>X</INF> 
monitoring system (if this option is selected, use a special dual-
range component type code, as specified by the Administrator, to 
satisfy the requirements of Sec. 75.53(e)(1)(iv)(D)). When two 
NO<INF>X</INF> analyzers are connected to separate probes and sample 
interfaces, designate the analyzers as the NO<INF>X</INF> components 
of two separate, primary NO<INF>X</INF> monitoring systems. For 
units with add-on NO<INF>X</INF> controls or units equipped with dry 
low-NO<INF>X</INF> technology, if the default high range value is 
used, designate the low range analyzer as the NO<INF>X</INF> 
component of the primary NO<INF>X</INF> monitoring system. * * *
* * * * *

2.1.2.5  Adjustment of Span and Range

* * * * *
    (c) * * * Use the data validation procedures in 
Sec. 75.20(b)(3), beginning with the hour in which the span is 
changed.

2.1.3  CO<INF>2</INF> and O<INF>2</INF> Monitors

     * * * If a dual-range or autoranging diluent analyzer is 
installed, the analyzer may be represented in the monitoring plan as 
a single component, using a special component type code specified by 
the Administrator to satisfy the requirements of 
Sec. 75.53(e)(1)(iv)(D).
* * * * *

2.1.3.3  Adjustment of Span and Range

    The MPC and MEC values for diluent monitors are subject to the 
same periodic review as SO<INF>2</INF> and NO<INF>X</INF> monitors 
(see sections 2.1.1.5 and 2.1.2.5 of this appendix). If an MPC or 
MEC value is found to be either inappropriately high or low, the MPC 
shall be adjusted and corresponding span and range adjustments shall 
be made, if necessary. * * *
* * * * *

2.1.6  Maximum Potential Moisture Percentage

     * * * Alternatively, a default maximum potential moisture value 
of 15 percent H<INF>2</INF>O may be used.

2.2  Design for Quality Control Testing

2.2.1  Pollutant Concentration and CO<INF>2</INF> or O<INF>2</INF> 
Monitors

    (a) Design and equip each pollutant concentration and 
CO<INF>2</INF> or O<INF>2</INF> monitor with a calibration gas 
injection port that allows a check of the entire measurement system 
when calibration gases are introduced. For extractive and dilution 
type monitors, all monitoring components exposed to the sample gas, 
(e.g., sample lines, filters, scrubbers, conditioners, and as much 
of the probe as practicable) are included in the measurement system. 
For in situ type

[[Page 32030]]

monitors, the calibration must check against the injected gas for 
the performance of all active electronic and optical components 
(e.g. transmitter, receiver, analyzer).
    (b) Design and equip each pollutant concentration or 
CO<INF>2</INF> or O<INF>2</INF> monitor to allow daily 
determinations of calibration error (positive or negative) at the 
zero- and mid- or high-level concentrations specified in section 5.2 
of this appendix.

2.2.2  Flow Monitors

    Design all flow monitors to meet the applicable performance 
specifications.

2.2.2.1  Calibration Error Test

    Design and equip each flow monitor to allow for a daily 
calibration error test consisting of at least two reference values: 
(1) Zero to 20 percent of span or an equivalent reference value 
(e.g., pressure pulse or electronic signal) and (2) 50 to 70 percent 
of span. Flow monitor response, both before and after any 
adjustment, must be capable of being recorded by the data 
acquisition and handling system. Design each flow monitor to allow a 
daily calibration error test of (1) the entire flow monitoring 
system, from and including the probe tip (or equivalent) through and 
including the data acquisition and handling system, or (2) the flow 
monitoring system from and including the transducer through and 
including the data acquisition and handling system.

2.2.2.2  Interference Check

    (a) Design and equip each flow monitor with a means to ensure 
that the moisture expected to occur at the monitoring location does 
not interfere with the proper functioning of the flow monitoring 
system. Design and equip each flow monitor with a means to detect, 
on at least a daily basis, pluggage of each sample line and sensing 
port, and malfunction of each resistance temperature detector (RTD), 
transceiver or equivalent.
    (b) Design and equip each differential pressure flow monitor to 
provide (1) an automatic, periodic back purging (simultaneously on 
both sides of the probe) or equivalent method of sufficient force 
and frequency to keep the probe and lines sufficiently free of 
obstructions on at least a daily basis to prevent velocity sensing 
interference, and (2) a means for detecting leaks in the system on 
at least a quarterly basis (manual check is acceptable).
    (c) Design and equip each thermal flow monitor with a means to 
ensure on at least a daily basis that the probe remains sufficiently 
clean to prevent velocity sensing interference.
    (d) Design and equip each ultrasonic flow monitor with a means 
to ensure on at least a daily basis that the transceivers remain 
sufficiently clean (e.g., backpurging system) to prevent velocity 
sensing interference.


Appendix A to Part 75  [Amended]

    49. Section 3 of Appendix A to Part 75 is amended by:
    a. In section heading 3.3.1 by adding the word ``Monitors'' after 
the word ``SO<INF>2</INF>'';
    b. Revising section 3.3.1;
    c. Revising paragraph (a) of section 3.3.2;
    d. In the first sentence of paragraph (b) of section 3.3.2 by 
revising the words ``not exceed'' to read ``be within'';
    e. In section heading 3.3.3 by removing the words ``Pollutant 
Concentration'';
    f. In paragraph 3.3.3 by adding ``<plus-minus>'' before the words 
``1.0 percent'';
    g. In section heading 3.3.4 by adding the word ``Monitors'' after 
the word ``Flow'';
    h. Revising section 3.3.4;
    i. In the second sentence of section 3.3.6 by revising the words 
``appendix are'' to read ``appendix is''; and
    j. Revising the second sentence of paragraph (b) of section 3.3.7.
    The revisions and additions read as follows:

3. Performance Specifications

* * * * *

3.3  Relative Accuracy

3.3.1  Relative Accuracy for SO<INF>2</INF> Monitors

    (a) The relative accuracy for SO<INF>2</INF> pollutant 
concentration monitors shall not exceed 10.0 percent except as 
provided below in this section.
    (b) For affected units where the average of the reference method 
measurements of SO<INF>2</INF> concentration during the relative 
accuracy test audit is less than or equal to 250.0 ppm, the mean 
value of the monitor measurements shall be within <plus-minus>15.0 
ppm of the reference method mean value wherever the relative 
accuracy specification of 10.0 percent is not achieved.

3.3.2  Relative Accuracy for NO<INF>X</INF>-Diluent Continuous 
Monitoring Systems

    (a) The relative accuracy for NO<INF>X</INF>-diluent continuous 
emission monitoring systems shall not exceed 10.0 percent at any 
load level at which a RATA is performed (the low, mid, or high load 
level, as defined in section 6.5.2.1 of this appendix).
* * * * *

3.3.4  Relative Accuracy for Flow Monitors

    (a) The relative accuracy of flow monitors shall not exceed 10.0 
percent at any load level at which a RATA is performed (the low, 
mid, or high load level, as defined in section 6.5.2.1 of this 
appendix).
    (b) For affected units where the average of the flow reference 
method measurements of gas velocity at a particular load level of 
the relative accuracy test audit is less than or equal to 10.0 fps, 
the mean value of the flow monitor velocity measurements shall be 
within <plus-minus>2.0 fps of the reference method mean value in fps 
at that load level, wherever the 10.0 percent relative accuracy 
specification is not achieved.
* * * * *

3.3.7  Relative Accuracy for NO<INF>X</INF> Concentration Monitoring 
Systems

* * * * *
    (b) * * * Alternatively, for affected units where the average of 
the reference method measurements of NO<INF>X</INF> concentration 
during the relative accuracy test audit is less than or equal to 
250.0 ppm, the mean value of the continuous emission monitoring 
system measurements shall be within <plus-minus>15.0 ppm of the 
reference method mean value.
* * * * *
    50. Section 4 of Appendix A to Part 75 is amended by:
    a. Revising the second sentence of the first paragraph of section 
4;
    b. Removing the last sentence of the first paragraph of section 4; 
and
    c. In subparagraph (3) of section 4 by adding the words ``the 
appropriate'' before the word ``units'', by removing the words ``of the 
standard'', and by adding the word ``e.g.,'' before the words ``lb/
hr''.
    The revisions and additions read as follows:

4. Data Acquisition and Handling Systems

    * * * These systems also shall have the capability of 
interpreting and converting the individual output signals from an 
SO<INF>2</INF> pollutant concentration monitor, a flow monitor, a 
CO<INF>2</INF> monitor, a NO<INF>X</INF> pollutant concentration 
monitor, and a NO<INF>X</INF>-diluent continuous emission monitoring 
system to produce a continuous readout of pollutant mass emission 
rates in the appropriate units (e.g., lb/hr, lb/mmBtu, tons/hr). * * 
*

* * * * *


Appendix A to Part 75  [Amended]

    51. Section 6 of Appendix A to Part 75 is amended by:
    a. In the first sentence of paragraph (a) of section 6.2 by adding 
the word ``conditional'' before the words ``data validation 
procedures'';
    b. In section 6.3.1 by removing the word ``extended'' before the 
words ``unit outages'' in the second sentence, and by adding a new 
sentence after the second sentence;
    c. In the first sentence of paragraph (a) of section 6.3.1 by 
adding the word ``conditional'' before the words ``data validation 
procedures'';
    d. In the fourth sentence of section 6.3.2 by removing the word 
``extended'' before the words ``unit outages'', and by adding a new 
sentence after the fourth sentence;
    e. In the first sentence of paragraph (a) of section 6.3.2 by 
adding the word ``conditional'' before the words ``data validation 
procedures'';
    f. In the first sentence of paragraph (a) of section 6.4 by adding 
the word ``conditional'' before the words ``data validation 
procedures'';
    g. In the first sentence of section 6.5 by adding the word ``and'' 
after the words ``heat input,'' and by removing the words ``and each 
SO<INF>2</INF>-diluent continuous emission monitoring system'';

[[Page 32031]]

    h. Revising paragraphs (a) and (c) of section 6.5;
    i. In the first sentence of paragraph (f)(1) of section 6.5 by 
adding the word ``conditional'' before the words ``data validation 
procedures'';
    j. In the second sentence of paragraph (g) of section 6.5 by 
removing the words ``SO<INF>2</INF>-diluent'';
    k. Revising paragraph (a) of section 6.5.1 and paragraph (a) of 
section 6.5.2;
    l. In paragraph (b) of section 6.5.2 by revising the words 
``section 6.5.2.1'' to read ``section 6.5.2.1(d)'';
    m. In paragraph (c) of section 6.5.2 by adding the words ``(or 
three operating levels)'' after the word ``level(s)'';
    n. In paragraph (d) of section 6.5.2 by adding the words ``(or 
operating levels)'' after the word ``level(s)'';
    o. In section heading 6.5.2.1 by adding the words ``(or 
Operating)'' after the words ``Normal Load'';
    p. Revising paragraph (a) of section 6.5.2.1;
    q. In the first sentence of paragraph (b) of section 6.5.2.1 by 
revising the words ``30.0 to 60.0 percent'' to read ``> 30.0 percent, 
but <ls-thn-eq> 60.0 percent'' and revising the words ``60.0 to 100.0 
percent'' to read ``> 60.0 percent'';
    r. Revising paragraphs (c) and (d) of section 6.5.2.1;
    s. Revising the first sentence of paragraph (e) of section 6.5.2.1;
    t. Removing and reserving section 6.5.3;
    u. Amending section 6.5.6 by removing the third sentence;
    v. In paragraph (b)(2) of section 6.5.6 by revising the number 
``1.0'' To read ``1.2'';
    w. Adding paragraph (b)(5) to section 6.5.6;
    x. In the first sentence of paragraph (a) of sections 6.5.6.1 and 
6.5.6.2 by revising the words ``normal load'' to read ``the normal load 
level (or normal operating level)'';
    y. In paragraph (c) of section 6.5.6.3 by removing the words 
``Sec. 75.56(a)(7) or'' and the words ``, as applicable'';
    z. In paragraph (a) of section 6.5.7 by removing the words ``or 
SO<INF>2</INF>-diluent'' in the fourth sentence, by adding one sentence 
before, and two sentences after, the ninth sentence, and by removing 
the words ``Sec. 75.56(a)(5)(ix) and'' from the next to last sentence; 
and
    aa. In section 6.5.10 by adding a comma after the number ``7D'', 
and by adding a new third sentence.
    The revisions and additions read as follows:

6. Certification Tests and Procedures

* * * * *

6.3  7-Day Calibration Error Test

6.3.1  Gas Monitor 7-Day Calibration Error Test

    * * * Notwithstanding this requirement, for a peaking unit (as 
defined in Sec. 72.2 of this chapter), only 3 of the 7 days in the 
test need be unit operating days. * * *
* * * * *

6.3.2  Flow Monitor 7-Day Calibration Error Test

    * * * Notwithstanding these requirements, for a peaking unit (as 
defined in Sec. 72.2 of this chapter), only 3 of the 7 days in the 
test need be unit operating days. * * *
* * * * *

6.5  Relative Accuracy and Bias Tests (General Procedures)

* * * * *
    (a) Except as provided in Sec. 75.21(a)(5), perform each RATA 
while the unit (or units, if more than one unit exhausts into the 
flue) is combusting the fuel that is a normal primary or backup fuel 
for that unit (for some units, more than one type of fuel may be 
considered normal, e.g., a unit that combusts gas or oil on a 
seasonal basis). For units that co-fire fuels as the predominant 
mode of operation, perform the RATAs while co-firing. When relative 
accuracy test audits are performed on continuous emission monitoring 
systems installed on bypass stacks/ducts, use the fuel normally 
combusted by the unit (or units, if more than one unit exhausts into 
the flue) when emissions exhaust through the bypass stack/ducts.
* * * * *
    (c) For monitoring systems with dual ranges, perform the 
relative accuracy test on the range normally used for measuring 
emissions. For units with add-on SO<INF>2</INF> or NO<INF>X</INF> 
controls that operate continuously rather than seasonally, or for 
units that need a dual range to record high concentration ``spikes'' 
during startup conditions, the low range is considered normal. 
However, for some dual span units (e.g., for units that use fuel 
switching or for which the emission controls are operated 
seasonally), provided that both monitor ranges are connected to a 
common probe and sample interface, either of the two measurement 
ranges may be considered normal; in such cases, perform the RATA on 
the range that is in use at the time of the scheduled test. If the 
low and high measurement ranges are connected to separate sample 
probes and interfaces, RATA testing on both ranges is required.
* * * * *

6.5.1  Gas Monitoring System RATAs (Special Considerations)

    (a) Perform the required relative accuracy test audits for each 
SO<INF>2</INF> or CO<INF>2</INF> pollutant concentration monitor, 
each CO<INF>2</INF> or O2 diluent monitor used to determine heat 
input, each NO<INF>X</INF>-diluent continuous emission monitoring 
system, and each NO<INF>X</INF> concentration monitoring system used 
to determine NO<INF>X</INF> mass emissions, as defined in 
Sec. 75.71(a)(2) at the normal load level or normal operating level 
for the unit (or combined units, if common stack), as defined in 
section 6.5.2.1 of this appendix. If two load levels or operating 
levels have been designated as normal, the RATAs may be done at 
either load level.
* * * * *

6.5.2  Flow Monitor RATAs (Special Considerations)

    (a) Except for flow monitors on bypass stacks/ducts and peaking 
units, perform relative accuracy test audits for the initial 
certification of each flow monitor at three different exhaust gas 
velocities (low, mid, and high), corresponding to three different 
load levels or operating levels within the range of operation, as 
defined in section 6.5.2.1 of this appendix. For a common stack/
duct, the three different exhaust gas velocities may be obtained 
from frequently used unit/load or operating level combinations for 
the units exhausting to the common stack. Select the three exhaust 
gas velocities such that the audit points at adjacent load or 
operating levels (i.e., low and mid or mid and high), in megawatts 
(or in thousands of lb/hr of steam production or in ft/sec, as 
applicable), are separated by no less than 25.0 percent of the range 
of operation, as defined in section 6.5.2.1 of this appendix.
* * * * *

6.5.2.1  Range of Operation and Normal Load (or Operating) Load 
Level(s)

    (a) The owner or operator shall determine the upper and lower 
boundaries of the ``range of operation'' as follows for each unit 
(or combination of units, for common stack configurations) 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:
    (1) For affected units that produce electrical output (in 
megawatts) or thermal output (in klb/hr of steam production), the 
lower boundary of the range of operation of a unit shall be the 
minimum safe, stable load. For common stacks, the minimum safe, 
stable load shall be the lowest of the minimum safe, stable loads 
for any of the units discharging through the stack. Alternatively, 
for a group of frequently-operated units that serve a common stack, 
the sum of the minimum safe, stable loads for the individual units 
may be used as the lower boundary of the range of operation. The 
upper boundary of the range of operation of a unit shall be the 
maximum sustainable load. The ``maximum sustainable load'' is the 
higher of either: the nameplate or rated capacity of the unit, less 
any physical or regulatory limitations or other deratings; or the 
highest sustainable unit load, based on at least four quarters of 
representative historical operating data. For common stacks, the 
maximum sustainable load is the sum of all of the maximum 
sustainable loads of the individual units discharging through the 
stack, unless this load is unattainable in practice, in which case 
use the highest sustainable combined load for the units that 
discharge through the stack, based on at least four quarters of 
representative historical operating data. The load values for the 
unit(s) shall be expressed either in units of megawatts or thousands 
of lb/hr of steam load; or

[[Page 32032]]

    (2) For affected units that do not produce electrical or thermal 
output, the lower boundary of the range of operation shall be the 
minimum expected flue gas velocity (in ft/sec) during normal, stable 
operation of the unit. The upper boundary of the range of operation 
shall be the maximum potential flue gas velocity (in ft/sec) as 
defined in section 2.1.4.1 of this appendix. The minimum expected 
and maximum potential velocities may be derived from the results of 
reference method testing or by using Equation A-3a or A-3b (as 
applicable) in section 2.1.4.1 of this appendix. If Equation A-3a or 
A-3b is used to determine the minimum expected velocity, replace the 
word ``maximum'' to read ``minimum'' in the definitions of ``MPV,'' 
``H<INF>f</INF>,'' ``% O<INF>2</INF><INF>d</INF>,'' and ``% 
H<INF>2</INF>O,'' and replace the word ``minimum'' to read 
``maximum'' in the definition of ``CO<INF>2</INF><INF>d</INF>.''
* * * * *
    (c) Analysis of historical load or operating level data. (1) For 
units that produce electrical or thermal output, the owner or 
operator shall identify, for each affected unit or common stack 
(except for peaking units), the ``normal'' load level or levels 
(low, mid or high), based on the operating history of the unit(s). 
To identify the normal load level(s), the owner or operator shall, 
at a minimum, determine the relative number of operating hours at 
each of the three load levels, low, mid and high over the past four 
representative operating quarters. The owner or operator shall 
determine, to the nearest 0.1 percent, the percentage of the time 
that each load level (low, mid, high) has been used during that time 
period. A summary of the data used for this determination and the 
calculated results shall be kept on-site in a format suitable for 
inspection. For new units or newly-affected units, the data analysis 
in this paragraph may be based on fewer than four quarters of data 
if fewer than four representative quarters of historical load data 
are available. Or, if no historical load data are available, the 
owner or operator may designate the normal load based on the 
expected or projected manner of operating the unit. However, in 
either case, once four quarters of representative data become 
available, the historical load analysis shall be repeated.
    (2) If the affected unit does not produce electrical or steam 
load, follow the procedures in paragraph (c)(1) of this section, 
except that:
    (i) The words ``load level'' shall read ``operating level;'' and
    (ii) If the unit does not have an installed flow monitor, the 
historical data analysis described in paragraph (c)(1) of this 
section is not required.
    (d) Determination of normal load. (1) Based on the analysis of 
the historical load data described in paragraph (c) of this section, 
the owner or operator shall, for units that produce electrical or 
thermal output, designate the most frequently used load level as the 
normal load level for the unit (or combination of units, for common 
stacks). The owner or operator may also designate the second most 
frequently used load level as an additional normal load level for 
the unit or stack. For peaking units, normal load designations are 
unnecessary; the entire operating load range shall be considered 
normal. If the manner of operation of the unit changes 
significantly, such that the designated normal load(s) or the two 
most frequently used load levels change, the owner or operator shall 
repeat the historical load analysis and shall redesignate the normal 
load(s) and the two most frequently used load levels, as 
appropriate. A minimum of two representative quarters of historical 
load data are required to document that a change in the manner of 
unit operation has occurred. Update the electronic monitoring plan 
whenever the normal load level(s) and the two most frequently-used 
load levels are redesignated.
    (2) For units that do not produce electrical or thermal output, 
follow the procedures in paragraph (d)(1) of this section, except 
that:
    (i) The words ``load'' and ``load level'' shall read ``operating 
level;'' and
    (ii) If the unit does not have an installed flow monitor, the 
two most frequently-used operating levels and the normal operating 
level(s) shall be determined using sound engineering judgment, in 
lieu of performing a historical data analysis. The operating level 
determinations shall be based on knowledge of the unit, operating 
experience with the unit, and actual stack gas velocity measurements 
using EPA Method 2 in appendix A to part 60 of this chapter (or its 
allowable alternatives).
    (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 of steam production or ft/sec (as applicable), in the 
electronic quarterly report required under Sec. 75.64. * * *
* * * * *

6.5.6  Reference Method Traverse Point Selection

* * * * *
    (b) * * *
    (5) If Method 7E is used as the reference method for the RATA of 
a NO<INF>X</INF> CEMS installed on a combustion turbine, the 
reference method measurements may be made at the sampling points 
specified in section 6.1.2 of Method 20 in appendix A to part 60 of 
this chapter.
* * * * *

6.5.7  Sampling Strategy

    (a) * * * Also, allow sufficient measurement time to ensure that 
stable temperature readings are obtained at each traverse point, 
particularly at the first measurement point at each sample port, 
when a probe is moved sequentially from port-to-port. * * * 
Alternatively, moisture measurements for molecular weight 
determination may be performed before and after a series of RATA 
runs at a particular load level (low, mid, or high), provided that 
the time interval between the two moisture measurements does not 
exceed three hours. If this option is selected, the results of the 
two moisture determinations shall be averaged arithmetically and 
applied to all RATA runs in the series. * * *
* * * * *

6.5.10  Reference Methods

    * * * Notwithstanding these requirements, Method 20 may be used 
as the reference method for relative accuracy test audits of 
NO<INF>X</INF> monitoring systems installed on combustion turbines.

Appendix A to Part 75  [Amended]

    52. Section 7 of Appendix A to Part 75 is amended by:
    a. In section heading 7.3 by revising the words ``SO<INF>2</INF>-
Diluent Continuous Emission'' to read ``O<INF>2</INF> Monitors, 
NO<INF>X</INF> Concentration'';
    b. Revising the first sentence of section 7.3;
    c. Revising the variable
    [GRAPHIC] [TIFF OMITTED] TP13JN01.002
    

in the list of defined variables for Eq. A-7 to be
[GRAPHIC] [TIFF OMITTED] TP13JN01.003


and removing the final sentence of section 7.3.1;
    d. In the section heading and text of section 7.4 by revising the 
word `` NO<INF>X</INF>'' to read `` NO<INF>X</INF>-diluent'';
    e. In section heading 7.4.2 by removing the words ``(Monitoring 
System)'';
    f. In the second sentence of section 7.6.1 by adding the words ``or 
NO<INF>X</INF>'' after both occurrences of the word ``SO<INF>2</INF>'' 
and the third sentence by revising the word `` NO<INF>X</INF>'' to read 
``NO<INF>X</INF>diluent'';
    g. In paragraph (a) of section 7.7 by removing the fourth sentence;
    h. In paragraph (b) of section 7.7 by removing the first two 
sentences and adding four new sentences;
    i. In the variable ``(Heat Input)<INF>avg</INF>'' under Eq. A-13a 
in paragraph (c) of section 7.7 by adding a second and third sentence 
to the definition;
    j. In paragraph (d) of section 7.7 by adding the words ``(i.e., the 
arithmetic average of the diluent gas concentrations for all clock 
hours in which a RATA run was performed)'' to the end of the sentence;
    k. In section 7.8 by designating the existing text as paragraph 
(a), removing

[[Page 32033]]

the first sentence, adding the words ``and section 2.2.5 of appendix B 
to this part'' to the end of the second sentence, and adding a new 
paragraph (b); and
    l. Revising Figure 6.
    The revisions and additions read as follows:

7. Calculations

* * * * *

7.3  Relative Accuracy for SO<INF>2</INF> and CO<INF>2</INF> 
Pollutant Concentration Monitors, O<INF>2</INF> Monitors, 
NO<INF>X</INF> Concentration Monitoring Systems, and Flow Monitors

    Analyze the relative accuracy test audit data from the reference 
method tests for SO<INF>2</INF> and CO<INF>2</INF> pollutant 
concentration monitors, O<INF>2</INF> monitors used only for heat 
input rate determination, NO<INF>X</INF> concentration monitoring 
systems, and flow monitors using the following procedures. * * *
* * * * *

7.7  Reference Flow-to-Load Ratio or Gross Heat Rate

* * * * *
    (b) In Equation A-13, for a common stack, determine 
L<INF>avg</INF> by summing, for each RATA run, the operating loads 
of all units discharging through the common stack, and then taking 
the arithmetic average of the summed loads. For a unit that 
discharges its emissions through multiple stacks, either determine a 
single value of Q<INF>ref</INF> for the unit or a separate value of 
Q<INF>ref</INF> for each stack. In the former case, calculate 
Q<INF>ref</INF> by summing, for each RATA run, the volumetric flow 
rates through the individual stacks and then taking the arithmetic 
average of the summed RATA run flow rates. In the latter case, 
calculate the value of Q<INF>ref</INF> for each stack by taking the 
arithmetic average, for all RATA runs, of the flow rates through the 
stack. * * *
    (c) * * *
(Heat Input)<INF>avg</INF> = * * * For multiple stack 
configurations, if the reference GHR value is determined separately 
for each stack, use the hourly heat input measured at each stack. If 
the reference GHR is determined at the unit level, sum the hourly 
heat inputs measured at the individual stacks.
* * * * *

7.8  Flow-to-Load Test Exemptions

* * * * *
    (b) Units that do not produce electrical output (in megawatts) 
or thermal output (in klb of steam per hour) are exempted from the 
flow-to-load ratio test requirements of section 7.7 of this appendix 
and section 2.2.5 of appendix B to this part.
* * * * *
[GRAPHIC] [TIFF OMITTED] TP13JN01.004

* * * * *
    53. Section 1 of Appendix B to Part 75 is amended by:
    a. Adding a fourth sentence to section 1; and
    b. Removing the word ``and'' before the words ``section 
2.1.5.1'' in the second sentence of section 1.3.1.
    The revisions and additions read as follows:

Appendix B to Part 75--Quality Assurance and Quality Control Procedures

1. Quality Assurance/Quality Control Program

    * * * Electronic storage of the information in the QA/QC plan is 
permissible, provided that the information can be made available in 
hardcopy upon request during an audit.
* * * * *
    54. Section 2 of Appendix B to Part 75 is amended by:
    a. In paragraph (a) of section 2.1.4 by revising the words `` 200 
ppm'' in the first sentence to read ``> 50.0 ppm but <ls-thn-eq> 200 
ppm, or exceeds 5.0 ppm for span values <ls-thn-eq> 50.0 ppm'';
    b. In the first sentence of section 2.2.1 by revising the word 
``Perform'' to read ``Unless a particular monitor (or monitoring range) 
is exempted under this paragraph or under section 6.2 of appendix A to 
this part, perform'';
    c. In paragraph (c) of section 2.2.3 by adding a third sentence;
    d. In the second sentence of paragraph (e) of section 2.2.3 by 
removing the words ``or SO<INF>2</INF>-diluent'';
    e. In the second sentence of paragraph (f) of section 2.2.3 by 
revising the words ``168 unit operating hour or stack operating hour 
grace period'' to read ``grace period of 168 cumulative unit or stack 
operating hours'';
    f. In paragraph (a) of section 2.2.4 by revising both occurrences 
of the word ``consecutive'' to read ``cumulative'';
    g. In the first sentence of paragraph (b) of section 2.2.4 by 
adding the word ``cumulative'' after the number ``168'' and the words 
``first unit operating'' before the words ``hour following'';
    h. In paragraph (a) of section 2.2.5 by removing the first 
sentence, revising the words ``by an approved petition in accordance 
with'' in the second sentence to read ``from the flow-to-load ratio 
test under'', and by adding a final sentence before Eq. B-1;
    i. Revising the third sentence of paragraph (a)(1) of section 
2.2.5;
    j. In paragraph (a)(3) of section 2.2.5 by adding the word ``rate'' 
after the words ``heat input'';
    k. In paragraph (a)(4) of section 2.2.5 by adding the word 
``acceptable'' after each occurrence of the number ``168'', and by 
adding in the third sentence the words ``(i.e., at loads within 
<plus-minus> 10 percent of L<INF>avg</INF>)'' after the word ``rates'';
    l. Revising the last sentence of paragraph (b) of section 2.2.5;
    m. Revising the introductory text of paragraph (c) of section 
2.2.5;
    n. Adding a new third sentence in paragraph (c)(1) of section 
2.2.5;

[[Page 32034]]

    o. In paragraph (c)(8) of section 2.2.5 by removing the second 
sentence and adding two new sentences in its place;
    p. In the first sentence of the introductory paragraph to section 
2.2.5.1 by revising the words ``two weeks'' to read ``14 unit operating 
days'';
    q. Revising paragraph (b) of section 2.2.5.1;
    r. Revising section 2.2.5.2;
    s. Revising the second and third sentences of paragraph (a) of 
section 2.2.5.3;
    t. In the second sentence of paragraph (b) of section 2.2.5.3 by 
changing the number ``5.0'' to ``10.0'';
    u. In paragraph (c) of section 2.2.5.3 by adding the words ``(if 
applicable)'' after the words ``flow-to-load test'' in the second 
sentence and after the words ``flow monitor'' in the third sentence;
    v. In the fourth sentence of paragraph (a) of section 2.3.1.1 by 
revising the words ``720 unit (or stack) operating hour grace period'' 
to read ``grace period of 720 cumulative unit or stack operating 
hours'';
    w. Removing and reserving paragraph (b) of section 2.3.1.2;
    x. Removing the words ``On and after January 1, 2000,'' and 
capitalizing the letter ``t'' in the first instance of ``the'' in 
paragraph (c) of section 2.3.1.2;
    y. In paragraph (d) of section 2.3.1.2 by adding the words ``, as 
measured by the reference method during the RATA'' after the words 
``<ls-thn-eq>10.0 fps'' and by removing the words ``(10.0 percent if 
prior to January 1, 2000)'';
    z. In paragraph (e) of section 2.3.1.2 by adding the words 
``reference method'' before the word ``concentrations'', and by adding 
the words ``) during the RATA'' after the words ``250 ppm'';
    aa. In paragraph (f) of section 2.3.1.2 by adding the words 
``measured by the reference method during the RATA'' after the words 
``average NO<INF>X</INF> emission rate'';
    bb. Removing and reserving paragraph (g) of section 2.3.1.2;
    cc. In section heading 2.3.1.3 by adding the words ``(or 
Operating)'' after the words ``RATA Load'';
    dd. In paragraph (a) of section 2.3.1.3 by adding the words ``(or 
operating level)'' after each instance of the words ``load level'', 
adding the words ``(or operating levels)'' after the words ``load 
levels'', and by revising the words ``section 6.5.2.1'' to read 
``section 6.5.2.1(d)'';
    ee. In paragraph (b) of section 2.3.1.3 by revising the words 
``section 6.5.2.1'' to read ``section 6.5.2.1(d)'';
    ff. Revising paragraphs (c)(1) through (c)(6) of section 2.3.1.3;
    gg. In paragraph (c) of section 2.3.2 by adding a new third 
sentence;
    hh. In paragraphs (d) and (f) of section 2.3.2 by adding the words 
``(or operating level)'' after each occurrence of the words ``load 
level'', the words ``(or single-level)'' after the word ``single-
load'', the words ``(or multiple-level)'' after the word ``multiple-
load'', the words ``(or operating level(s))'' after the words ``load 
level(s)'', and the words ``(or 3-level)'' after the words ``3-load'';
    ii. Revising paragraph (e) of section 2.3.2;
    jj. In paragraph (a) of section 2.3.3 by revising the first two 
instances of the word ``consecutive'' to read ``cumulative'', removing 
the word ``or'' after the first two semicolons, and by removing the 
words ``consecutive calendar'' after the word ``five'';
    kk. In the first sentence of paragraph (c) of section 2.3.3 by 
adding the word ``cumulative'' after the number ``720'';
    ll. Revising paragraph (b) of section 2.4;
    mm. Revising footnote 2 of Figure 1 to Appendix B of Part 75; and
    nn. In Figure 2 to Appendix B of Part 75 by removing the row for 
``Flow (Phase I)'', renaming the row for ``Flow (Phase II)'' as 
``Flow'', by revising the word ``H<INF>2</INF>O<INF>2</INF>'' in the 
final row to read ``H<INF>2</INF>O<SUP>2</SUP>'', and by adding the 
word ``cumulative'' after both occurrences of the number ``168'' in 
footnote 1 to Figure 2.
    The revisions and additions read as follows:

2. Frequency of Testing

* * * * *

2.2  Quarterly Assessments

* * * * *

2.2.3  Data Validation

* * * * *
    (c) * * * If a routine daily calibration error test is performed 
and passed just prior to a linearity test (or during a linearity 
test period) and a mathematical correction factor is automatically 
applied by the DAHS, the correction factor shall be applied to all 
subsequent data recorded by the monitor, including the linearity 
test data.
* * * * *

2.2.5  Flow-to-Load Ratio or Gross Heat Rate Evaluation

    (a) Applicability and methodology. * * * Alternatively, for the 
reasons stated in paragraphs (c)(1) through (c)(6) of this section, 
the owner or operator may exclude from the data analysis certain 
hours within <plus-minus> 10.0 percent of 
L<INF>a</INF><INF>v</INF><INF>g</INF> and may calculate 
R<INF>h</INF> values for only the remaining hours. * * *
    (1) * * * For a unit that discharges its emissions through 
multiple stacks or that monitors its emissions in multiple 
breechings, Q<INF>h</INF> will be either the combined hourly 
volumetric flow rate for all of the stacks or ducts (if the test is 
done on a unit basis) or the hourly flow rate through each stack 
individually (if the test is performed separately for each stack). * 
* *
* * * * *
    (b) * * * If E<INF>f</INF> is above these limits, the owner or 
operator shall either: implement Option 1 in section 2.2.5.1 of this 
appendix; perform a RATA in accordance with Option 2 in section 
2.2.5.2 of this appendix; or (if applicable) re-examine the hourly 
data used for the flow-to-load or GHR analysis and recalculate 
E<INF>f</INF>, after excluding all non-representative hourly flow 
rates, as provided in paragraph (c) of this section.
    (c) Recalculation of E<INF>f.</INF> If the owner or operator did 
not exclude any hours within <plus-minus>10 percent of L<INF>avg</INF> 
from the original data analysis and chooses to recalculate 
E<INF>f</INF>, the flow rates for the following hours are considered 
non-representative and may be excluded from the data analysis:
    (1) * * * Also, for units that co-fire different types of fuels, 
if the reference RATA was done while co-firing, then hours in which 
a single fuel was combusted may be excluded from the data analysis 
as different fuel hours (and vice-versa for co-fired hours, if the 
reference RATA was done while combusting only one type of fuel);
* * * * *
    (8) * * * If, however, E<INF>f</INF> is still above the 
applicable limit, data from the monitor shall be declared out-of-
control, beginning with the first unit operating hour following the 
quarter in which E<INF>f</INF> exceeded the applicable limit. 
Alternatively, if a probationary calibration error test is performed 
and passed according to Sec. 75.20(b)(3)(ii), data from the monitor 
may be declared conditionally valid following the quarter in which 
E<INF>f</INF> exceeded the applicable limit. * * *

2.2.5.1  Option 1

* * * * *
    (b) If a problem with the flow monitor is identified through the 
investigation (including the need to re-linearize the monitor by 
changing the polynomial coefficients or K factor(s)), data from the 
monitor are considered invalid back to the first unit operating hour 
after the end of the calendar quarter for which E<INF>f</INF> was 
above the applicable limit. If the option to use conditional data 
validation was selected under section 2.2.5(c)(8) of this appendix, 
all conditionally valid data shall be invalidated, back to the first 
unit operating hour after the end of the calendar quarter for which 
E<INF>f</INF> was above the applicable limit. Corrective actions 
shall be taken. All corrective actions (e.g., non-routine 
maintenance, repairs, major component replacements, re-linearization 
of the monitor, etc.) shall be documented in the operation and 
maintenance records for the monitor. The owner or operator then 
shall either complete the abbreviated flow-to-load test in section 
2.2.5.3 of this appendix, or, if the corrective action taken has 
required relinearization of the flow monitor, shall perform a 3-load 
RATA. The conditional data validation procedures in Sec. 75.20(b)(3) 
may be applied to the 3-load RATA.

2.2.5.2  Option 2

    Perform a single-load RATA (at a load designated as normal under 
section 6.5.2.1 of

[[Page 32035]]

appendix A to this part) of each flow monitor for which E<INF>f</INF> 
is outside of the applicable limit. If the RATA is passed hands-off, 
in accordance with section 2.3.2(c) of this appendix, no further 
action is required and the out-of-control period for the monitor 
ends at the date and hour of completion of a successful RATA, unless 
the option to use conditional data validation was selected under 
section 2.2.5(c)(8) of this appendix. In that case, all 
conditionally valid data from the monitor are considered to be 
quality-assured, back to the first unit operating hour following the 
end of the calendar quarter for which the E<INF>f</INF> value was 
above the applicable limit. If the RATA is failed, all data from the 
monitor shall be invalidated, back to the first unit operating hour 
following the end of the calendar quarter for which the E<INF>f</INF> 
value was above the applicable limit. Data from the monitor remain 
invalid until the required RATA has been passed. Alternatively, 
following a failed RATA and corrective actions, the conditional data 
validation procedures of Sec. 75.20(b)(3) may be used until the RATA 
has been passed. If the corrective actions taken following the 
failed RATA included adjustment of the polynomial coefficients or K-
factor(s) of the flow monitor, a 3-level RATA is required.

2.2.5.3  Abbreviated Flow-to-Load Test

    (a) * * * Data from the monitoring system are considered invalid 
from the hour of commencement of the repair, replacement, or 
maintenance until either the hour in which the abbreviated flow-to-
load test is passed, or the hour in which a probationary calibration 
error test is passed following completion of the repair, 
replacement, or maintenance and any associated adjustments to the 
monitor. If the latter option is selected, the abbreviated flow-to-
load test shall be completed within 168 cumulative unit operating 
hours of the probationary calibration error test (or, for peaking 
units, within 30 unit operating days, if that is less restrictive). 
* * *
* * * * *

2.3  Semiannual and Annual Assessments

* * * * *

2.3.1  Relative Accuracy Test Audit (RATA)

* * * * *

2.3.1.3  RATA Load (or Operating) Levels and Additional RATA 
Requirements

* * * * *
    (c) * * *
    (1) An annual 2-load (or 2-level) flow RATA shall be done at the 
two most frequently used load levels (or operating levels), as 
determined under section 6.5.2.1(d) of appendix A to this part. 
Alternatively, a 3-load (or 3-level) flow RATA at the low, mid, and 
high load levels (or operating levels), as defined under section 
6.5.2.1(b) of appendix A to this part, may be performed in lieu of 
the 2-load (or 2-level) annual RATA.
    (2) If the flow monitor is on a semiannual RATA frequency, 2-
load (or 2-level) flow RATAs and single-load (or single-level) flow 
RATAs at the normal load level (or normal operating level) may be 
performed alternately.
    (3) A single-load (or single-level) annual flow RATA may be 
performed in lieu of the 2-load (or 2-level) RATA if the results of 
an historical load data analysis show that in the time period 
extending from the ending date of the last annual flow RATA to a 
date that is no more than 21 days prior to the date of the current 
annual flow RATA, the unit (or combination of units, for a common 
stack) has operated at a single load level (or operating level) 
(low, mid, or high), for <gr-thn-eq>85.0 percent of the time. 
Alternatively, a flow monitor may qualify for a single-load (or 
single-level) RATA if the 85.0 percent criterion is met in the time 
period extending from the beginning of the quarter in which the last 
annual flow RATA was performed through the end of the calendar 
quarter preceding the quarter of current annual flow RATA.
    (4) A 3-load (or 3-level) RATA, at the 
low-, mid-, and high-load levels (or operating levels), as 
determined under section 6.5.2.1 of appendix A to this part, shall 
be performed at least once every five consecutive calendar years.
    (5) A 3-load (or 3-level) RATA is required whenever a flow 
monitor is re-linearized, i.e., when its polynomial coefficients or 
K factor(s) are changed, except for flow monitors installed on 
peaking units and bypass stacks. For peaking units and bypass 
stacks, a single-load RATA at the normal load is required.
    (6) For all multi-level flow audits, the audit points at 
adjacent load levels or at adjacent operating levels (e.g., mid and 
high) shall be separated by no less than 25.0 percent of the ``range 
of operation,'' as defined in section 6.5.2.1 of appendix A to this 
part.
* * * * *

2.3.2  Data Validation

* * * * *
    (c) * * * If a routine daily calibration error test is performed 
and passed just prior to a RATA (or during a RATA test period) and a 
mathematical correction factor is automatically applied by the DAHS, 
the correction factor shall be applied to all subsequent data 
recorded by the monitor, including the RATA test data. * * *
* * * * *
    (e) For a RATA performed using the option in paragraph (b)(1) or 
(b)(2) of this section, if the RATA is failed (that is, if the 
relative accuracy exceeds the applicable specification in section 
3.3 of appendix A to this part) or if the RATA is aborted prior to 
completion due to a problem with the CEMS, then the CEMS is out-of-
control and all emission data from the CEMS are invalidated 
prospectively from the hour in which the RATA is failed or aborted. 
Data from the CEMS remain invalid until the hour of completion of a 
subsequent RATA that meets the applicable specification in section 
3.3 of appendix A to this part. If the option in paragraph (b)(3) of 
this section to use the data validation procedures and associated 
timelines in Secs. 75.20(b)(3)(ii) through(b)(3)(ix) has been 
selected, the beginning and end of the out-of-control period shall 
be determined in accordance with Sec. 75.20(b)(3)(vii)(A) and (B). 
Note that when a RATA is aborted for a reason other than monitoring 
system malfunction (see paragraph (h) of this section), this does 
not trigger an out-of-control period for the monitoring system.
* * * * *

2.4  Recertification, Quality Assurance, RATA Frequency and Bias 
Adjustment Factors (Special Considerations)

* * * * *
    (b) Except as provided in section 2.3.3 of this appendix, 
whenever a passing RATA of a gas monitor is performed, or a passing 
2-load (or 2-level) RATA or a passing 3-load (or 3-level) RATA of a 
flow monitor is performed (irrespective of whether the RATA is done 
to satisfy a recertification requirement or to meet the quality 
assurance requirements of this appendix, or both), the RATA 
frequency (semi-annual or annual) shall be established based upon 
the date and time of completion of the RATA and the relative 
accuracy percentage obtained. For 2-load (or 2-level) and 3-load (or 
3-level) flow RATAs, use the highest percentage relative accuracy at 
any of the loads (or levels) to determine the RATA frequency. The 
results of a single-load (or single-level) flow RATA may be used to 
establish the RATA frequency when the single-load flow RATA is 
specifically required under section 2.3.1.3(b) of this appendix (for 
flow monitors installed on peaking units and bypass stacks) or when 
the single-load (or single-level) RATA is allowed under section 
2.3.1.3(c) of this appendix for a unit that has operated at one load 
level (or operating level) for <gr-thn-eq> 85.0 percent of the time 
since the last annual flow RATA. No other single-load (or single-
level) flow RATA may be used to establish an annual RATA frequency; 
however, a 2-load or 3-load (or a 2-level or 3-level) flow RATA may 
be performed at any time or in place of any required single-load (or 
single-level) RATA, in order to establish an annual RATA frequency.
* * * * *

Figure 1 to Appendix B of Part 75--Quality Assurance Test Requirements

* * * * *
    \2\ For flow monitors installed on peaking units and bypass 
stacks, conduct all RATAs at a single, normal load. For other flow 
monitors, conduct annual RATAs at two load levels (or operating 
levels). Alternating single-level and 2-level RATAs may be done if a 
monitor is on a semiannual frequency. A single-level RATA may be 
done in lieu of a 2-level RATA if, since the last annual flow RATA, 
the unit has operated at one load level (or operating level) for 
<gr-thn-eq> 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.
* * * * *
    55. Appendix C to Part 75 is amended by:
    a. Revising the section heading of section 2;
    b. Revising the fifth sentence in section 2.2.1 and adding a new 
sentence after that fifth sentence;
    c. Revising in section 2.2.3.9 the reference ``75.51(a)(2)'' to 
read ``75.71(a)(2)''; and

[[Page 32036]]

    d. Adding new sections 3 and 4.
    The revisions and additions read as follows:

Appendix C to Part 75--Missing Data Estimation Procedures

* * * * *

2. Load-Based Procedure for Missing Flow Rate, NO<INF>X</INF> 
Concentration, and NO<INF>X</INF> Emission Rate Data

* * * * *

2.2  Procedure

    2.2.1 * * * For a cogenerating unit or other unit at which some 
portion of the heat input is not used to produce electricity or for 
a unit for which hourly average gross load in MWge is not recorded 
separately, determine the maximum hourly average gross load for the 
unit by converting the maximum rated hourly unit heat input 
(including heat input from auxiliary firing, if applicable) to an 
equivalent gross megawatt value, using the percentage efficiencies 
of the main combustion source and (if applicable) any auxiliary 
combustion sources. If the actual percentage efficiency of a 
particular combustion source is unknown, use a default value of 50 
percent for a combustion turbine and 33 percent for any other type 
of combustion source. * * *
* * * * *

3. Non-Load-Based Procedure for Missing Flow Rate, NO<INF>X</INF> 
Concentration, and NO<INF>X</INF> Emission Rate Data (Optional)

3.1  Applicability

    For affected units that do not produce electrical output in 
megawatts or thermal output in klb/hr of steam, this procedure may 
be used in accordance with the provisions of this part to provide 
substitute data for volumetric flow rate (scfh), NO<INF>X</INF> 
emission rate (in lb/mmBtu) from NO<INF>X</INF>-diluent continuous 
emission monitoring systems, and NO<INF>X</INF> concentration data 
(in ppm) from NO<INF>X</INF> concentration monitoring systems used 
to determine NO<INF>X</INF> mass emissions.

3.2  Procedure

    3.2.1  For each monitored parameter (flow rate, NO<INF>X</INF> 
emission rate, or NO<INF>X</INF> concentration), establish at least 
two, but no more than ten operational bins, corresponding to various 
operating conditions and parameters (or combinations of these) that 
affect volumetric flow rate or NO<INF>X</INF> emissions. Include a 
complete description of each operational bin in the hardcopy portion 
of the monitoring plan required under Sec. 75.53(e)(2), identifying 
the unique combination of parameters and operating conditions 
associated with the bin and explaining the relationship between 
these parameters and conditions and the magnitude of the stack gas 
flow rate or NO<INF>X</INF> emissions. Assign a unique number, 1 
through 10, to each operational bin. Examples of conditions and 
parameters that may be used to define operational bins include unit 
heat input, type of fuel combusted, specific stages of an industrial 
process, or (for common stacks), the particular combination of units 
that are in operation.
    3.2.2  In the electronic quarterly report required under 
Sec. 75.64, indicate for each hour of unit operation the operational 
bin associated with the NO<INF>X</INF> or flow rate data, by 
recording the number assigned to the bin under section 3.2.1 of this 
appendix.
    3.2.3  The data acquisition and handling system must be capable 
of properly identifying and recording the operational bin number for 
each unit operating hour. The DAHS must also be capable of 
calculating and recording the following information for each unit 
operating hour of missing flow or NO<INF>X</INF> data within each 
identified operational bin during the shorter of: (a) the previous 
2,160 quality assured monitor operating hours (on a rolling basis), 
or (b) all previous quality assured monitor operating hours:
    3.2.3.1  Average of the hourly flow rates reported by a flow 
monitor (scfh).
    3.2.3.2  The 90th percentile value of hourly flow rates (scfh).
    3.2.3.3  The 95th percentile value of hourly flow rates (scfh).
    3.2.3.4  The maximum value of hourly flow rates (scfh).
    3.2.3.5  Average of the hourly NO<INF>X</INF> emission rate, in 
lb/mmBtu, reported by a NO<INF>X</INF>-diluent continuous emission 
monitoring system.
    3.2.3.6  The 90th percentile value of hourly NO<INF>X</INF> 
emission rates (lb/mmBtu).
    3.2.3.7  The 95th percentile value of hourly NO<INF>X</INF> 
emission rates (lb/mmBtu).
    3.2.3.8  The maximum value of hourly NO<INF>X</INF> emission 
rates, in (lb/mmBtu).
    3.2.3.9  Average of the hourly NO<INF>X</INF> pollutant 
concentrations (ppm), reported by a NO<INF>X</INF> concentration 
monitoring system used to determine NO<INF>X</INF> mass emissions, 
as defined in Sec. 75.51(a)(2).
    3.2.3.10  The 90th percentile value of hourly NO<INF>X</INF> 
pollutant concentration (ppm).
    3.2.3.11  The 95th percentile value of hourly NO<INF>X</INF> 
pollutant concentration (ppm).
    3.2.3.12  The maximum value of hourly NO<INF>X</INF> pollutant 
concentration (ppm).
    3.2.4  When a bias adjustment is necessary for the flow monitor 
and/or the NO<INF>X</INF>-diluent continuous emission monitoring 
system (and/or the NO<INF>X</INF> concentration monitoring system), 
apply the bias adjustment factor to all data values placed in the 
operational bins.
    3.2.5  Calculate all CEMS data averages, maximum values, and 
percentile values determined by this procedure using bias-adjusted 
values.
    3.2.6  Use the calculated monitor or monitoring system data 
averages, maximum values, and percentile values to substitute for 
missing flow rate and NO<INF>X</INF> emission rate data (and where 
applicable, NO<INF>X</INF> concentration data) according to the 
procedures in subpart D of this part.

4. Non-Load-Based Procedure for Missing Fuel Flowmeter Data 
(Optional)

4.1  Applicability

    For affected units that do not produce electrical output in 
megawatts or thermal output in klb/hr of steam, this procedure may 
be used in accordance with the provisions of this part to provide 
substitute data for fuel flow rate.

4.2  Procedure

    4.2.1  Establish at least two, but no more than ten operational 
bins, corresponding to various operating conditions and parameters 
(or combinations of these) related to the fuel flow rate. Include a 
complete description of each operational bin in the hardcopy portion 
of the monitoring plan required under Sec. 75.53(f)(1)(ii), 
identifying the parameters and operating conditions associated with 
the bin and explaining the relationship between these parameters and 
conditions and the magnitude of the fuel flow rate. Assign a unique 
number, 1 through 10, to each operational bin.
    4.2.2  In the electronic quarterly report required under 
Sec. 75.64, indicate for each hour of unit operation the operational 
bin associated with the fuel flow rate data, by recording the number 
assigned to the bin under section 4.2.1 of this appendix.
    4.2.3  The data acquisition and handling system (DAHS) must be 
capable of properly identifying and recording the operational bin 
number for each unit operating hour. The DAHS must also be capable 
of calculating and recording the following information for each unit 
operating hour of missing fuel flow rate data within each identified 
operational bin during the previous 720 operating hours (on a 
rolling basis):
    4.2.3.1  Arithmetic average of the hourly fuel flow rates 
reported by a certified fuel flowmeter system, in appropriate units 
of fuel flow rate.
    4.2.3.2  The maximum value of hourly fuel flow rates reported by 
a certified fuel flowmeter system, in appropriate units of fuel flow 
rate.
    4.2.4  The DAHS shall also be capable of separating the recorded 
fuel flow rate data on the basis of the type of fuel combusted in 
the unit. A separate database shall be created and maintained for 
each type of fuel when it is combusted alone in the unit. If 
different types of fuel are co-fired in the unit, an additional 
database shall be created and maintained for each type of fuel, for 
hours in which it is co-fired with any other type(s) of fuel(s).
    4.3  Use the calculated average and maximum values to substitute 
for missing fuel flow rate data according to the applicable 
procedures in sections 2.4.2 and 2.4.3 in appendix D to this part.


Appendix D Section 1  [Amended].

    56. Section 1 of Appendix D to Part 75 is amended by removing the 
final sentence of section 1.2.
    57. Section 2 of Appendix D to Part 75 is amended by:
    a. Revising sections 2.1.2, 2.1.2.1, and 2.1.2.2;
    b. Revising the first sentence of section 2.1.4.1;
    c. Revising section 2.1.4.3;
    d. In section 2.1.5 by revising the words ``calibrated fuel flow 
rate'' to read ``fuel flow rate measurable by the flowmeter'' in the 
first sentence, by adding the words ``(orifice, nozzle, and venturi-
type flowmeters, only)'' after the words ``by design'' in the second

[[Page 32037]]

sentence, and by revising the words ``measurement against a NIST-
traceable reference method'' in the third sentence to read ``in-line 
comparison against a reference flowmeter'';
    e. In section 2.1.5.4 by revising the words ``using the following'' 
to read ``in a manner consistent with'';
    f. In paragraph (c) of section 2.1.6 by removing the words 
``2.1.5.1 or'';
    g. In paragraph (d) of section 2.1.6 by removing the words ``, 
where applicable,'' before the words ``those procedures'' and ``, where 
applicable'' after the second occurrence of the words ``element 
inspection'', and by adding ``(if applicable)'' after both occurrences 
of the words ``test or'';
    h. Adding new paragraphs (e) and (f) to section 2.1.6;
    i. In the second sentence of paragraph (a) of section 2.1.6.1 by 
adding the word ``upscale'' after the word ``other'' and by adding a 
new third sentence;
    j. In section heading 2.1.6.2 by revising the words ``and Reporting 
of'' to read ``for'';
    k. In paragraph (a) of section 2.1.6.2 by removing the second and 
third sentences;
    l. Removing and reserving sections 2.1.6.2(b) and 2.1.6.2(c);
    m. In the final sentence of section 2.1.6.3 by removing the words 
``Sec. 75.56 or'' and ``, as applicable'';
    n. In the fourth sentence of paragraph (a) of section 2.1.6.4 by 
revising the words ``indicates that'' to read ``is failed (if'' and by 
adding a closing parenthesis after the word ``corroded'';
    o. In paragraph (a)(1) of section 2.1.6.4 by adding a new second 
sentence;
    p. In paragraphs (a)(2) and (b)(2) of section 2.1.6.4 by revising 
the word ``under'' to read ``, using'';
    q. In paragraph (b) of section 2.1.6.4 by removing the first 
sentence;
    r. In paragraph (b)(1) of section 2.1.6.4 by adding the words 
``and, if applicable, the transmitters have been successfully 
recalibrated'' to the end of the final sentence;
    s. In paragraph (c) of section 2.1.6.4 by revising the words ``this 
period'' to read ``each period of invalid fuel flowmeter data described 
in paragraph (b) of this section'';
    t. In section 2.1.7 by removing each occurrence of the words 
``where applicable,'' and ``as applicable,'', by removing the words 
``Sec. 75.54(a) or'', and by adding the words ``(if applicable) a'' and 
``(if applicable)'' after the two occurrences of ``test or'', 
respectively;
    u. In paragraph (a) of section 2.1.7.1 by revising the first 
occurrence of ``i.e.'' to read ``e.g.'', by revising the sixth 
sentence, and by adding the word ``Arithmetic'' before the word 
``average'' in the definitions of the variables ``Q<INF>base</INF>'' 
and ``L<INF>avg</INF>'' under Eq. D-1b;
    v. Revising paragraph (b) of section 2.1.7.1;
    w. In paragraph (c) of section 2.1.7.1 by adding the words 
``average fuel flow rate and the fuel GCV in the'' before the word 
``applicable'' in the definition of the variable ``(Heat 
Input)<INF>avg</INF>'' under Eq. D-1c;
    x. In paragraph (a) of section 2.1.7.2 by adding a new third 
sentence;
    y. Revising paragraph (b) of section 2.1.7.2;
    z. In the variable for ``(Heat Input)<INF>h</INF>'' under Eq. D-1e 
in paragraph (c) of section 2.1.7.2 by adding the words ``hourly fuel 
flow rate and the fuel GCV in the'' after the words ``using the'';
    aa. In paragraph (d) of section 2.1.7.2 by revising the third 
sentence and by adding a new fourth sentence;
    bb. Revising the first sentence of paragraph (a) of section 
2.1.7.3;
    cc. Adding a second sentence to paragraph (b) of section 2.1.7.3;
    dd. In the first sentence of paragraph (a) of section 2.1.7.4 by 
revising the reference to ``section 2.1.7.2'' to read ``section 
2.1.7.2(h)'';
    ee. In the final sentence of paragraph (b) of section 2.1.7.4 by 
adding the word ``fuel'' after the word ``two'' and by adding the words 
``(as defined in Sec. 72.2 of this chapter)'' after the word 
``quarters'';
    ff. Revising Table D-4 in section 2.2;
    gg. In section 2.2.4.2 introductory text by adding the words ``and 
GCV value'' after the words ``Use the sulfur content'' in the fourth 
sentence, and by revising the reference to ``section 2.2.4.3'' to read 
``section 2.2.4.3(c)'';
    hh. Revising paragraph (b) of section 2.2.4.2;
    ii. In the second sentence of paragraph (c) of section 2.2.4.3 by 
revising the first and second occurrences of the words ``two following 
values'' with, respectively, the words ``following conservative, 
assumed values'' and ``assumed values'';
    jj. Revising paragraph (d) of section 2.2.4.3;
    kk. Revising Table D-5 in section 2.3(b);
    ll. Revising all of section 2.3.1.4 except for the section heading 
and paragraph (a)(1);
    mm. In section 2.3.2.1.1 by adding a new second sentence and by 
revising Equation D-1h and the definitions of variables for Equation D-
1h;
    nn. Revising sections 2.3.2.1.2 and 2.3.2.4;
    oo. In section 2.3.3.2 by revising the third sentence and adding a 
new fourth sentence;
    pp. In section 2.3.4.3 by adding a new second sentence;
    qq. Revising the fourth sentence of section 2.3.4.3.1;
    rr. Revising section 2.3.4.3.2 and paragraph (a) of section 2.3.5;
    ss. In paragraph (a) of section 2.3.6 by revising the first, 
second, fourth, and fifth sentences and by adding a new sentence after 
the second sentence;
    tt. In the first sentence of paragraph (b) of section 2.3.6 by 
removing the words ``(and hydrogen sulfide content, if applicable)'';
    uu. In the first sentence of section 2.4.1 by removing the 
reference ``2.3.3.1.2,'';
    vv. Revising Table D-6 in section 2.4.1 and sections 2.4.2, 
2.4.2.1(b) and heading, 2.4.2.2, and 2.4.2.3; and
    ww. In section 2.4.3 by adding a new sentence to the end of that 
section.
    The revisions and additions read as follows:

2. Procedure

2.1  Fuel Flowmeter Measurements

* * * * *
    2.1.2 Install and use fuel flowmeters meeting the requirements 
of this appendix in a pipe going to each unit, or install and use a 
fuel flowmeter in a common pipe header (as defined in Sec. 72.2 of 
this chapter). However, the use of a fuel flowmeter in a common pipe 
header and the provisions of sections 2.1.2.1 and 2.1.2.2 of this 
appendix shall not apply to any unit that is using the provisions of 
subpart H of this part to monitor, record, and report NO<INF>X</INF> 
mass emissions under a state or federal NO<INF>X</INF> mass emission 
reduction program, unless both of the following are true: all of the 
units served by the common pipe are affected units, and all of the 
units have similar efficiencies. For the purposes of this section, 
units served by a common pipe have similar efficiencies (e.g., if 
all of the units are boilers or if all of the units are combustion 
turbines). When a fuel flowmeter is installed in a common pipe 
header, proceed as follows:
    2.1.2.1  Measure the fuel flow rate in the common pipe, and 
combine SO<INF>2</INF> mass emissions (Acid Rain Program units only) 
for the affected units for recordkeeping and compliance purposes; 
and
    2.1.2.2  Apportion the heat input rate measured at the common 
pipe to the individual units, using Equation F-21a, F-21b, or F-21d 
in appendix F to this part.
* * * * *

2.1.4  Situations in Which Certified Flowmeter Is Not Required

2.1.4.1  Start-up or Ignition Fuel

    For an oil-fired unit that uses gas solely for start-up or 
burner ignition, a gas-fired unit that uses oil solely for start-up 
or burner ignition, or an oil-fired unit that uses a different grade 
of oil solely for start-up or burner ignition, a fuel flowmeter for 
the start-up fuel is permitted but not required. * * *
* * * * *

2.1.4.3  Emergency Fuel

    The designated representative of a unit that is restricted by a 
federally-enforceable permit

[[Page 32038]]

to combusting a particular fuel only during emergencies where the 
primary fuel is not available is exempt from certifying a fuel 
flowmeter for use during combustion of the emergency fuel. During 
any hour in which the emergency fuel is combusted, report the hourly 
heat input to be the maximum rated heat input of the unit for the 
fuel. Use the maximum potential sulfur content for the fuel (from 
Table D-6 of this appendix) and the fuel flow rate corresponding to 
the maximum hourly heat input to calculate the hourly SO<INF>2</INF> 
mass emission rate, using Equations D-2 through D-4 of this appendix 
(as applicable). Alternatively, if a certified fuel flowmeter is 
available for the emergency fuel, you may use the measured hourly 
fuel flow rates in the calculations. Also, if daily samples or 
weekly composite samples (fuel oil, only) of the fuel's total sulfur 
content, GCV, and (if applicable) density are taken during the 
combustion of the emergency fuel, as described in section 2.2 or 2.3 
of this appendix, the sample results may be used to calculate the 
hourly SO<INF>2</INF> emissions and heat input rates, in lieu of 
using maximum potential values. The designated representative shall 
also provide notice under Sec. 75.61(a)(6) for each period when the 
emergency fuel is combusted.
* * * * *

2.1.6  Quality Assurance

* * * * *
    (e) When accuracy testing of the orifice, nozzle, or venturi 
meter is performed according to section 2.1.5.2 of this appendix, 
record the information displayed in Table D-1 in this section. At a 
minimum, record the overall accuracy results for the fuel flowmeter 
at the three flow rate levels specified in section 2.1.5.2 of this 
appendix.
    (f) Report the results of all fuel flowmeter accuracy tests, 
transmitter or transducer accuracy tests, and primary element 
inspections, as applicable, in the emissions report for the quarter 
in which the quality assurance tests are performed, using the 
electronic format specified by the Administrator under Sec. 75.64.

2.1.6.1  Transmitter or Transducer Accuracy Test for Orifice-, Nozzle-, 
and Venturi-Type Flowmeters

    (a) * * * For temperature transmitters, the zero and upscale 
levels may correspond to fixed reference points, such as the 
freezing point or boiling point of water.
* * * * *

2.1.6.4  Primary Element Inspection

    (a) * * *
    (1) * * * If the primary element size is changed, also calibrate 
the transmitters or transducers, consistent with the new primary 
element size;
* * * * *

2.1.7  Fuel Flow-to-Load Quality Assurance Testing for Certified Fuel 
Flowmeters

* * * * *

2.1.7.1  Baseline Flow Rate-to-Load Ratio or Heat Input-to-Load Ratio

    (a) * * * For orifice-, nozzle-, and venturi-type fuel 
flowmeters, if the fuel flow-to-load ratio is to be used as a 
supplement both to the transmitter accuracy test under section 
2.1.6.1 of this appendix and to primary element inspections under 
section 2.1.6.4 of this appendix, then the baseline data must be 
obtained after both procedures are completed and no later than the 
end of the fourth calendar quarter following the calendar quarter in 
which both procedures were completed. * * *
* * * * *
    (b) In Equation D-1b, for a fuel flowmeter installed on a common 
pipe header, L<INF>avg</INF> is the sum of the operating loads of 
all units that received fuel through the common pipe header during 
the baseline period, divided by the total number of hours of fuel 
flow rate data collected during the baseline period. For a unit that 
receives the same type of fuel through multiple pipes, 
Q<INF>base</INF> is the sum of the fuel flow rates during the 
baseline period from all of the pipes, divided by the total number 
of hours of fuel flow rate data collected during the baseline 
period. Round off the value of R<INF>base</INF> to the nearest 
tenth.
* * * * *

2.1.7.2  Data Preparation and Analysis

    (a) * * * Alternatively, the owner or operator may exclude non-
representative hours from the data analysis, as described in section 
2.1.7.3 of this appendix, prior to calculating the values of 
R<INF>h</INF>.
* * * * *
    (b) For a fuel flowmeter installed on a common pipe header, 
L<INF>h</INF> shall be the sum of the hourly operating loads of all 
units that receive fuel through the common pipe header. For a unit 
that receives the same type of fuel through multiple pipes, 
Q<INF>h</INF> will be the sum of the fuel flow rates from all of the 
pipes. Round off each value of R<INF>h</INF> to the nearest tenth.
* * * * *
    (d) * * * If, for a particular fuel flowmeter, fewer than 168 
hourly flow-to-load ratios (or GHR values) are available, or, if the 
baseline data collection period is still in progress at the end of 
the quarter and fewer than four calendar quarters have elapsed since 
the quarter in which the last successful fuel flowmeter accuracy 
test was performed, a flow-to-load (or GHR) evaluation is not 
required for that flowmeter for that calendar quarter. A one-quarter 
extension of the deadline for the next fuel flowmeter accuracy test 
may be claimed for a quarter in which there is insufficient hourly 
data available to analyze or a quarter that ends with the baseline 
data collection period still in progress.
* * * * *

2.1.7.3  Optional Data Exclusions

    (a) If E<INF>f</INF> is outside the limits in section 2.1.7.2(h) 
of this appendix, the owner or operator may re-examine the hourly 
fuel flow rate-to-load ratios (or GHRs) that were used for the data 
analysis and may identify and exclude fuel flow-to-load ratios or 
GHR values for any non-representative hours, provided that such data 
exclusions were not previously made under section 2.1.7.2(a) of this 
appendix. * * *
    (b) * * * If fewer than 168 hourly fuel flow-to-load ratio or 
GHR values remain after the allowable data exclusions, a fuel flow-
to-load ratio or GHR analysis is not required for that quarter, and 
a one-quarter extension of the fuel flowmeter accuracy test deadline 
may be claimed.
* * * * *

2.2  Oil Sampling and Analysis

* * * * *

       Table D-4.--Oil Sampling Methods and Sulfur, Density and Gross Calorific Value Used in Calculations
----------------------------------------------------------------------------------------------------------------
                  Parameter                      Sampling technique/frequency       Value used in calculations
----------------------------------------------------------------------------------------------------------------
Oil Sulfur Content...........................  Daily manual sampling...........  1. Highest sulfur content from
                                                                                  previous 30 daily samples; or
                                                                                 2. Actual daily value.
                                               Flow proportional/weekly          Actual measured value.
                                                composite.
                                               In storage tank (after addition   1. Actual measured value; or
                                                of fuel to tank).
                                                                                 2. Highest of all sampled
                                                                                  values in previous calendar
                                                                                  year, unless a higher sample
                                                                                  value is obtained; \1\ or
                                                                                 3. Maximum value allowed by
                                                                                  contract, unless a higher
                                                                                  sample value is obtained.\1\
                                               As delivered (in delivery truck   1. Highest of all sampled
                                                or barge).\1\                     values in previous calendar
                                                                                  year, unless a higher sample
                                                                                  value is obtained; \1\ or
                                                                                 2. Maximum value allowed by
                                                                                  contract, unless a higher
                                                                                  sample value is obtained.\1\
Oil Density..................................  Daily manual sampling...........  1. Use the highest density from
                                                                                  the previous 30 daily samples;
                                                                                  or
                                                                                 2. Actual measured value.

[[Page 32039]]

 
                                               Flow proportional/weekly          Actual measured value.
                                                composite.
                                               In storage tank (after addition   1. Actual measured value; or
                                                of fuel to tank).
                                                                                 2. Highest of all sampled
                                                                                  values in previous calendar
                                                                                  year, unless a higher sample
                                                                                  value is obtained; \1\ or
                                                                                 3. Maximum value allowed by
                                                                                  contract, unless a higher
                                                                                  sample value is obtained.\1\
                                               As delivered (in delivery truck   1. Highest of all sampled
                                                or barge).\1\                     values in previous calendar
                                                                                  year, unless a higher sample
                                                                                  value is obtained; \1\ or
                                                                                 2. Maximum value allowed by
                                                                                  contract, unless a higher
                                                                                  sample value is obtained.\1\
Oil GCV......................................  Daily manual sampling...........  1. Highest fuel GCV from the
                                                                                  previous 30 daily samples; or
                                                                                 2. Actual measured value.
                                               Flow proportional/weekly          Actual measured value.
                                                composite.
                                               In storage tank (after addition   1. Actual measured value; or
                                                of fuel to tank).
                                                                                 2. Highest of all sampled
                                                                                  values in previous calendar
                                                                                  year, unless a higher sample
                                                                                  value is obtained; \1\ or
                                                                                 3. Maximum value allowed by
                                                                                  contract, unless a higher
                                                                                  sample value is obtained.\1\
                                               As delivered (in delivery truck   1. Highest of all sampled
                                                or barge).\1\                     values in previous calendar
                                                                                  year, unless a higher sample
                                                                                  value is obtained; \1\ or
                                                                                 2. Maximum value allowed by
                                                                                  contract, unless a higher
                                                                                  sample value is obtained.\1\
----------------------------------------------------------------------------------------------------------------
\1\ Assumed values may only be used if sulfur content, gross calorific value, or density of each sample is no
  greater than the assumed value used to calculate emissions or heat input. If a higher sample value is
  obtained, use the results of that sample analysis as the new assumed value.

* * * * *

2.2.4  Manual Sampling

* * * * *

2.2.4.2  Sampling from a Unit's Storage Tank

* * * * *
    (b) One of the conservative assumed values described in section 
2.2.4.3(c) of this appendix. Follow the applicable provisions in 
section 2.2.4.3(d) of this appendix, regarding the use of assumed 
values.

2.2.4.3  Sampling from Each Delivery

* * * * *
    (d) Continue using the assumed value(s), so long as the sample 
results do not exceed the assumed value(s). However, if the actual 
sampled sulfur content, gross calorific value, or density of an oil 
sample is greater than the assumed value for that parameter, then, 
beginning on the date of receipt of the results of the sample 
analysis, use the actual sampled value for sulfur content, gross 
calorific value, or density of fuel to calculate SO<INF>2</INF> mass 
emission rate or heat input rate. Consider the sampled value to be 
the new assumed sulfur content, gross calorific value, or density. 
Continue using this new assumed value to calculate SO<INF>2</INF> 
mass emission rate or heat input rate unless and until: it is 
superseded by a higher value from an oil sample; or (if applicable) 
it 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 (if 
applicable) both the calendar year in which the sampled value 
exceeded the assumed value and the subsequent calendar year have 
elapsed.

2.3  SO<INF>2</INF> Emissions from Combustion of Gaseous Fuels

* * * * *

                Table D-5.--Gas Sulfur and GCV Values Used in Calculations for Various Fuel Types
----------------------------------------------------------------------------------------------------------------
                                                                                    Value used in calculations
                  Parameter                    Fuel type and sampling frequency  (except for missing data hours)
----------------------------------------------------------------------------------------------------------------
Gas Sulfur Content...........................  Pipeline Natural Gas with total   0.0006 lb/mmBtu.
                                                sulfur content less than or
                                                equal to 0.5 grains/100scf
                                                (when using the provisions of
                                                section 2.3.1 to determine SO<INF>2</INF>
                                                mass emissions)--Sample
                                                semiannually and whenever fuel
                                                composition changes
                                                significantly.
                                               Natural Gas with total sulfur     Default SO<INF>2</INF> emission rate
                                                content less than or equal to     calculated from Eq. D-1h,
                                                20.0 grains/100scf (when using    using either:
                                                the provisions of section 2.3.2  1. The fuel contract maximum
                                                to determine SO<INF>2</INF> mass             total sulfur content, unless a
                                                emissions)--Sample semiannually   higher value is obtained in a
                                                and whenever fuel composition     semiannual sample;\1\
                                                changes significantly.           2. The maximum total sulfur
                                                                                  content from the previous
                                                                                  year's samples, unless a
                                                                                  higher value is obtained in a
                                                                                  semiannual sample;\1\ or
                                                                                 3. The actual total sulfur
                                                                                  content from the most recent
                                                                                  semiannual sample.

[[Page 32040]]

 
                                               Any gaseous fuel delivered in     1. Actual total sulfur content
                                                shipments or lots--Sample each    from most recent shipment;
                                                lot or shipment.                 2. Highest total sulfur content
                                                                                  from previous year's samples,
                                                                                  unless a higher value is
                                                                                  obtained in a sample;\1\ or
                                                                                 3. Maximum total sulfur content
                                                                                  value allowed by contract,
                                                                                  unless a higher value is
                                                                                  obtained in a sample.\1\
                                               Any gaseous fuel transmitted by   1. Actual total sulfur content
                                                pipeline and having a             from daily sample; or
                                                demonstrated ``low sulfur        2. Highest total sulfur content
                                                variability'' using the           from previous 30 daily
                                                provisions of section 2.3.6--     samples.
                                                Sample daily.
                                               Any gaseous fuel--Sample hourly.  Actual hourly total sulfur
                                                                                  content of the gas.
Gas GCV......................................  Pipeline Natural Gas--Sample      1. GCV from most recent monthly
                                                monthly.                          sample (with <gr-thn-eq> 48
                                                                                  operating hours in the month);
                                                                                 2. Maximum GCV from contract,
                                                                                  unless a higher value is
                                                                                  obtained in a monthly
                                                                                  sample;\1\ or
                                                                                 3. Highest GCV from previous
                                                                                  year's samples, unless a
                                                                                  higher value is obtained in a
                                                                                  monthly sample.\1\
                                               Natural Gas--Sample monthly.....  1. GCV from most recent monthly
                                                                                  sample (with <gr-thn-eq> 48
                                                                                  operating hours in the month);
                                                                                 2. Maximum GCV from
                                                                                  contract;\1\ or
                                                                                 3. Highest GCV from previous
                                                                                  year's samples.\1\
                                               Any gaseous fuel delivered in     1. Actual GCV from most recent
                                                shipments or lots--Sample each    shipment or lot;
                                                lot or shipment.                 2. Highest GCV from previous
                                                                                  year's samples, unless a
                                                                                  higher value is obtained in a
                                                                                  sample;\1\ or
                                                                                 3. Maximum GCV value allowed by
                                                                                  contract, unless a higher
                                                                                  value is obtained in a
                                                                                  sample.\1\
                                               Any gaseous fuel transmitted by   1. GCV from most recent monthly
                                                pipeline and having a             sample (with <gr-thn-eq> 48
                                                demonstrated ``low GCV            operating hours in the month);
                                                variability'' using the           or
                                                provisions of section 2.3.5--    2. Highest GCV from previous
                                                Sample monthly.                   year's samples, unless a
                                                                                  higher value is obtained in a
                                                                                  monthly sample.\1\
                                               Any other gaseous fuel not        Actual daily or hourly GCV of
                                                having a ``low GCV                the gas.
                                                variability''--Sample daily or
                                                hourly. (Note that the use of
                                                an on-line GCV calorimeter or
                                                gas chromatograph is allowed).
----------------------------------------------------------------------------------------------------------------
\1\ Assumed sulfur content and GCV values (i.e., contract values or highest values from previous year) may only
  continue to be used if the sulfur content or GCV of each sample is no greater than the assumed value used to
  calculate SO<INF>2</INF> emissions or heat input. If a higher sample value is obtained, use the results of that sample
  analysis as the new assumed value.

2.3.1  Pipeline Natural Gas Combustion

* * * * *

2.3.1.4  Documentation that a Fuel is Pipeline Natural Gas

    (a) A fuel may initially qualify as pipeline natural gas, if 
information is provided in the monitoring plan required under 
Sec. 75.53, demonstrating that the definition of pipeline natural 
gas in Sec. 72.2 of this chapter has been met. The information must 
demonstrate that the fuel meets either the percent methane or GCV 
requirement and has a total sulfur content of less than or equal to 
0.5 grains/100scf. The demonstration must be made using one of the 
following sources of information:
* * * * *
    (2) The results of all available fuel sample analyses from the 
past 12 months, documenting the total sulfur content of the fuel and 
the percentage by weight of methane and/or GCV of the fuel. The fuel 
samples may be obtained and analyzed by the owner or operator, by an 
independent laboratory, or by the supplier of the gaseous fuel;
    (3) Data from a 720-hour demonstration conducted using the 
procedures of sections 2.3.5 and 2.3.6 of this appendix, documenting 
the total sulfur content of the fuel and the percentage by weight of 
methane and/or the GCV of the fuel, and using comparable procedures 
to document the percentage by weight of methane; or
    (4) If historical fuel sampling results or data from a 720-hour 
demonstration are not available, a fuel may initially qualify as 
pipeline natural gas if a sample of the fuel is obtained and 
analyzed for total sulfur content and for percent methane or GCV, 
and if the results of the sample analysis show that the total sulfur 
content and percentage methane or GCV meet the definition of 
pipeline natural gas in Sec. 72.2 of this chapter.
    (b) After a fuel initially qualifies as pipeline natural gas 
under paragraph (a) of this section, the owner or operator shall 
sample the fuel for total sulfur content at least semiannually and 
whenever it is reasonable to believe that the fuel composition has 
changed significantly. The owner or operator shall also sample the 
GCV of the fuel at the frequency specified in section 2.3.4.1 of 
this appendix.
    (c) If the results of a sample under paragraph (b) of this 
section show that the total sulfur content of the fuel exceeds 
0.5gr/100 scf, the fuel no longer qualifies as pipeline natural gas. 
When this occurs:
    (1) If the sample results show that the fuel still qualifies as 
natural gas under section 2.3.2.4 of this appendix, discontinue 
using the 0.0006 lb/mmBtu default SO<INF>2</INF> emission rate under 
2.3.1.1, as of the date on which the sample results are received. 
Determine a new default SO<INF>2</INF> emission rate according to 
section 2.3.2.1.1 of this appendix and use the new SO<INF>2</INF> 
emission rate, beginning with the date of receipt of the sample 
results; or
    (2) If the sample results show that the fuel no longer qualifies 
either as pipeline natural gas or natural gas, the owner or operator 
shall implement the procedures of section 2.3.3.1 of this appendix 
(for sulfur content determination) and section 2.3.4.3 of this 
appendix (for GCV determination), no later than 90 days after the 
end of the quarter in which the sample results are received.

2.3.2  Natural Gas Combustion

* * * * *

2.3.2.1  SO<INF>2</INF> Emission Rate

* * * * *

2.3.2.1.1   * * * In Equation D-1h, the total sulfur content and GCV 
values shall be determined in accordance with the allowable options 
shown in Table D-5 of this appendix. * * *

[[Page 32041]]

[GRAPHIC] [TIFF OMITTED] TP13JN01.005

Where:

    ER = Default SO<INF>2</INF> emission rate for natural gas 
combustion, lb/mmBtu.
    S<INF>total</INF> = Total sulfur content of the natural gas, gr/
100scf.
    GCV = Gross calorific value of the natural gas, Btu/100scf.
    7000 = Conversion of grains/100scf to lb/100scf.
    2.0 = Ratio of lb SO<INF>2</INF>/lb S.
    10\6\ = Conversion factor (Btu/mmBtu).

    2.3.2.1.2  For reporting purposes, apply the results of the 
required periodic fuel samples described in Table D-5 of this 
appendix as follows. Use Equation D-1h to recalculate the 
SO<INF>2</INF> emission rate, as necessary.
    (a) For daily samples of total sulfur content or GCV:
    (1) If the actual value is to be used in the calculations, apply 
the results of each daily sample to all hours in the day on which 
the sample is taken; or
    (2) If the highest value in the previous 30 daily samples is to 
be used in the calculations, apply that value to all hours in the 
current day. If, for a particular unit, fewer than 30 daily samples 
have been collected, use the highest value from all available 
samples until 30 days of historical sampling results have been 
obtained.
    (b) For semiannual samples of total sulfur content:
    (1) If the actual value is to be used in the calculations, apply 
the results of the most recent sample, until the date on which the 
results of the next sample are received; 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 the quarter unless a higher value 
is obtained in a semiannual fuel sample. In that case, use the 
sampled value, beginning with the date of receipt of the sample 
results. Consider the sample results to be the new assumed value. 
Continue using the new assumed value unless and until it is 
superseded by a higher value from a subsequent quarterly sample; or 
(if applicable) it 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 (if applicable) both the calendar year in which the sampled value 
exceeded the assumed value and the subsequent calendar year have 
elapsed.
    (c) For monthly samples of the fuel GCV:
    (1) If the actual value is to be used in the calculations, apply 
the results of the most recent sample, until the date on which the 
results of the next sample are received; 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. In that case, use 
the sampled value, beginning with the date of receipt of the sample 
results. Consider the sample results to be the new assumed value. 
Continue using the new assumed value unless and until it is 
superseded by a higher value from a subsequent monthly sample; or 
(if applicable) it 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 (if applicable) both the calendar year in which the sampled value 
exceeded the assumed value and the subsequent calendar year have 
elapsed.
    (d) For samples of gaseous fuel delivered in shipments or lots:
    (1) If the actual value for the most recent shipment is to be 
used in the calculations, apply the results of the most recent 
sample, until the date on which the results of the next sample are 
received; 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 unless a higher value is obtained in a sample of a 
shipment. In that case, use the sampled value, beginning with the 
date of receipt of the sample results. Consider the sample results 
to be the new assumed value. Continue using the new assumed value 
unless and until: it is superseded by a higher value from a sample 
of a subsequent shipment; or (if applicable) it 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 (if applicable) both the 
calendar year in which the sampled value exceeded the assumed value 
and the subsequent calendar year have elapsed.
* * * * *

2.3.2.4  Documentation that a Fuel is a Natural Gas

    (a) A fuel may initially qualify as natural gas if information 
is provided in the monitoring plan required under Sec. 75.53, 
demonstrating that the definition of natural gas in Sec. 72.2 of 
this chapter has been met. The information must demonstrate that the 
fuel meets either the percent methane or GCV requirement and has a 
total sulfur content of less than or equal to 20.0 grains/100 scf. 
This demonstration must be made using one of the following sources 
of information:
    (1) The gas quality characteristics specified by a purchase 
contract or by a transportation contract;
    (2) The results of all available fuel sample analyses from the 
past 12 months, documenting the total sulfur content of the fuel and 
the percentage by weight of methane and/or GCV of the fuel. The fuel 
samples may be obtained and analyzed by the owner or operator, by an 
independent laboratory, or by the supplier of the gaseous fuel;
    (3) Data from a 720-hour demonstration conducted using the 
procedures of section 2.3.6 of this appendix, documenting the total 
sulfur content of the fuel and the percentage by weight of methane 
and/or the GCV of the fuel, and using comparable procedures to 
document the percentage by weight of methane; or
    (4) If historical fuel sampling results or data from a 720-hour 
demonstration are not available, a fuel may initially qualify as 
natural gas if a sample of the fuel is obtained and analyzed for 
total sulfur content and for percent methane or GCV, and if the 
results of the sample analyses show that the total sulfur content 
and percentage methane or GCV meet the definition of natural gas in 
Sec. 72.2 of this chapter.
    (b) After a fuel initially qualifies as natural gas under 
paragraph (a) of this section, the owner or operator shall sample 
the fuel for total sulfur content at least semiannually and whenever 
it is reasonable to believe that the fuel composition has changed 
significantly. The owner or operator shall also sample the GCV of 
the fuel at the frequency specified in section 2.3.4.2 of this 
appendix.
    (c) If the results of a periodic sample required under paragraph 
(b) of this section show that the total sulfur content of the fuel 
exceeds 20.0 gr/100 scf, the fuel no longer qualifies as natural 
gas. In that case, the owner or operator shall implement the 
procedures of section 2.3.3.1 of this appendix (for sulfur content 
determination) and section 2.3.4.3 of this appendix (for GCV 
determination), no later than 90 days after the end of the quarter 
in which the sample results are received.

2.3.3  SO<INF>2</INF> Mass Emissions From Any Gaseous Fuel

* * * * *

2.3.3.2  SO<INF>2</INF> Mass Emission Rate

    * * * That is, for fuels delivered by pipeline which demonstrate 
a low sulfur variability (under section 2.3.6 of this appendix) use 
either the daily sample value or the highest value in the previous 
30 daily samples or for fuels requiring hourly sulfur content 
sampling with a gas chromatograph use the actual hourly sulfur 
content). For fuels delivered in shipments or lots, use either the 
actual sulfur content from the most recent shipment or an assumed 
value (contract maximum or highest value from the previous year's 
samples). In all cases, for reporting purposes, apply the results of 
the required periodic total sulfur samples in accordance with the 
provisions of section 2.3.2.1.2 of this appendix.
* * * * *

2.3.4  Gross Calorific Values for Gaseous Fuels

* * * * *

2.3.4.3  GCV of Other Gaseous Fuels

    * * * For reporting purposes, apply the results of the required 
periodic GCV samples in accordance with the provisions of section 
2.3.2.1.2 of this appendix.
    2.3.4.3.1  * * * For sampling from the tank after each delivery, 
use either the most recent GCV sample, the maximum GCV specified in 
the fuel contract, or the highest GCV from the previous year's 
samples.

[[Page 32042]]

    2.3.4.3.2  For any gaseous fuel that does not qualify as 
pipeline natural gas or natural gas, which is not delivered in 
shipments or lots, and which performs the required 720 hour test 
under section 2.3.5 of this appendix, if the results of the test 
demonstrate that the gaseous fuel has a low GCV variability, 
determine the GCV at least monthly. In calculations of hourly heat 
input for a unit, use either the most recent monthly sample, the 
maximum GCV specified in the fuel contract, or the highest fuel GCV 
from the previous year's samples.
* * * * *

2.3.5  Demonstration of Fuel GCV Variability

    (a) This optional demonstration may be made for any fuel which 
does not qualify as pipeline natural gas or natural gas, and is not 
delivered only in shipments or lots. The demonstration data may be 
used to show that monthly sampling of the GCV of the gaseous fuel or 
blend is sufficient, in lieu of daily GCV sampling. The procedures 
in this section may also be used to demonstrate that the GCV of a 
particular gaseous fuel is within the range of GCV values for 
pipeline natural gas or natural gas, as defined in Sec. 72.2 of this 
chapter.
* * * * *

2.3.6  Demonstration of Fuel Sulfur Variability

    (a) This optional demonstration may be made for any fuel which 
does not qualify as pipeline natural gas or natural gas, and is not 
delivered only in shipments or lots. The results of the 
demonstration may be used to show that daily sampling for sulfur in 
the fuel is sufficient, rather than hourly sampling. The procedures 
in this section may also be used to demonstrate that the total 
sulfur content of a particular gaseous fuel is within the limits for 
pipeline natural gas or natural gas, as defined in Sec. 72.2 of this 
chapter. * * * Provide a minimum of 720 hours of data, indicating 
the total sulfur content of the gaseous fuel or blend (in gr/100 
scf). The demonstration data shall be obtained using either manual 
hourly sampling or an on-line gas chromatograph capable of 
determining fuel total sulfur content on an hourly basis. * * *
* * * * *

2.4  Missing Data Procedures

* * * * *

2.4.1  Missing Data for Oil and Gas Samples

* * * * *

  Table D-6.--Missing Data Substitution Procedures for Sulfur, Density,
                     and Gross Calorific Value Data
------------------------------------------------------------------------
                                   Missing data substitution maximum
          Parameter                         potential value
------------------------------------------------------------------------
Oil Sulfur Content...........  3.5 percent for residual oil, or 1.0
                                percent for diesel fuel.
Oil Density..................  8.5 lb/gal for residual oil, or 7.4 lb/
                                gal for diesel fuel.
Oil GCV......................  19,500 Btu/lb for residual oil, or 20,000
                                Btu/lb for diesel fuel.
Gas Total Sulfur Content.....  1. 0.002 lb/mmBtu for pipeline natural
                                gas;
                               2. For natural gas for which semiannual
                                sampling is performed, a default
                                emission rate calculated from Equation D-
                                1h, using the lesser of: (a) The maximum
                                total sulfur content specified in the
                                fuel contract; or (b) 1.5 times the
                                highest total sulfur content from the
                                previous year's samples;
                               3. For any gaseous fuel sampled daily,
                                1.5 times the highest total sulfur
                                content value from the previous 30 days
                                on which valid samples were obtained; or
                               4. For any gaseous fuel sampled hourly,
                                the highest total sulfur content value
                                from the previous 720 hourly samples
Gas GCV/Heat Content.........  1100 Btu/scf for pipeline natural gas,
                                natural gas or landfill gas.
                               1500 for butane or refinery gas.
                               2100 Btu/scf for propane or any other
                                gaseous fuel.
------------------------------------------------------------------------

    2.4.2  Missing Data Procedures for Fuel Flow Rate. Whenever data 
are missing from any primary fuel flowmeter system (as defined in 
Sec. 72.2 of this chapter) and there is no backup system available 
to record the fuel flow rate, use the procedures in sections 2.4.2.2 
and 2.4.2.3 of this appendix to account for the flow rate of fuel 
combusted at the unit for each hour during the missing data period. 
Alternatively, for a fuel flowmeter system used to measure the fuel 
combusted by a peaking unit, the simplified fuel flow missing data 
procedure in section 2.4.2.1 of this appendix may be used. Before 
using the procedures in sections 2.4.2.2 and 2.4.2.3 of this 
appendix, establish load ranges for the unit using the procedures of 
section 2 in appendix C to this part, except for units that do not 
produce electrical output (megawatts) or thermal output (e.g., klb 
of steam per hour). The owner or operator of a unit that does not 
produce electrical or thermal output may either establish 
operational bins for the unit, as described in section 4 of appendix 
C to this part, or may perform missing data substitution without 
segregating the fuel flow rate data into bins. When load ranges or 
operational bins are used for fuel flow rate missing data purposes, 
separate, fuel-specific databases shall be created and maintained. A 
database shall be kept for each type of fuel combusted in the unit, 
for the hours in which the fuel is combusted alone in the unit. An 
additional database shall be kept for each type of fuel, for the 
hours in which it is co-fired with any other type(s) of fuel(s).

2.4.2.1  Simplified Fuel Flow Rate Missing Data Procedure for Peaking 
Units * * *

    (b) The maximum flow rate that the fuel flowmeter can measure 
(i.e, the upper range value of the flowmeter).
    2.4.2.2  Missing Data Procedures for Non-peaking Units--Single 
Fuel Hours. For missing data periods that occur when only one type 
of fuel is being combusted, provide substitute data for each hour in 
the missing data period as follows.
    2.4.2.2.1  If load-based missing data procedures are used, 
substitute the arithmetic average of the hourly fuel flow rate(s) 
measured and recorded by a certified fuel flowmeter system at the 
corresponding operating unit load range during the previous 720 
operating hours in which the unit combusted only that same fuel. If 
no fuel flow rate data are available at the corresponding load 
range, apply the same mathematical algorithm to, and use the same 
lookback period for, the data from the next higher load range, if 
such data are available. If no quality-assured fuel flow rate data 
are available at either the corresponding load range or a higher 
load range, substitute the maximum potential fuel flow rate (as 
defined in section 2.4.2.1 of this appendix) for each hour of the 
missing data period.
    2.4.2.2.2  For units that do not produce electrical or thermal 
output and therefore cannot use load-based missing data procedures, 
provide substitute data for each hour of the missing data period as 
follows.
    2.4.2.2.2.1  If operational bins (as defined in section 4 of 
appendix C to this part) are used, substitute the arithmetic average 
of the hourly fuel flow rates measured and recorded by a certified 
fuel flowmeter system at the corresponding operational bin during 
the previous 720 operating hours in which the unit combusted only 
that same fuel. If no quality-assured fuel flow rate data are 
available at the corresponding operational bin, or, if essential 
operating or parametric data are unavailable and the operational bin 
cannot be determined, substitute the maximum potential fuel flow 
rate (as defined in section 2.4.2.1 of this appendix) for each hour 
of the missing data period.
    2.4.2.2.2.2  If operational bins are not used, substitute the 
arithmetic average of the hourly fuel flow rates measured and 
recorded by a certified fuel flowmeter system during the previous 
720 operating hours in which the unit combusted only that same fuel. 
If no quality-assured fuel flow rate data are available, substitute 
the maximum potential fuel flow rate (as defined in section 2.4.2.1

[[Page 32043]]

of this appendix) for each hour of the missing data period.
    2.4.2.3  Missing Data Procedures for Non-peaking Units--Multiple 
Fuel Hours. For missing data periods that occur when two or more 
different types of fuel are being co-fired, provide substitute fuel 
flow rate data for each hour of the missing data period as follows.
    2.4.2.3.1  If load-based missing data procedures are used, 
substitute the maximum hourly fuel flow rate measured and recorded 
by a certified fuel flowmeter system at the corresponding load range 
during the previous 720 operating hours when the fuel for which the 
flow rate data are missing was co-fired with any other type of fuel. 
If no such quality-assured fuel flow rate data are available at the 
corresponding load range, apply the same mathematical algorithm to, 
and use the same lookback period for, the data from the next higher 
load range (if available). If no quality-assured fuel flow rate data 
are available for co-fired hours, either at the corresponding load 
range or a higher load range, substitute the maximum potential fuel 
flow rate (as defined in section 2.4.2.1 of this appendix) for each 
hour of the missing data period.
    2.4.2.3.2  For units that do not produce electrical or thermal 
output and therefore cannot use load-based missing data procedures, 
provide substitute fuel flow rate data for each hour of the missing 
data period as follows.
    2.4.2.3.2.1  If operational bins (as defined in section 4 of 
appendix C to this part) are used, substitute the maximum hourly 
fuel flow rate measured and recorded by a certified fuel flowmeter 
system at the corresponding operational bin, during the previous 720 
operating hours in which the unit for which the flow rate data are 
missing was co-fired with any other type of fuel. If no quality-
assured fuel flow rate data for co-fired hours are available at the 
corresponding operational bin, or, if essential operating or 
parametric data are unavailable and the operational bin cannot be 
determined, substitute the maximum potential fuel flow rate (as 
defined in section 2.4.2.1 of this appendix) for each hour of the 
missing data period.
    2.4.2.3.2.2  If operational bins are not used, substitute the 
maximum hourly fuel flow rate measured and recorded by a certified 
fuel flowmeter system during the previous 720 operating hours in 
which the fuel for which the flow rate data are missing was co-fired 
with any other type of fuel. If no quality-assured fuel flow rate 
data for co-fired hours are available, substitute the maximum 
potential fuel flow rate (as defined in section 2.4.2.1 of this 
appendix) for each hour of the missing data period.
    2.4.2.3.3  If, during an hour in which different types of fuel 
are co-fired, quality-assured fuel flow rate data are missing for 
two or more of the fuels being combusted, apply the procedures in 
section 2.4.2.3.1 or 2.4.2.3.2 of this appendix (as applicable) 
separately for each type of fuel.
    2.4.2.3.4  If the missing data substitution required in section 
2.4.2.3.1 or 2.4.2.3.2 causes the reported hourly heat input rate 
based on the combined fuel usage to exceed the maximum rated hourly 
heat input of the unit, adjust the substitute fuel flow rate 
value(s) so that the reported heat input rate equals the unit's 
maximum rated hourly heat input. Manual entry of the adjusted 
substitute data values is permitted.
    2.4.3  * * * In addition, if there is at least one hour, but 
fewer than 720 hours of quality-assured fuel flowmeter data 
available for the lookback periods described in sections 2.4.2.2 and 
2.4.2.3 of this appendix, use all of the available fuel flowmeter 
data to determine the appropriate substitute data values.


Appendix D to Part 75  [Amended]

    58. Section 3 of Appendix D to Part 75 is amended by:
    a. In the definition of the variable ``%S<INF>oil</INF>'' in 
Equation D-2 in section 3.1.1 by removing the word ``measured'', and by 
revising the word ``sample'' to read ``oil'';
    b. In the numerator of Equation D-4 in section 3.3.1 by revising 
the number ``2'' with the number ``2.0'';
    c. In the definition of the variable ``GCV<INF>gas</INF>'' in 
Equation D-6 in section 3.4.1 by revising the word ``Btu/hr'' to read 
``Btu/100 scf'';
    d. In the definition of the variable ``GCV<INF>oil</INF>'' in 
Equation D-8 in section 3.4.2 by adding the word ``or'' after the word 
``Btu/ton,'';
    e. In paragraph (b) in section 3.4.3 by revising the words 
``Equation D-10 or D-11'' to read ``Equation F-21a or F-21b in appendix 
F to this part'' in the third sentence and by removing equations and 
variable definitions for Equations D-10 and D-11;
    f. In paragraph (c) of section 3.4.3 by revising the words 
``Equation D-10 or D-11'' to read ``Equation F-21a or F-21b'';
    g. Revising the section heading of section 3.5;
    h. In section heading 3.5.4 by adding the words ``Rate and Heat 
Input'' after the word ``Input''; and
    i. In section 3.5.4 by adding the subsection number ``3.5.4.1'' 
before the existing text of the section and adding new subsection 
3.5.4.2 following the variable definitions for Equation D-15.
    The revisions and additions read as follows:

3. Calculations

* * * * *

3.5  Conversion of Hourly Rates to Hourly, Quarterly, and Year-to-Date 
Totals

* * * * *

3.5.4  Hourly Total Heat Input Rate and Heat Input from the Combustion 
of all Fuels

* * * * *

3.5.4.2  For reporting purposes, determine the heat input rate to each 
unit, in mmBtu/hr, for each hour from the combustion of all fuels using 
Equation D-15a:
[GRAPHIC] [TIFF OMITTED] TP13JN01.033

Where:
HI<INF>rate-hr</INF> = Total heat input rate from all fuels 
combusted during the hour, mmBtu/hr.
HI<INF>rate-i</INF> = Heat input rate for each type of gas or oil 
combusted during the hour, mmBtu/hr.
t<INF>i</INF> = Time each gas or oil fuel was combusted for the hour 
(fuel usage time), 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).
t<INF>u</INF> = Unit operating time
* * * * *
    59. Section 1 of Appendix E to Part 75 is amended by revising the 
second sentence of section 1.1 and adding two sentences after that 
second sentence to read as follows:

Appendix E to Part 75--Optional NO<INF>X</INF> Emissions Estimation 
Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units

1. Applicability

1.1  Unit Operation Requirements

    * * * If a unit's operations exceed the levels required to be a 
peaking unit, the owner or operator shall install and certify a 
NO<INF>X</INF>-diluent continuous emission monitoring system no 
later than December 31 of the following calendar year. If the 
required CEMS has not been installed and certified by that date, the 
owner or operator shall report the maximum potential NO<INF>X</INF> 
emission rate (MER) (as defined in Sec. 72.2 of this chapter) for 
each unit operating hour, starting with the first unit operating 
hour after the deadline and continuing until the CEMS has been 
provisionally certified. For each unit operating hour in which the 
MER is reported, the MER shall be specific to the type of fuel being 
combusted in the unit. * * *
* * * * *
    60. Section 2 of Appendix E to Part 75 is amended by:
    a. Revising sections 2.1.4, 2.2 and 2.5.2;
    b. In the second sentence of section 2.1.5 by revising the words 
``nearest 0.01 lb/mm/Btu'' to read ``nearest 0.001 lb/mmBtu'';
    c. In section 2.3 by revising the words ``10 unit'' to read ``30 
unit'' and the words ``section 2.1 of appendix B of this part'' with 
``Sec. 72.2 of this chapter,'' and by revising the reference to 
``Sec. 75.60(a)'' to read ``Sec. 75.60'';
    d. In sections 2.3.1 and 2.3.2 by revising the first sentence of 
each section, adding a new sentence after each first sentence, and 
revising each occurrence of the words

[[Page 32044]]

``manufacturer's recommended'' to read ``acceptable'';
    e. Revising the third sentence of 2.4.2;
    f. Adding a new second sentence in section 2.5; and
    g. Adding sections 2.5.2.1, 2.5.2.1.1, 2.5.2.1.2, 2.5.2.2, and 
2.5.2.3.
    The revisions and additions read as follows:

Appendix E to Part 75--Optional NO<INF>X</INF> Emissions Estimation 
Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units

* * * * *

2. Procedure

2.1  Initial Performance Testing

* * * * *
2.1.4  Emergency Fuel
    The designated representative of a unit that has a federally-
enforceable permit restricting the combustion of a particular fuel to 
emergencies where the primary fuel is not available is exempted from 
the requirements of this appendix for testing the NO<INF>X</INF> 
emission rate during combustion of the emergency fuel. The designated 
representative shall include in the monitoring plan for the unit 
documentation that the permit restricts use of the fuel to emergencies 
only. When emergency fuel is combusted, report the maximum potential 
NO<INF>X</INF> emission rate for the unit, in accordance with section 
2.5.2.3 of this appendix. The designated representative shall also 
provide notice under Sec. 75.61(a)(6) for each period when the 
emergency fuel is combusted.
* * * * *

2.2  Periodic NO<INF>X</INF> Emission Rate Testing

    Retest the NO<INF>X</INF> emission rate of the gas-fired peaking 
unit or the oil-fired peaking unit while combusting each type of fuel 
(or fuel mixture) for which a NO<INF>X</INF> emission rate versus heat 
input rate correlation curve was derived, at least once every 20 
calendar quarters. If a required retest is not completed by the end of 
the 20th calendar quarter following the quarter of the last test, use 
the missing data substitution procedures in section 2.5 of this 
appendix, beginning with the first unit operating hour after the end of 
the 20th calendar quarter. Continue using the missing data procedures 
until the required retest has been passed. Note that missing data 
substitution is fuel-specific (i.e., the use of substitute data is 
required only when combusting a fuel (or fuel mixture) for which the 
retesting deadline has not been met). Each time that a new fuel-
specific correlation curve is derived from retesting, the new curve 
shall be used to report NO<INF>X</INF> emission rate, beginning with 
the first operating hour in which the fuel is combusted, following the 
completion of the retest.

2.3  Other Quality Assurance/Quality Control-Related NO<INF>X</INF> 
Emission Rate Testing

* * * * *
    2.3.1  For a stationary gas turbine, select at least four operating 
parameters indicative of the turbine's NO<INF>X</INF> formation 
characteristics, and define in the QA plan for the unit the acceptable 
ranges for these parameters at each tested load-heat input point. The 
acceptable parametric ranges should be based upon the turbine 
manufacturer's recommendations. * * *
    2.3.2  For a diesel or dual-fuel reciprocating engine, select at 
least four operating parameters indicative of the engine's 
NO<INF>X</INF> formation characteristics, and define in the QA plan for 
the unit the acceptable ranges for these parameters at each tested 
load-heat input point. The acceptable parametric ranges should be based 
upon the engine manufacturer's recommendations. * * *
* * * * *

2.4  Procedures for Determining Hourly NO<INF>X</INF> Emission Rate

* * * * *
    2.4.2  * * * Linearly interpolate to 0.1 mmBtu/hr heat input rate 
and 0.001 lb/mmBtu NO<INF>X</INF>. * * *
* * * * *

2.5  Missing Data Procedures

    * * * For the purpose of providing substitute data, calculate the 
maximum potential NO<INF>X</INF> emission rate (as defined in Sec. 72.2 
of this chapter) for each type of fuel combusted in the unit.
* * * * *
    2.5.2  Substitute missing NO<INF>X</INF> emission rate data using 
the highest NO<INF>X</INF> 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 paragraphs 
2.5.2.1, 2.5.2.2, and 2.5.2.3 of this section.
    2.5.2.1  If the measured heat input rate during any unit operating 
hour is higher than the highest heat input rate from the baseline 
correlation tests, the NO<INF>X</INF> emission rate for the hour is 
considered to be missing. Provide substitute data for each such hour, 
as follows.
    2.5.2.1.1  Substitute the higher of: the NO<INF>X</INF> emission 
rate obtained by linear extrapolation of the correlation curve, or the 
maximum potential NO<INF>X</INF> emission rate (MER) (as defined in 
Sec. 72.2 of this chapter), specific to the type of fuel being 
combusted. (For fuel mixtures, substitute the highest NO<INF>X</INF> 
MER value for any fuel in the mixture.) For units with NO<INF>X</INF> 
emission controls, the option to report the extrapolated NO<INF>X</INF> 
emission rate may only be used if the controls are documented (e.g., by 
parametric data) to be operating properly during the missing data 
period (see section 2.5.2.2 of this appendix); or 2.5.2.1.2 Substitute 
1.25 times the highest NO<INF>X</INF> emission rate from the baseline 
correlation tests for the fuel (or fuel mixture) being combusted in the 
unit, not to exceed the MER for that fuel (or mixture). For units with 
NO<INF>X</INF> emission controls, the option to report 1.25 times the 
highest emission rate from the correlation curve may only be used if 
the controls are documented (e.g., by parametric data) to be operating 
properly during the missing data period (see section 2.5.2.2 of this 
appendix).
    2.5.2.2  For a unit with add-on NO<INF>X</INF> emission controls 
(e.g., steam or water injection, selective catalytic reduction), if, 
for any unit operating hour, the emission controls are either not in 
operation or if appropriate parametric data are unavailable to ensure 
proper operation of the controls, the NO<INF>X</INF> emission rate for 
the hour is considered to be missing. Substitute the fuel-specific MER 
(as defined in Sec. 72.2 of this chapter) for each such hour.
    2.5.2.3  When emergency fuel (as defined in Sec. 72.2) is combusted 
in the unit, report the fuel-specific NO<INF>X</INF> MER for each hour 
that the fuel is combusted.
* * * * *
    61. Section 2 of Appendix F to Part 75 is amended by revising 
Equation F-3 in section 2.3 to read as follows:

Appendix F to Part 75--Conversion Procedures

* * * * *

2. Procedures for SO <INF>2</INF> Emissions

* * * * *
2.3  * * *
[GRAPHIC] [TIFF OMITTED] TP13JN01.006


where: * * *
* * * * *


Appendix F Section 3  [Amended]

    62. Section 3 of Appendix F to Part 75 is amended by removing the 
third sentence from section 3.3.5.
    63. Section 5 of Appendix F to Part 75 is amended by:

[[Page 32045]]

    a. In the definition of the variable ``Q<INF>g</INF>'' of Equation 
F-20 in section 5.5.2 by revising the words ``hundred cubic feet'' to 
read ``hundred standard cubic feet per hour'';
    b. In the first sentence of sections 5.6.1, 5.6.2, and 5.7 by 
revising the word ``should'' to read ``shall.''
    c. In the definitions for the variables ``t<INF>i</INF>,'' and 
``t<INF>cs</INF>,'' and ``n'' of Equations F-21a and F-21b in sections 
5.6.1 and 5.6.2 by revising the words ``Operating time at a particular 
unit'' in the definition of ``variable t<INF>i</INF>'' to read ``Unit 
operating time'', by revising the words ``Operating time at common 
stack'' in the definition of ``variable t<INF>cs</INF>'' with ``Common 
stack or common pipe operating time'', and by adding the words ``or 
pipe'' to the end of the definition of variable ``n''.
    d. Revising the definitions of variables ``HI<INF>s</INF>'', 
``t<INF>unit</INF>'', and ``t<INF>s</INF>'', and adding a new 
definition for ``s'' in the definition of variables of Equation F-21c 
in section 5.7; and
    e. Adding section 5.6.3.
    The revisions and additions read as follows:

5. Procedures for Heat Input

* * * * *

5.6  Heat Input Rate Apportionment for Units Sharing a Common Stack 
or Pipe

* * * * *
    5.6.3  As an alternative to using Equation F-21a or F-21b, the 
owner or operator may apportion the heat input rate at a common pipe 
to the individual units served by the common pipe based on the fuel 
flow rate to the individual units, as measured by uncertified fuel 
flowmeters. This option may only be used if a fuel flowmeter system 
that meets the requirements of appendix D to this part is installed 
on the common pipe. If this option is used, determine the unit heat 
input rates using the following equation:
[GRAPHIC] [TIFF OMITTED] TP13JN01.034

Where:

HI<INF>i</INF> = Heat input rate for a unit, mmBtu/hr.
HI<INF>CP</INF> = Heat input rate at the common pipe, mmBtu/hr.
FF<INF>i</INF> = Fuel flow rate to a unit, gal/min, 100 scfh, or 
other appropriate units
t<INF>i</INF> = Unit operating time, hour 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).
t<INF>CP</INF> = Common pipe operating time, hour 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).
n = Total number of units using the common pipe.
i = Designation of a particular unit.

5.7  Heat Input Rate Summation for Units with Multiple Stacks or 
Pipes

* * * * *
HI<INF>s</INF> = Heat input rate for the individual stack, duct, or 
pipe, mmBtu/hr.
t<INF>Unit</INF> = Unit operating time, hour or fraction of the hour 
(in equal increments that can range from one hundredth to one 
quarter of an hour, at the option of the owner or operator).
t<INF>s</INF> = Operating time for the individual stack or pipe, 
hour or fraction of the hour (in equal increments that can range 
from one hundredth to one quarter of an hour, at the option of the 
owner or operator).
s = Designation for a particular stack, duct, or pipe.


Appendix F to Part 75  [Amended]

    64. Section 7 of Appendix F to Part 75 is amended by revising the 
definitions of variables ``E<INF>h</INF>'' and ``HI'' of Equation F-23 
in section 7 to read as follows:

7. Procedures for SO<INF>2</INF> Mass Emissions at Units with 
SO<INF>2</INF> Continuous Emission Monitoring Systems During the 
Combustion of Pipeline Natural Gas or Natural Gas

* * * * *
E<INF>h</INF> = Hourly SO<INF>2</INF> mass emission rate, lb/hr.
HI = Hourly heat input rate, as determined using the procedures of 
section 5.2 of this appendix, mmBtu/hr.


Appendix F to Part 75  [Amended]

    65. Section 8 of Appendix F to Part 75 is amended by:
    a. In the first sentence of section 8.1.1 by adding the word 
``rate'' after each occurrence of the words ``heat input'';
    b. Revising the definition of the variable ``t<INF>cs</INF>'' of 
Equation F-25 in section 8.1.2; and
    c. Adding definitions of the variables ``p'' and ``u'' to Equation 
F-25 of section 8.1.2.
    The revisions and additions read as follows:

8. Procedures for NO<INF>X</INF> Mass Emissions

* * * * *

8.1  * * *

8.1.2  * * *

t<INF>CS</INF> = Common stack 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). (For each hour, t<INF>cs</INF> is the total time during 
which one or more of the units which exhaust through the common 
stack operate.)
* * * * *
p = Number of units that exhaust through the common stack.
u = Designation of a particular unit.
* * * * *
    66. Section 2 of Appendix G to Part 75 is amended by:
    a. Amending section 2.1 to designate the first two sentences 
following the variables in Equation G-1 as section 2.1.1, the third 
sentence as section 2.1.2, and the remaining text as section 2.1.3;
    b. Revising the first sentence of section 2.3; and
    c. Revising the definition of variable ``F<INF>c</INF>'' of 
Equation G-4 in section 2.3.
    The revisions read as follows:

Appendix G to Part 75--Determination of CO<INF>2</INF> Emissions

* * * * *

2. Procedures for Estimating CO<INF>2</INF> Emissions from 
Combustion

* * * * *
    2.3 In lieu of using the procedures, methods, and equations in 
section 2.1 of this appendix, the owner or operator of an affected 
gas-fired (or oil-fired) unit (as defined under Sec. 72.2 of this 
chapter) may use the following equation and records of hourly heat 
input to estimate hourly CO<INF>2</INF> mass emissions (in tons). * 
* *

(Eq. G-4) * * *

F<INF>C</INF> = Carbon based F-factor, 1040 scf/mmBtu for natural 
gas; 1,420 scf/mmBtu for crude, residual, or distillate oil; and 
calculated according to the procedures in section 3.3.5 of appendix 
F to this part for other gaseous fuels.
* * * * *


Appendix G to Part 75  [Amended]

    67. Section 5 of Appendix G to Part 75 is amended by:

[[Page 32046]]

    a. Removing and reserving sections 5.1 and 5.1.1;
    b. Revising the section heading and introductory text of section 
5.2; and
    c. Revising Table G-1 in section 5.2.2.
    The revisions read as follows:

5. Missing Data Substitution Procedures for Fuel Analytical Data

* * * * *

5.2 Missing Carbon Content Data

    Use the procedures of this section to substitute for missing 
carbon content data.
* * * * *

   Table G-1.--Missing Data Substitution Procedures for Missing Carbon
                              Content Data
------------------------------------------------------------------------
          Parameter                        Missing data value
------------------------------------------------------------------------
Oil and coal carbon content..  Most recent, previous carbon content
                                value available for that type of coal,
                                grade of oil, or default value, in this
                                table.
Gas carbon content...........  Most recent, previous carbon content
                                value available for that type of gaseous
                                fuel, or default value, in this table.
Default coal carbon content..  Anthracite: 90.0 percent.
                               Bituminous: 85.0 percent.
                               Sub-bituminous/Lignite: 75.0 percent.
Default oil carbon content...  90.0 percent.
Default gas carbon content...  Natural gas: 75.0 percent.
                               Other gaseous fuels: 90.0 percent.
------------------------------------------------------------------------

* * * * *

PART 78--APPEAL PROCEDURES FOR ACID RAIN PROGRAM

    68. The authority citation for part 78 continues to read as 
follows:

    Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et 
seq.

    69. Section 78.1 is amended by removing from paragraph (a)(1) the 
words ``parts 72, 73, 74, 75, 76, and 77 of this chapter'' and adding 
in their place ``parts 72, 73, 74, 75, 76, or 77 of this chapter or 
part 97 of this chapter''; and adding a new paragraph (b)(6) to read as 
follows:


Sec. 78.1  Purpose and scope.

    (b) * * *
    (6) Under part 97 of this chapter,
    (i) The adjustment of the information in a compliance certification 
or other submission and the deduction or transfer of NO<INF>X</INF> 
allowances based on the information, as adjusted, under Sec. 97.31;
    (ii) The decision on the allocation of NO<INF>X</INF> allowances to 
a NO<INF>X</INF> Budget unit under Sec. 97.41(b), (c), (d), or (e);
    (iii) The decision on the allocation of NO<INF>X</INF> allowances 
to a NO<INF>X</INF> Budget unit from the compliance supplement pool 
under Sec. 97.43;
    (iv) The decision on the deduction of NO<INF>X</INF> allowances 
under Sec. 97.54;
    (v) The decision on the transfer of NO<INF>X</INF> allowances under 
Sec. 97.61;
    (vi) The decision on a petition for approval of an alternative 
monitoring system;
    (vii) The approval or disapproval of a monitoring system 
certification or recertification under Sec. 97.71;
    (viii) The finalization of control period emissions data, including 
retroactive adjustment based on audit;
    (ix) The approval or disapproval of a petition under Sec. 97.75;
    (x) The determination of the sufficiency of the monitoring plan for 
a NO<INF>X</INF> Budget opt-in unit;
    (xi) The decision on a request for withdrawal of a NO<INF>X</INF> 
Budget opt-in unit from the NO<INF>X</INF> Budget Trading Program under 
Sec. 97.86;
    (xii) The decision on the deduction of NO<INF>X</INF> allowances 
under Sec. 97.87; and (xiii) The decision on the allocation of 
NO<INF>X</INF> allowances to a NO<INF>X</INF> Budget opt-in unit under 
Sec. 97.88.
* * * * *


Sec. 78.2  [Amended].

    70. Section 78.2 is amended by removing the words ``shall apply to 
this part'' and adding to their place ``shall apply to appeals of any 
final decision of the Administrator under parts 72, 73, 74, 75, 76, 77, 
or 78 of this chapter''.
    71. Section 78.3 is amended by:
    a. Amending paragraph (b)(3)(i) by adding, after the word 
``petitioner)'', the words ``or the NO<INF>X</INF> authorized account 
representative under paragraph (a)(3) of this section (unless the 
NO<INF>X</INF> authorized account representative is the petitioner)'';
    b. In paragraph (c)(7) by adding, after the words ``title IV of the 
Act'', the words ``or part 97 of this chapter, as appropriate'';
    c. In paragraph (d)(2) by adding, after the words ``Acid Rain 
Program'' the words ``or on an account certificate of representation 
submitted by a NO<INF>X</INF> authorized account representative or an 
application for a general account submitted by a NO<INF>X</INF> 
authorized account representative under the NO<INF>X</INF> Budget 
Trading Program'';
    d. Redesignating paragraphs (d)(2) and (d)(3) as paragraphs (d)(3) 
and (d)(4) respectively; and
    e. Adding new paragraphs (a)(3) and (d)(2).
    The additions and revisions read as follows:


Sec. 78.3  Petition for administrative review and request for 
evidentiary hearing.

    (a) * * *
    (3) The following persons may petition for administrative review of 
a decision of the Administrator that is made under part 97 of this 
chapter and that is appealable under Sec. 78.1(a) of this part:
    (i) The NO<INF>X</INF> authorized account representative for the 
unit or any NO<INF>X</INF> Allowance Tracking System account covered by 
the decision; or
    (ii) Any interested person.
* * * * *
    (d) * * *
    (2) Any provision or requirement of part 97 of this chapter, 
including the standard requirements under Sec. 97.6 of this chapter and 
any emission monitoring or reporting requirements under part 97 of this 
chapter.
* * * * *
    72. Section 78.4 is amended by adding two new sentences after the 
third sentence in paragraph (a) to read as follows:


Sec. 78.4  Filings.

    (a) * * * Any filings on behalf of owners and operators of a 
NO<INF>X</INF> Budget unit or source shall be signed by the 
NO<INF>X</INF> authorized account representative. Any filings on behalf 
of persons with an interest in NO<INF>X</INF> allowances in a general 
account shall be signed by the NO<INF>X</INF> authorized account 
representative. * * *
* * * * *


Sec. 78.12  [Amended]

    73. Section 78.12 is amended by adding, after the words ``was 
properly issued or should be issued'' in paragraph (a)(2), the words 
``or that a

[[Page 32047]]

 NO<INF>X</INF> Budget permit or other federally enforceable permit was 
properly issued or should be issued''.

PART 97--FEDERAL NO<INF>X</INF> BUDGET TRADING PROGRAM

    74. The authority citation for part 97 continues to read as 
follows:

    Authority: 42 U.S.C. 7401, 7403, 7426, and 7601.

    75. Section 97.2 is amended by:
    a. Revising the definition of ``continuous emission monitoring 
system or CEMS'';
    b. In the definition of ``Most stringent State or Federal 
NO<INF>X</INF> emissions limitation'' by removing the words ``, with 
regard to a NO<INF>X</INF> Budget opt-in unit,'';
    c. In the third sentence of the definition of ``NO<INF>X</INF> 
allowance'' by adding the reference ``Sec. 97.40,'' after the word 
``except'';
    d. In the definition of ``NO<INF>X</INF> Budget unit'' by removing 
the words ``Trading Program'';
    e. In the definition of ``owner'' by adding the word ``the'' before 
the final occurrence of the word ``NO<INF>X</INF>'' in paragraph (4) of 
the definition; and
    f. In the definition of ``Percent monitor data availability'' by 
revising the words ``3,672 hours per'' to read ``the total number of 
unit operating hours in the'', and by revising the symbol ``%'' to read 
``percent''.
    The revisions and additions read as follows:


Sec. 97.2  Definitions.

* * * * *
    Continuous emission monitoring system or CEMS means the equipment 
required under subpart H of this part to sample, analyze, measure, and 
provide, by means of readings taken at least once every 15 minutes 
(using an automated data acquisition and handling system (DAHS), a 
permanent record of nitrogen oxides (NO<INF>X</INF>) emissions, stack 
gas volumetric flow rate or stack gas moisture content (as applicable), 
in a manner consistent with part 75 of this chapter. The following are 
the principal types of continuous emission monitoring systems required 
under subpart H of this part:
    (1) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated DAHS. A flow monitoring system provides a 
permanent, continuous record of stack gas volumetric flow rate, in 
units of standard cubic feet per hour (scfh);
    (2) A nitrogen oxides concentration monitoring system, consisting 
of a NO<INF>X</INF> pollutant concentration monitor and an automated 
DAHS. A NO<INF>X</INF> concentration monitoring system provides a 
permanent, continuous record of NO<INF>X</INF> emissions in units of 
parts per million (ppm);
    (3) A nitrogen oxides emission rate (or NO<INF>X</INF>-diluent) 
monitoring system, consisting of a NO<INF>X</INF> pollutant 
concentration monitor, a diluent gas (CO<INF>2</INF> or O<INF>2</INF>) 
monitor, and an automated DAHS. A NO<INF>X</INF> concentration 
monitoring system provides a permanent, continuous record of: 
NO<INF>X</INF> concentration in units of parts per million (ppm), 
diluent gas concentration in units of percent O<INF>2</INF> or 
CO<INF>2</INF> (% O<INF>2</INF> or CO<INF>2</INF>), and NO<INF>X</INF> 
emission rate in units of pounds per million British thermal units (lb/
mmBtu); and
    (4) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter. A moisture monitoring system provides a permanent, 
continuous record of the stack gas moisture content, in units of 
percent H<INF>2</INF>O (% H<INF>2</INF>O).
* * * * *


Sec. 97.4  [Amended]

    76. Section 97.4(b) is amended by:
    a. Amending the first sentence of paragraph (b)(1) by adding, after 
the words ``federally enforceable permit that'', the words ``restricts 
the unit to combusting only natural gas or fuel oil (as defined in 
Sec. 75.2 of this chapter) during a control period and'';
    b. In paragraph (b)(4)(i) by adding, after the words ``with the 
restriction on'', the words ``fuel use and''; and
    c. In paragraph (b)(4)(vi)(B) by adding, after the words ``the 
restriction on'', the words ``fuel use or''.
    77. Section 97.5 is amended by:
    a. In the third sentence of paragraph (b)(2) by adding, after the 
word ``submit'', the words ``such a statement or'';
    b. In paragraph (c)(6)(ii) by removing the period and replacing it 
with ``; or''; and
    c. Adding a new paragraph (c)(6)(iii).
    The revisions and additions read as follows:


Sec. 97.5  Retired unit exemption.

* * * * *
    (c) * * *
    (6) * * *
    (iii) The date on which the unit resumes operation, if the unit is 
not required to submit a NO<INF>X</INF> permit application.
* * * * *


Sec. 97.40  [Amended]

    78. Section 97.40 is amended by removing the word ``program''.


Sec. 97.43  [Amended]

    79. Section 97.43 is amended by removing paragraph (c)(8).


Sec. 97.51  [Amended]

    80. Section 97.51 is amended by amending paragraph (b)(1)(i)(D) by 
adding, after the words ``with respect to'', the word `` 
NO<INF>X</INF>''.
    81. Section 97.54 is amended in paragraph (f) introductory text by 
revising the colon after the words ``as follows'' with a period and by 
adding a new sentence to the end of the paragraph to read as follows:


Sec. 97.54  Compliance.

* * * * *
    (f) * * * For each State NO<INF>X</INF> Budget Trading Program that 
is established, and approved and administered by the Administrator 
pursuant to Sec. 51.121 of this chapter, the terms ``compliance 
account'' or ``compliance accounts'', ``overdraft account'' or 
``overdraft accounts'', ``general account'' or ``general accounts'', 
``States'', and ``trading program budgets under Sec. 97.40'' in 
paragraphs (f)(1) through (f)(3) of this section shall be read to 
include respectively: a compliance account or compliance accounts 
established under such State NO<INF>X</INF> Budget Trading Program; an 
overdraft account or overdraft accounts established under such State 
NO<INF>X</INF> Budget Trading Program; a general account or general 
accounts established under such State NO<INF>X</INF> Budget Trading 
Program; the State or portion of a State covered by such State 
NO<INF>X</INF> Budget Trading Program; and the trading program budget 
of the State or portion of a State covered by such State NO<INF>X</INF> 
Budget Trading Program.
* * * * *


Sec. 97.61  [Amended]

    82. Section 97.61 is amended in paragraph (b) by revising the words 
``same year as'' to read ``third year after the year of''.
    83. Section 97.70 is amended by:
    a. In paragraph (a)(1) by revising the words ``Secs. 75.72 and 
Secs. 75.76'' to read ``Secs. 75.71 and 75.72'';
    b. Revising paragraph (b)(3);
    c. Revising paragraph (b)(4);
    d. Removing paragraphs (b)(5) and (b)(6);
    e. Redesignating paragraphs (b)(7), (b)(8) and (b)(9) as paragraphs 
(b)(5), (b)(6), and (b)(7), respectively;
    f. Revising newly redesignated paragraphs (b)(5) and (b)(6); and
    g. Revising paragraph (c).
    The revisions and additions read as follows:


Sec. 97.70  General requirements.

* * * * *
    (b) * * *
    (3) For the owner or operator of a NO<INF>X</INF> Budget unit under 
Sec. 97.4(a) that

[[Page 32048]]

commences operation on or after January 1, 2002 and that reports on an 
annual basis under Sec. 97.74(d) by the following dates:
    (i) The earlier of 90 unit operating days after the date on which 
the unit commences commercial operation or 180 calendar days after the 
date on which the unit commences commercial operation; or (ii) May 1, 
2002, if the compliance date under paragraph (b)(3)(i) of this section 
is before May 1, 2002.
    (4) For the owner or operator of a NO<INF>X</INF> Budget unit under 
Sec. 97.4(a) that commences operation on or after January 1, 2002 and 
that reports on a control period basis under Sec. 97.74(d)(2)(ii), by 
the following dates:
    (i) The earlier of 90 unit operating days or 180 calendar days 
after the date on which the unit commences commercial operation, 
provided that this compliance date is during a control period; or (ii) 
May 1 immediately following the compliance date under paragraph 
(b)(4)(i) of this section, if such compliance date is not during a 
control period.
    (5) For the owner or operator of a NO<INF>X</INF> Budget unit that 
has a new stack or flue for which construction is completed after the 
applicable deadline under paragraph (b)(1), (b)(2), (b)(3), or (b)(4) 
of this section or under subpart I of this part and that reports on an 
annual basis under Sec. 97.74(d), by the earlier of 90 unit operating 
days or 180 calendar days after the date on which emissions first exit 
to the atmosphere through the new stack or flue.
    (6) For the owner or operator of a NO<INF>X</INF> Budget unit that 
has a new stack or flue for which construction is completed after the 
applicable deadline under paragraph (b)(1), (b)(2), (b)(3), or (b)(4) 
of this section or under subpart I of this part and that reports on a 
control period basis under Sec. 97.74(d)(2)(ii), by the following 
dates:
    (i) The earlier of 90 unit operating days or 180 calendar days 
after the date on which emissions first exit to the atmosphere through 
the new stack or flue, provided that this compliance date is during a 
control period; or
    (ii) May 1 immediately following the compliance date under 
paragraph (b)(6)(i) of this section, if such compliance date is not 
during a control period.
* * * * *
    (c) Commencement of data reporting. (1) The owner or operator of 
NO<INF>X</INF> Budget units under paragraph (b)(1) or (b)(2) of this 
section shall determine, record and report NO<INF>X</INF> mass 
emissions, heat input rate, and any other values required to determine 
NO<INF>X</INF> mass emissions (e.g., NO<INF>X</INF> emission rate and 
heat input rate, or NO<INF>X</INF> concentration and stack flow rate) 
in accordance with Sec. 75.70(g) of this chapter, beginning on the 
first hour of the applicable compliance deadline in paragraph (b)(1) or 
(b)(2) of this section.
    (2) The owner or operator of a NO<INF>X</INF> Budget unit under 
paragraph (b)(3) or (b)(4) of this section shall determine, record and 
report NO<INF>X</INF> mass emissions, heat input rate, and any other 
values required to determine NO<INF>X</INF> mass emissions (e.g., 
NO<INF>X</INF> emission rate and heat input rate, or NO<INF>X</INF> 
concentration and stack flow rate) and electric and thermal output in 
accordance with Sec. 75.70(g) of this chapter, beginning on:
    (i) The date and hour on which the unit commences operation, if the 
date and hour on which the unit commences operation is during a control 
period; or
    (ii) The first hour on May 1 of the first control period after the 
date and hour on which the unit commences operation, if the date and 
hour on which the unit commences operation is not during a control 
period.
    (3) Notwithstanding paragraphs (c)(2)(i) and (c)(2)(ii) of this 
section, the owner or operator may begin reporting NO<INF>X</INF> mass 
emission data and heat input data before the date and hour under 
paragraph (c)(2)(i) or (c)(2)(ii) of this section if the unit reports 
on an annual basis and if the required monitoring systems are certified 
before the applicable date and hour under paragraph (c)(1) or (c)(2) of 
this section.
* * * * *
    84. Section 97.71 is amended by:
    a. Revising paragraph (a) introductory text;
    b. In paragraphs (b)(1), (b)(2), and (b)(3)(ii) by adding the word 
``emission'' before the words ``monitoring system'' in each occurrence 
in paragraph (b)(1), in both occurrences in the first sentence of 
paragraph (b)(2), and in the one occurrence in paragraph (b)(3)(ii); 
and by revising the word ``a'' to read ``an'' after the word 
``installs'' in the second sentence of paragraph (b)(1);
    c. In paragraphs (b)(3)(iii) and (b)(3)(iv)(C) by removing each 
occurrence of the words ``or component thereof''; and
    d. Revising the second sentence of paragraph (c), adding two new 
sentences to the end of paragraph (c), and removing paragraphs (c)(i) 
through (iii).
    The revisions and additions read as follows:


Sec. 97.71  Initial certification and recertification procedures.

    (a) The owner or operator of a NO<INF>X</INF> Budget unit that is 
subject to an Acid Rain emissions limitation shall comply with the 
initial certification and recertification procedures of part 75 of this 
chapter for NO<INF>X</INF>-diluent CEMS, flow monitors, NO<INF>X</INF> 
concentration CEMS, or excepted monitoring systems under appendix E of 
part 75 of this chapter for NO<INF>X</INF>, under appendix D for heat 
input, or under Sec. 75.19 for NO<INF>X</INF> and heat input, except 
that:
* * * * *
    (c) * * * The owner or operator of such a unit shall also meet the 
applicable certification and recertification procedures of paragraph 
(b) of this section, except that the excepted methodology shall be 
deemed provisionally certified for use under the NO<INF>X</INF> Budget 
Trading Program as of the date on which the certification application 
is received by the Administrator. The methodology shall be considered 
to be certified either upon receipt of a written notice of approval 
from the Administrator or, if such notice is not provided, at the end 
of the Administrator's 120 day review period. However, a provisionally 
certified or certified low mass emissions excepted methodology shall 
not be used to report data under the NO<INF>X</INF> Budget Trading 
Program prior to the applicable commencement date specified in 
Sec. 75.19(a)(1)(ii) of this chapter.
* * * * *
    85. Section 97.72 is amended by:
    a. In paragraph (a) by adding the word ``emission'' before the 
words ``monitoring system'' and the words ``subpart H,'' before 
``appendix D''; and
    b. In paragraph (b) by adding the word ``emission'' before 
``monitoring system'' in the first sentence, by removing each 
occurrence of the words ``or component'' in the paragraph, and by 
adding a new final sentence.
    The revisions and additions read as follows:


Sec. 97.72  Out of control periods.

* * * * *
    (b) * * * The owner or operator shall follow the initial 
certification or recertification procedures in Sec. 97.71 for each 
disapproved system.
    86. Section 97.74 is amended by revising paragraphs (a)(1), (d)(1), 
and (d)(2)(ii); to read as follows:


Sec. 97.74  Recordkeeping and reporting.

    (a) * * *
    (1) The NO<INF>X</INF> authorized account representative shall 
comply with all recordkeeping and reporting requirements in this 
section, with the

[[Page 32049]]

recordkeeping and reporting requirements under Sec. 75.73 of this 
chapter, and with the requirements of Sec. 97.10(e)(1).
* * * * *
    (d) * * *
    (1) If a unit is subject to an Acid Rain emission limitation or if 
the owner or operator of the NO<INF>X</INF> budget unit chooses to meet 
the annual reporting requirements of this subpart H, the NO<INF>X</INF> 
authorized account representative shall submit a quarterly report, 
documenting the NO<INF>X</INF> mass emissions from the unit, for each 
calendar quarter beginning with:
    (i) For a unit for which the owner or operator intends to apply or 
applies for the early reduction credits under Sec. 97.43, the calendar 
quarter that covers May 1, 2000 through June 30, 2000. NO<INF>X</INF> 
mass emission data shall be recorded and reported from the first hour 
on May 1, 2000; or
    (ii) For a unit that commences operation before January 1, 2002 and 
that is not subject to paragraph (d)(1)(i) of this section, the 
calendar quarter covering May 1, 2002 through June 30, 2002. 
NO<INF>X</INF> mass emission data shall be recorded and reported from 
the first hour on May 1, 2002; or
    (iii) For a unit that commences operation on or after January 1, 
2002:
    (A) The calendar quarter in which the unit commences operation, if 
unit operation commences during a control period. NO<INF>X</INF> mass 
emission data shall be recorded and reported from the date and hour 
when the unit commences operation; or
    (B) The calendar quarter which includes May 1 through June 30 of 
the first control period following the date on which the unit commences 
operation, if the unit does not commence operation during a control 
period. NO<INF>X</INF> mass emission data shall be recorded and 
reported from the first hour on May 1 of that control period; or
    (iv) A calendar quarter before the quarter specified in paragraph 
(d)(1)(i), (d)(1)(ii), or (d)(1)(iii)(B) of this section, if the owner 
or operator elects to begin reporting early under Sec. 97.70(c)(3).
    (2) * * *
    (ii) Submit quarterly reports, documenting NO<INF>X</INF> mass 
emissions from the unit, only for the period from May 1 through 
September 30 of each year and including the data described in 
Sec. 75.74(c)(6) of this chapter. The NO<INF>X</INF> authorized account 
representative shall submit such quarterly reports, beginning with:
    (A) For a unit for which the owner or operator intends to apply or 
applies for early reduction credits under Sec. 97.43, the calendar 
quarter covering May 1, 2000 through June 30, 2000. NO<INF>X</INF> mass 
emission data shall be recorded and reported from first hour on May 1, 
2000;
    (B) For a unit that commences operation before January 1, 2002 and 
that is not subject to paragraph (d)(2)(ii)(A)of this section, the 
calendar quarter covering May 1 through June 30, 2002. NO<INF>X</INF> 
mass emission data shall be recorded and reported from the first hour 
of May 1, 2002;
    (C) For a unit that commences operation on or after January 1, 2002 
and during a control period, the calendar quarter in which the unit 
commences operation. NO<INF>X</INF> mass emission data shall be 
reported from the date and hour corresponding to when the unit 
commences operation; or (D) For a unit that commences operation on or 
after January 1, 2002 and not during a control period, the calendar 
quarter which includes May 1 through June 30 of the first control 
period after the unit commences operation. NO<INF>X</INF> mass emission 
data shall be recorded and reported from the first hour on May 1 of the 
first control period after the unit commences operation.
* * * * *


Sec. 97.87  [Amended]

    87. Section 97.87 is amended in second sentence of paragraph 
(b)(1)(iii)(A) by adding the word ``be'' after the words ``shall not''.
    88. Subpart J consisting of Sec. 97.90 is added to read as follows:

Subpart J--Appeal Procedures


Sec. 97.90  Appeal Procedures.

    The appeal procedures for the NO<INF>X</INF> Budget Trading Program 
are set forth in part 78 of this chapter.

[FR Doc. 01-13142 Filed 6-12-01; 8:45 am]
BILLING CODE 6560-50-P